[Code of Federal Regulations]
[Title 49, Volume 3, Parts 186 to 199]
[Revised as of October 1, 1999]
From the U.S. Government Printing Office via GPO Access
[CITE: 49CFR195]
[Page 141-182]
TITLE 49--TRANSPORTATION
CHAPTER I--RESEARCH AND SPECIAL PROGRAMS ADMINISTRATION, DEPARTMENT OF
TRANSPORTATION--Continued
PART 195--TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE
Subpart A--General
Sec.
195.0 Scope.
195.1 Applicability.
195.2 Definitions.
195.3 Matter incorporated by reference.
195.4 Compatibility necessary for transportation of hazardous liquids
or carbon dioxide.
195.5 Conversion to service subject to this part.
[[Page 142]]
195.8 Transportation of hazardous liquid or carbon dioxide in pipelines
constructed with other than steel pipe.
195.9 Outer continental shelf pipelines.
195.10 Responsibility of operator for compliance with this part.
Subpart B--Reporting Accidents and Safety-Related Conditions
195.50 Reporting accidents.
195.52 Telephonic notice of certain accidents.
195.54 Accident reports.
195.55 Reporting safety-related conditions.
195.56 Filing safety-related condition reports.
195.57 Filing offshore pipeline condition reports.
195.58 Address for written reports.
195.60 Operator assistance in investigation.
195.62 Supplies of accident report DOT Form 7000-1.
195.63 OMB control number assigned to information collection.
Subpart C--Design Requirements
195.100 Scope.
195.101 Qualifying metallic components other than pipe.
195.102 Design temperature.
195.104 Variations in pressure.
195.106 Internal design pressure.
195.108 External pressure.
195.110 External loads.
195.111 Fracture propagation.
195.112 New pipe.
195.114 Used pipe.
195.116 Valves.
195.118 Fittings.
195.120 Passage of internal inspection devices.
195.122 Fabricated branch connections.
195.124 Closures.
195.126 Flange connection.
195.128 Station piping.
195.130 Fabricated assemblies.
195.132 Design and construction of aboveground breakout tanks.
195.134 CPM leak detection.
Subpart D--Construction
195.200 Scope.
195.202 Compliance with specifications or standards.
195.204 Inspection--general.
195.205 Repair, alteration and reconstruction of aboveground breakout
tanks that have been in service.
195.206 Material inspection.
195.208 Welding of supports and braces.
195.210 Pipeline location.
195.212 Bending of pipe.
195.214 Welding: General.
195.216 Welding: Miter joints.
195.222 Welders: Qualification of welders.
195.224 Welding: Weather.
195.226 Welding: Arc burns.
195.228 Welds and welding inspection: Standards of acceptability.
195.230 Welds: Repair or removal of defects.
195.234 Welds: Nondestructive testing.
195.236 External corrosion protection.
195.238 External coating.
195.242 Cathodic protection system.
195.244 Test leads.
195.246 Installation of pipe in a ditch.
195.248 Cover over buried pipeline.
195.250 Clearance between pipe and underground structures.
195.252 Backfilling.
195.254 Above ground components.
195.256 Crossing of railroads and highways.
195.258 Valves: General.
195.260 Valves: Location.
195.262 Pumping equipment.
195.264 Impoundment, protection against entry, normal/emergency venting
or pressure/vacuum relief for aboveground breakout tanks.
195.266 Construction records.
Subpart E--Pressure Testing
195.300 Scope.
195.302 General requirements.
195.303 Risk-based alternative to pressure testing older hazardous
liquid and carbon dioxide pipelines.
195.304 Test pressure.
195.305 Testing of components.
195.306 Test medium.
195.307 Pressure testing aboveground breakout tanks.
195.308 Testing of tie-ins.
195.310 Records.
Subpart F--Operation and Maintenance
195.400 Scope.
195.401 General requirements.
195.402 Procedural manual for operations, maintenance, and emergencies.
195.403 Training.
195.404 Maps and records.
195.405 Protection against ignitions and safe access/egress involving
floating roofs.
195.406 Maximum operating pressure.
195.408 Communications.
195.410 Line markers.
195.412 Inspection of rights-of-way and crossings under navigable
waters.
195.413 Underwater inspection and reburial of pipelines in the Gulf of
Mexico and its inlets.
195.414 Cathodic protection.
195.416 External corrosion control.
195.418 Internal corrosion control.
195.420 Valve maintenance.
195.422 Pipeline repairs.
195.424 Pipe movement.
195.426 Scraper and sphere facilities.
[[Page 143]]
195.428 Overpressure safety devices and overfill protection systems.
195.430 Firefighting equipment.
195.432 Inspection of in-service breakout tanks.
195.434 Signs.
195.436 Security of facilities.
195.438 Smoking or open flames.
195.440 Public education.
195.442 Damage prevention program.
195.444 CPM leak detection.
Subpart G
195.501 Scope.
195.503 Definitions.
195.505 Qualification program.
195.507 Recordkeeping.
195.509 General.
Appendix A to Part 195--Delineation Between Federal and State
Jurisdiction--Statement of Agency Policy and Interpretation
Appendix B to Part 195--Risk-Based Alternative to Pressure Testing Older
Hazardous Liquid and Carbon Dioxide Pipelines
Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60118; and 49
CFR 1.53.
Source: Amdt. 195-22, 46 FR 38360, July 27, 1981, unless otherwise
noted.
Subpart A--General
Sec. 195.0 Scope.
This part prescribes safety standards and reporting requirements for
pipeline facilities used in the transportation of hazardous liquids or
carbon dioxide.
[Amdt. 195-45, 56 FR 26925, June 12, 1991]
Sec. 195.1 Applicability.
(a) Except as provided in paragraph (b) of this section, this part
applies to pipeline facilities and the transportation of hazardous
liquids or carbon dioxide associated with those facilities in or
affecting interstate or foreign commerce, including pipeline facilities
on the Outer Continental Shelf.
(b) This part does not apply to--
(1) Transportation of a hazardous liquid that is transported in a
gaseous state;
(2) Transportation of a hazardous liquid through a pipeline by
gravity;
(3) Transportation through any of the following low-stress
pipelines:
(i) An onshore pipeline or pipeline segment that--
(A) Does not transport HVL;
(B) Is located in a rural area; and
(C) Is located outside a waterway currently used for commercial
navigation;
(ii) A pipeline subject to safety regulations of the U.S. Coast
Guard; or
(iii) A pipeline that serves refining, manufacturing, or truck,
rail, or vessel terminal facilities, if the pipeline is less than 1 mile
long (measured outside facility grounds) and does not cross an offshore
area or a waterway currently used for commercial navigation;
(4) Transportation of petroleum in onshore gathering lines in rural
areas except gathering lines in the inlets of the Gulf of Mexico subject
to Sec. 195.413;
(5) Transportation of hazardous liquid or carbon dioxide in offshore
pipelines which are located upstream from the outlet flange of each
facility where hydrocarbons or carbon dioxide are produced or where
produced hydrocarbons or carbon dioxide are first separated, dehydrated,
or otherwise processed, whichever facility is farther downstream;
(6) Transportation of hazardous liquid or carbon dioxide in Outer
Continental Shelf pipelines which are located upstream of the point at
which operating responsibility transfers from a producing operator to a
transporting operator.
(7) Transportation of a hazardous liquid or carbon dioxide through
onshore production (including flow lines), refining, or manufacturing
facilities, or storage or in-plant piping systems associated with such
facilities;
(8) Transportation of hazardous liquid or carbon dioxide--
(i) By vessel, aircraft, tank truck, tank car, or other non-pipeline
mode of transportation; or
(ii) Through facilities located on the grounds of a materials
transportation terminal that are used exclusively to transfer hazardous
liquid or carbon dioxide between non-pipeline modes of transportation or
between a non-pipeline mode and a pipeline, not including any device and
associated piping that are necessary to control pressure in the pipeline
under Sec. 195.406(b); and
(9) Transportation of carbon dioxide downstream from the following
point, as applicable:
[[Page 144]]
(i) The inlet of a compressor used in the injection of carbon
dioxide for oil recovery operations, or the point where recycled carbon
dioxide enters the injection system, whichever is farther upstream; or
(ii) The connection of the first branch pipeline in the production
field that transports carbon dioxide to injection wells or to headers or
manifolds from which pipelines branch to injection wells.
(c) Breakout tanks subject to this part must comply with
requirements that apply specifically to breakout tanks and, to the
extent applicable, with requirements that apply to pipeline systems and
pipeline facilities. If a conflict exists between a requirement that
applies specifically to breakout tanks and a requirement that applies to
pipeline systems or pipeline facilities, the requirement that applies
specifically to breakout tanks prevails. Anhydrous ammonia breakout
tanks need not comply with Secs. 195.132(b), 195.205(b), 195.242 (c) and
(d), 195.264 (b) and (e), 195.307, 195.428 (c) and (d), and 195.432 (b)
and (c).
[Amdt. 195-22, 46 FR 38360, July 27, 1981]
Editorial Note: For Federal Register citations affecting Sec. 195.1,
see the List of Sections Affected in the Finding Aids section of this
volume.
Sec. 195.2 Definitions.
As used in this part--
Administrator means the Administrator of the Research and Special
Programs Administration or any person to whom authority in the matter
concerned has been delegated by the Secretary of Transportation.
Barrel means a unit of measurement equal to 42 U.S. standard
gallons.
Breakout tank means a tank used to (a) relieve surges in a hazardous
liquid pipeline system or (b) receive and store hazardous liquid
transported by a pipeline for reinjection and continued transportation
by pipeline.
Carbon dioxide means a fluid consisting of more than 90 percent
carbon dioxide molecules compressed to a supercritical state.
Component means any part of a pipeline which may be subjected to
pump pressure including, but not limited to, pipe, valves, elbows, tees,
flanges, and closures.
Computation Pipeline Monitoring (CPM) means a software-based
monitoring tool that alerts the pipeline dispatcher of a possible
pipeline operating anomaly that may be indicative of a commodity
release.
Corrosive product means ``corrosive material'' as defined by
Sec. 173.136 Class 8-Definitions of this chapter.
Exposed pipeline means a pipeline where the top of the pipe is
protruding above the seabed in water less than 15 feet (4.6 meters)
deep, as measured from the mean low water.
Flammable product means ``flammable liquid'' as defined by
Sec. 173.120 Class 3-Definitions of this chapter.
Gathering line means a pipeline 219.1 mm (8\5/8\ in) or less nominal
outside diameter that transports petroleum from a production facility.
Gulf of Mexico and its inlets means the waters from the mean high
water mark of the coast of the Gulf of Mexico and its inlets open to the
sea (excluding rivers, tidal marshes, lakes, and canals) seaward to
include the territorial sea and Outer Continental Shelf to a depth of 15
feet (4.6 meters), as measured from the mean low water.
Hazard to navigation means, for the purpose of this part, a pipeline
where the top of the pipe is less than 12 inches (305 millimeters) below
the seabed in water less than 15 feet (4.6 meters) deep, as measured
from the mean low water.
Hazardous liquid means petroleum, petroleum products, or anhydrous
ammonia.
Highly volatile liquid or HVL means a hazardous liquid which will
form a vapor cloud when released to the atmosphere and which has a vapor
pressure exceeding 276 kPa (40 psia) at 37.8 deg. C (100 deg. F).
In-plant piping system means piping that is located on the grounds
of a plant and used to transfer hazardous liquid or carbon dioxide
between plant facilities or between plant facilities and a pipeline or
other mode of transportation, not including any device and associated
piping that are necessary to control pressure in the pipeline under
Sec. 195.406(b).
[[Page 145]]
Interstate pipeline means a pipeline or that part of a pipeline that
is used in the transportation of hazardous liquids or carbon dioxide in
interstate or foreign commerce.
Intrastate pipeline means a pipeline or that part of a pipeline to
which this part applies that is not an interstate pipeline.
Line section means a continuous run of pipe between adjacent
pressure pump stations, between a pressure pump station and terminal or
breakout tanks, between a pressure pump station and a block valve, or
between adjacent block valves.
Low-stress pipeline means a hazardous liquid pipeline that is
operated in its entirety at a stress level of 20 percent or less of the
specified minimum yield strength of the line pipe.
Nominal wall thickness means the wall thickness listed in the pipe
specifications.
Offshore means beyond the line of ordinary low water along that
portion of the coast of the United States that is in direct contact with
the open seas and beyond the line marking the seaward limit of inland
waters.
Operator means a person who owns or operates pipeline facilities.
Outer Continental Shelf means all submerged lands lying seaward and
outside the area of lands beneath navigable waters as defined in Section
2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the subsoil
and seabed appertain to the United States and are subject to its
jurisdiction and control.
Person means any individual, firm, joint venture, partnership,
corporation, association, State, municipality, cooperative association,
or joint stock association, and includes any trustee, receiver,
assignee, or personal representative thereof.
Petroleum means crude oil, condensate, natural gasoline, natural gas
liquids, and liquefied petroleum gas.
Petroleum product means flammable, toxic, or corrosive products
obtained from distilling and processing of crude oil, unfinished oils,
natural gas liquids, blend stocks and other miscellaneous hydrocarbon
compounds.
Pipe or line pipe means a tube, usually cylindrical, through which a
hazardous liquid or carbon dioxide flows from one point to another.
Pipeline or pipeline system means all parts of a pipeline facility
through which a hazardous liquid or carbon dioxide moves in
transportation, including, but not limited to, line pipe, valves, and
other appurtenances connected to line pipe, pumping units, fabricated
assemblies associated with pumping units, metering and delivery stations
and fabricated assemblies therein, and breakout tanks.
Pipeline facility means new and existing pipe, rights-of-way and any
equipment, facility, or building used in the transportation of hazardous
liquids or carbon dioxide.
Production facility means piping or equipment used in the
production, extraction, recovery, lifting, stabilization, separation or
treating of petroleum or carbon dioxide, or associated storage or
measurement. (To be a production facility under this definition, piping
or equipment must be used in the process of extracting petroleum or
carbon dioxide from the ground or from facilities where CO<INF>2</INF>
is produced, and preparing it for transportation by pipeline. This
includes piping between treatment plants which extract carbon dioxide,
and facilities utilized for the injection of carbon dioxide for recovery
operations.)
Rural area means outside the limits of any incorporated or
unincorpated city, town, village, or any other designated residential or
commercial area such as a subdivision, a business or shopping center, or
community development.
Specified minimum yield strength means the minimum yield strength,
expressed in p.s.i. (kPa) gage, prescribed by the specification under
which the material is purchased from the manufacturer.
Stress level means the level of tangential or hoop stress, usually
expressed as a percentage of specified minimum yield strength.
Surge pressure means pressure produced by a change in velocity of
the moving stream that results from shutting down a pump station or
pumping unit, closure of a valve, or any other blockage of the moving
stream.
[[Page 146]]
Toxic product means ``poisonous material'' as defined by
Sec. 173.132 Class 6, Division 6.1-Definitions of this chapter.
[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982,
as amended by Amdt. 195-33, 50 FR 15898, Apr. 23, 1985; 50 FR 38660,
Sept. 24, 1985; Amdt. 195-36, 51 FR 15007, Apr. 22, 1986; Amdt. 195-45,
56 FR 26925, June 12, 1991; Amdt. 195-47, 56 FR 63771, Dec. 5, 1991;
Amdt. 195-50, 59 FR 17281, Apr. 12, 1994; Amdt. 195-52, 59 FR 33395,
33396, June 28, 1994; Amdt. 195-53, 59 FR 35471, July 12, 1994; Amdt.
195-59, 62 FR 61695, Nov. 19, 1997; Amdt. 195-62, 63 FR 36376, July 6,
1998; Amdt. 195-63, 63 FR 37506, July 13, 1998]
Sec. 195.3 Matter incorporated by reference.
(a) Any document or portion thereof incorporated by reference in
this part is included in this part as though it were printed in full.
When only a portion of a document is referenced, then this part
incorporates only that referenced portion of the document and the
remainder is not incorporated. Applicable editions are listed in
paragraph (c) of this section in parentheses following the title of the
referenced material. Earlier editions listed in previous editions of
this section may be used for components manufactured, designed, or
installed in accordance with those earlier editions at the time they
were listed. The user must refer to the appropriate previous edition of
49 CFR for a listing of the earlier editions.
(b) All incorporated materials are available for inspection in the
Research and Special Programs Administration, 400 Seventh Street, SW.,
Washington, DC, and at the Office of the Federal Register, 800 North
Capitol Street, NW., suite 700, Washington, DC. These materials have
been approved for incorporation by reference by the Director of the
Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51.
In addition, materials incorporated by reference are available as
follows:
(1) American Gas Association (AGA), 1515 Wilson Boulevard,
Arlington, VA 22209.
(2) American Petroleum Institute (API), 1220 L Street, NW.,
Washington, DC 20005.
(3) The American Society of Mechanical Engineers (ASME), United
Engineering Center, 345 East 47th Street, New York, NY 10017.
(4) Manufacturers Standardization Society of the Valve and Fittings
Industry, Inc. (MSS), 127 Park Street, NE., Vienna, VA 22180.
(5) American National Standards Institute (ANSI), 11 West 42nd
Street, New York, NY 10036.
(6) American Society for Testing and Materials (ASTM), 100 Barr
Harbor Drive, West Conshohocken, PA 19428.
(7) National Fire Protection Association (NFPA), 11 Tracy Drive,
Avon, MA 02322.
(c) The full titles of publications incorporated by reference wholly
or partially in this part are as follows. Numbers in parentheses
indicate applicable editions:
(1) American Gas Association (AGA): AGA Pipeline Research Committee,
Project PR-3-805, ``A Modified Criterion for Evaluating the Remaining
Strength of Corroded Pipe'' (December 1989). The RSTRENG program may be
used for calculating remaining strength.
(2) American Petroleum Institute (API):
(i) API 510 ``Pressure Vessel Inspection Code: Maintenance
Inspection, Rating, Repair, and Alteration'' (8th edition, June 1997).
(ii) API Publication 2026 ``Safe Access/Egress Involving Floating
Roofs of Storage Tanks in Petroleum Service'' (2nd edition, April 1998).
(iii) API Recommended Practice 651 ``Cathodic Protection of
Aboveground Petroleum Storage Tanks'' (2nd edition, December 1997).
(iv) API Recommended Practice 652 ``Lining of Aboveground Petroleum
Storage Tank Bottoms'' (2nd edition, December 1997).
(v) API Recommended Practice 2003 ``Protection Against Ignitions
Arising out of Static, Lightning, and Stray Currents'' (6th edition,
December 1998).
(vi) API Recommended Practice 2350 ``Overfill Protection for Storage
Tanks In Petroleum Facilities'' (2nd edition, January 1996).
(vii) API Specification 5L ``Specification for Line Pipe'' (41st
edition, 1995).
(viii) API Specification 6D ``Specification for Pipeline Valves
(Gate,
[[Page 147]]
Plug, Ball, and Check Valves)'' (21st edition, 1994).
(ix) API Specification 12F ``Specification for Shop Welded Tanks for
Storage of Production Liquids'' (11th edition, November 1994).
(x) API Standard 1104 ``Welding Pipelines and Related Facilities''
(18th edition, 1994).
(xi) API Standard 620 ``Design and Construction of Large, Welded,
Low-Pressure Storage Tanks'' (9th edition, February 1996, Including
Addenda 1 and 2).
(xii) API Standard 650 ``Welded Steel Tanks for Oil Storage'' (9th
edition, July 1993 (Including Addenda 1 through 4).
(xiii) API Standard 653 ``Tank Inspection, Repair, Alteration, and
Reconstruction'' (2nd edition, December 1995, including Addenda 1,
December 1996).
(xiv) API Standard 2000 ``Venting Atmospheric and Low-Pressure
Storage Tanks'' (4th edition, September 1992).
(xv) API Standard 2510 ``Design and Construction of LPG
Installations'' (7th edition, May 1995).
(3) American Society of Mechanical Engineers (ASME):
(i) ASME/ANSI B16.9 ``Factory-Made Wrought Steel Buttwelding
Fittings'' (1993).
(ii) ASME/ANSI B31.4 ``Liquid Transportation Systems for
Hydrocarbons, Liquid Petroleum Gas, Anhydrous Ammonia, and Alcohols''
(1992 edition with ASME B31.4a-1994 Addenda).
(iii) ASME/ANSI B31.8 ``Gas Transmission and Distribution Piping
Systems'' (1995)
(iv) ASME/ANSI B31G ``Manual for Determining the Remaining Strength
of Corroded Pipelines'' (1991).
(v) ASME Boiler and Pressure Vessel Code, Section VIII ``Pressure
Vessels,'' Divisions 1 and 2 (1995 edition with 1995 Addenda).
(vi) ASME Boiler and Pressure Vessel Code, Section IX ``Welding and
Brazing Qualifications'' (1995 edition with 1995 Addenda).
(4) Manufacturers Standardization Society of the Valve and Fittings
Industry, Inc. (MSS):
(i) MSS SP-75 ``Specification for High Test Wrought Butt Welding
Fittings'' (1993).
(ii) [Reserved]
(5) American Society for Testing and Materials (ASTM):
(i) ASTM Designation A 53 ``Standard specification for Pipe, Steel,
Black and Hot-Dipped, Zinc-Coated Welded and Seamless'' (A 53-96).
(ii) ASTM Designation: A 106 ``Standard Specification for Seamless
Carbon Steel Pipe for High-Temperature Service'' (A 106-95).
(iii) ASTM Designation: A 333/A 333M ``Standard Specification for
Seamless and Welded Steel Pipe for Low-Temperature Service''(A 333/A
333M-94).
(iv) ASTM Designation: A 381 ``Standard Specification for Metal-Arc-
Welded Steel Pipe for Use With High-Pressure Transmission Systems'' (A
381-93).
(v) ASTM Designation: A 671 ``Standard Specification for Electric-
Fusion-Welded Steel Pipe for Atmospheric and Lower Temperatures'' (A
671-94).
(vi) ASTM Designation: A 672 ``Standard Specification for Electric-
Fusion-Welded Steel Pipe for High-Pressure Service at Moderate
Temperatures'' (A 672-94).
(vii) ASTM Designation: A 691 ``Standard Specification for Carbon
and Alloy Steel Pipe Electric-Fusion-Welded for High- Pressure Service
at High Temperatures'' (A 691-93).
(6) National Fire Protection Association (NFPA):
(i) ANSI/NFPA 30 ``Flammable and Combustible Liquids Code,'' (1996).
(ii) [Reserved]
[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982,
as amended by Amdt. 195-32, 49 FR 36860, Sept. 20, 1984; 58 FR 14523,
Mar. 18, 1993; Amdt. 195-52, 59 FR 33396, June 28, 1994; Amdt. 195-56,
61 FR 26123, May 24, 1996; 61 FR 36826, July 15, 1996; Amdt. 195-61, 63
FR 7723, Feb. 17, 1998; Amdt. 195-62, 63 FR 36376, July 6, 1998; Amdt.
195-66, 64 FR 15934, Apr. 2, 1999]
Sec. 195.4 Compatibility necessary for transportation of hazardous
liquids or carbon dioxide.
No person may transport any hazardous liquid or carbon dioxide
unless the hazardous liquid or carbon dioxide is chemically compatible
with both the pipeline, including all components, and any other
commodity that it may come into contact with while in the pipeline.
[Amdt. 195-45, 56 FR 26925, June 12, 1991]
[[Page 148]]
Sec. 195.5 Conversion to service subject to this part.
(a) A steel pipeline previously used in service not subject to this
part qualifies for use under this part if the operator prepares and
follows a written procedure to accomplish the following:
(1) The design, construction, operation, and maintenance history of
the pipeline must be reviewed and, where sufficient historical records
are not available, appropriate tests must be performed to determine if
the pipeline is in satisfactory condition for safe operation. If one or
more of the variables necessary to verify the design pressure under
Sec. 195.106 or to perform the testing under paragraph (a)(4) of this
section is unknown, the design pressure may be verified and the maximum
operating pressure determined by--
(i) Testing the pipeline in accordance with ASME B31.8, Appendix N,
to produce a stress equal to the yield strength; and
(ii) Applying, to not more than 80 percent of the first pressure
that produces a yielding, the design factor F in Sec. 195.106(a) and the
appropriate factors in Sec. 195.106(e).
(2) The pipeline right-of-way, all aboveground segments of the
pipeline, and appropriately selected underground segments must be
visually inspected for physical defects and operating conditions which
reasonably could be expected to impair the strength or tightness of the
pipeline.
(3) All known unsafe defects and conditions must be corrected in
accordance with this part.
(4) The pipeline must be tested in accordance with subpart E of this
part to substantiate the maximum operating pressure permitted by
Sec. 195.406.
(b) A pipeline which qualifies for use under this section need not
comply with the corrosion control requirements of this part until 12
months after it is placed in service, notwithstanding any earlier
deadlines for compliance. In addition to the requirements of subpart F
of this part, the corrosion control requirements of subpart D apply to
each pipeline which substantially meets those requirements before it is
placed in service or which is a segment that is replaced, relocated, or
substantially altered.
(c) Each operator must keep for the life of the pipeline a record of
the investigations, tests, repairs, replacements, and alterations made
under the requirements of paragraph (a) of this section.
[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-52,
59 FR 33396, June 28, 1994]
Sec. 195.8 Transportation of hazardous liquid or carbon dioxide in
pipelines constructed with other than steel pipe.
No person may transport any hazardous liquid or carbon dioxide
through a pipe that is constructed after October 1, 1970, for hazardous
liquids or after July 12, 1991 for carbon dioxide of material other than
steel unless the person has notified the Administrator in writing at
least 90 days before the transportation is to begin. The notice must
state whether carbon dioxide or a hazardous liquid is to be transported
and the chemical name, common name, properties and characteristics of
the hazardous liquid to be transported and the material used in
construction of the pipeline. If the Administrator determines that the
transportation of the hazardous liquid or carbon dioxide in the manner
proposed would be unduly hazardous, he will, within 90 days after
receipt of the notice, order the person that gave the notice, in
writing, not to transport the hazardous liquid or carbon dioxide in the
proposed manner until further notice.
[Amdt. 195-45, 56 FR 26925, June 12, 1991, as amended by Amdt. 195-50,
59 FR 17281, Apr. 12, 1994]
Sec. 195.9 Outer continental shelf pipelines.
Operators of transportation pipelines on the Outer Continental Shelf
must identify on all their respective pipelines the specific points at
which operating responsibility transfers to a producing operator. For
those instances in which the transfer points are not identifiable by a
durable marking, each operator will have until September 15, 1998 to
identify the transfer points. If it is not practicable to durably mark a
transfer point and the transfer point is located above water, the
operator must
[[Page 149]]
depict the transfer point on a schematic maintained near the transfer
point. If a transfer point is located subsea, the operator must identify
the transfer point on a schematic which must be maintained at the
nearest upstream facility and provided to RSPA upon request. For those
cases in which adjoining operators have not agreed on a transfer point
by September 15, 1998 the Regional Director and the MMS Regional
Supervisor will make a joint determination of the transfer point.
[Amdt. 195-59, 62 FR 61695, Nov. 19, 1997]
Sec. 195.10 Responsibility of operator for compliance with this part.
An operator may make arrangements with another person for the
performance of any action required by this part. However, the operator
is not thereby relieved from the responsibility for compliance with any
requirement of this part.
Subpart B--Reporting Accidents and Safety-Related Conditions
Sec. 195.50 Reporting accidents.
An accident report is required for each failure in a pipeline system
subject to this part in which there is a release of the hazardous liquid
or carbon dioxide transported resulting in any of the following:
(a) Explosion or fire not intentionally set by the operator.
(b) Loss of 50 or more barrels (8 or more cubic meters) of hazardous
liquid or carbon dioxide.
(c) Escape to the atmosphere of more than 5 barrels (0.8 cubic
meters) a day of highly volatile liquids.
(d) Death of any person.
(e) Bodily harm to any person resulting in one or more of the
following:
(1) Loss of consciousness.
(2) Necessity to carry the person from the scene.
(3) Necessity for medical treatment.
(4) Disability which prevents the discharge of normal duties or the
pursuit of normal activities beyond the day of the accident.
(f) Estimated property damage, including cost of clean-up and
recovery, value of lost product, and damage to the property of the
operator or others, or both, exceeding $50,000.
[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-39,
53 FR 24950, July 1, 1988; Amdt. 195-45, 56 FR 26925, June 12, 1991;
Amdt. 195-52, 59 FR 33396, June 28, 1994; Amdt. 195-63, 63 FR 37506,
July 13, 1998]
Sec. 195.52 Telephonic notice of certain accidents.
(a) At the earliest practicable moment following discovery of a
release of the hazardous liquid or carbon dioxide transported resulting
in an event described in Sec. 195.50, the operator of the system shall
give notice, in accordance with paragraph (b) of this section, of any
failure that:
(1) Caused a death or a personal injury requiring hospitalization;
(2) Resulted in either a fire or explosion not intentionally set by
the operator;
(3) Caused estimated property damage, including cost of cleanup and
recovery, value of lost product, and damage to the property of the
operator or others, or both, exceeding $50,000;
(4) Resulted in pollution of any stream, river, lake, reservoir, or
other similar body of water that violated applicable water quality
standards, caused a discoloration of the surface of the water or
adjoining shoreline, or deposited a sludge or emulsion beneath the
surface of the water or upon adjoining shorelines; or
(5) In the judgment of the operator was significant even though it
did not meet the criteria of any other paragraph of this section.
(b) Reports made under paragraph (a) of this section are made by
telephone to 800-424-8802 (in Washington, DC 267-2675) and must include
the following information:
(1) Name and address of the operator.
(2) Name and telephone number of the reporter.
(3) The location of the failure.
(4) The time of the failure.
(5) The fatalities and personal injuries, if any.
(6) All other significant facts known by the operator that are
relevant to
[[Page 150]]
the cause of the failure or extent of the damages.
[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-23,
47 FR 32720, July 29, 1982; Amdt. 195-44, 54 FR 40878, Oct. 4, 1989;
Amdt. 195-45, 56 FR 26925, June 12, 1991; Amdt. 195-52, 59 FR 33396,
June 28, 1994]
Sec. 195.54 Accident reports.
(a) Each operator that experiences an accident that is required to
be reported under Sec. 195.50 shall as soon as practicable, but not
later than 30 days after discovery of the accident, prepare and file an
accident report on DOT Form 7000-1, or a facsimile.
(b) Whenever an operator receives any changes in the information
reported or additions to the original report on DOT Form 7000-1, it
shall file a supplemental report within 30 days.
[Amdt. 195-39, 53 FR 24950, July 1, 1988]
Sec. 195.55 Reporting safety-related conditions.
(a) Except as provided in paragraph (b) of this section, each
operator shall report in accordance with Sec. 195.56 the existence of
any of the following safety-related conditions involving pipelines in
service:
(1) General corrosion that has reduced the wall thickness to less
than that required for the maximum operating pressure, and localized
corrosion pitting to a degree where leakage might result.
(2) Unintended movement or abnormal loading of a pipeline by
environmental causes, such as an earthquake, landslide, or flood, that
impairs its serviceability.
(3) Any material defect or physical damage that impairs the
serviceability of a pipeline.
(4) Any malfunction or operating error that causes the pressure of a
pipeline to rise above 110 percent of its maximum operating pressure.
(5) A leak in a pipeline that constitutes an emergency.
(6) Any safety-related condition that could lead to an imminent
hazard and causes (either directly or indirectly by remedial action of
the operator), for purposes other than abandonment, a 20 percent or more
reduction in operating pressure or shutdown of operation of a pipeline.
(b) A report is not required for any safety-related condition that--
(1) Exists on a pipeline that is more than 220 yards (200 meters)
from any building intended for human occupancy or outdoor place of
assembly, except that reports are required for conditions within the
right-of-way of an active railroad, paved road, street, or highway, or
that occur offshore or at onshore locations where a loss of hazardous
liquid could reasonably be expected to pollute any stream, river, lake,
reservoir, or other body of water;
(2) Is an accident that is required to be reported under Sec. 195.50
or results in such an accident before the deadline for filing the
safety-related condition report; or
(3) Is corrected by repair or replacement in accordance with
applicable safety standards before the deadline for filing the safety-
related condition report, except that reports are required for all
conditions under paragraph (a)(1) of this section other than localized
corrosion pitting on an effectively coated and cathodically protected
pipeline.
[Amdt. 195-39, 53 FR 24950, July 1, 1988; 53 FR 29800, Aug. 8, 1988, as
amended by Amdt. 195-63, 63 FR 37506, July 13, 1998]
Sec. 195.56 Filing safety-related condition reports.
(a) Each report of a safety-related condition under Sec. 195.55(a)
must be filed (received by the Administrator) in writing within 5
working days (not including Saturdays, Sundays, or Federal holidays)
after the day a representative of the operator first determines that the
condition exists, but not later than 10 working days after the day a
representative of the operator discovers the condition. Separate
conditions may be described in a single report if they are closely
related. To file a report by facsimile (fax), dial (202) 366-7128.
(b) The report must be headed ``Safety-Related Condition Report''
and provide the following information:
(1) Name and principal address of operator.
(2) Date of report.
(3) Name, job title, and business telephone number of person
submitting the report.
[[Page 151]]
(4) Name, job title, and business telephone number of person who
determined that the condition exists.
(5) Date condition was discovered and date condition was first
determined to exist.
(6) Location of condition, with reference to the State (and town,
city, or county) or offshore site, and as appropriate nearest street
address, offshore platform, survey station number, milepost, landmark,
or name of pipeline.
(7) Description of the condition, including circumstances leading to
its discovery, any significant effects of the condition on safety, and
the name of the commodity transported or stored.
(8) The corrective action taken (including reduction of pressure or
shutdown) before the report is submitted and the planned follow-up or
future corrective action, including the anticipated schedule for
starting and concluding such action.
[Amdt. 195-39, 53 FR 24950, July 1, 1988; 53 FR 29800, Aug. 8, 1988, as
amended by Amdt. 195-42, 54 FR 32344, Aug. 7, 1989; Amdt. 195-44, 54 FR
40878, Oct. 4, 1989; Amdt. 195-50, 59 FR 17281, Apr. 12, 1994; Amdt.
195-61, 63 FR 7723, Feb. 17, 1998]
Sec. 195.57 Filing offshore pipeline condition reports.
(a) Each operator shall, within 60 days after completion of the
inspection of all its underwater pipelines subject to Sec. 195.413(a),
report the following information:
(1) Name and principal address of operator.
(2) Date of report.
(3) Name, job title, and business telephone number of person
submitting the report.
(4) Total number of miles (kilometers) of pipeline inspected.
(5) Length and date of installation of each exposed pipeline
segment, and location; including, if available, the location according
to the Minerals Management Service or state offshore area and block
number tract.
(6) Length and date of installation of each pipeline segment, if
different from a pipeline segment identified under paragraph (a)(5) of
this section, that is a hazard to navigation, and the location;
including, if available, the location according to the Minerals
Management Service or state offshore area and block number tract.
(b) The report shall be mailed to the Information Officer, Research
and Special Programs Administration, Department of Transportation, 400
Seventh Street, SW., Washington, DC 20590.
[Amdt. 195-47, 56 FR 63771, Dec. 5, 1991, as amended by Amdt. 195-63, 63
FR 37506, July 13, 1998]
Sec. 195.58 Address for written reports.
Each written report required by this subpart must be made to the
Information Resources Manager, Office of Pipeline Safety, Research and
Special Programs Administration, U.S. Department of Transportation, Room
2335, 400 Seventh Street SW., Washington DC 20590. However, accident
reports for intrastate pipelines subject to the jurisdiction of a State
agency pursuant to a certification under the pipeline safety laws (49
U.S.C. 60101 et seq.) may be submitted in duplicate to that State agency
if the regulations of that agency require submission of these reports
and provide for further transmittal of one copy within 10 days of
receipt to the Information Resources Manager. Safety-related condition
reports required by Sec. 195.55 for intrastate pipelines must be
submitted concurrently to the State agency, and if that agency acts as
an agent of the Secretary with respect to interstate pipelines, safety-
related condition reports for these pipelines must be submitted
concurrently to that agency.
[Amdt. 195-55, 61 FR 18518, Apr. 26, 1996]
Sec. 195.60 Operator assistance in investigation.
If the Department of Transportation investigates an accident, the
operator involved shall make available to the representative of the
Department all records and information that in any way pertain to the
accident, and shall afford all reasonable assistance in the
investigation of the accident.
Sec. 195.62 Supplies of accident report DOT Form 7000-1.
Each operator shall maintain an adequate supply of forms that are a
facsimile of DOT Form 7000-1 to enable it
[[Page 152]]
to promptly report accidents. The Department will, upon request, furnish
specimen copies of the form. Requests should be addressed to the
Information Resources Manager, Office of Pipeline Safety, Department of
Transportation, Washington, DC 20590.
[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended at 47 FR 32720,
July 29, 1982]
Sec. 195.63 OMB control number assigned to information collection.
The control number assigned by the Office of Management and Budget
to the hazardous liquid pipeline information collection requirements of
this part pursuant to the Paperwork Reduction Act of 1980 is 2137-0047.
[Amdt. 195-34, 50 FR 34474, Aug. 26, 1985]
Subpart C--Design Requirements
Sec. 195.100 Scope.
This subpart prescribes minimum design requirements for new pipeline
systems constructed with steel pipe and for relocating, replacing, or
otherwise changing existing systems constructed with steel pipe.
However, it does not apply to the movement of line pipe covered by
Sec. 195.424.
Sec. 195.101 Qualifying metallic components other than pipe.
Notwithstanding any requirement of the subpart which incorporates by
reference an edition of a document listed in Sec. 195.3, a metallic
component other than pipe manufactured in accordance with any other
edition of that document is qualified for use if--
(a) It can be shown through visual inspection of the cleaned
component that no defect exists which might impair the strength or
tightness of the component: and
(b) The edition of the document under which the component was
manufactured has equal or more stringent requirements for the following
as an edition of that document currently or previously listed in
Sec. 195.3:
(1) Pressure testing;
(2) Materials; and
(3) Pressure and temperature ratings.
[Amdt. 195-28, 48 FR 30639, July 5, 1983]
Sec. 195.102 Design temperature.
(a) Material for components of the system must be chosen for the
temperature environment in which the components will be used so that the
pipeline will maintain its structural integrity.
(b) Components of carbon dioxide pipelines that are subject to low
temperatures during normal operation because of rapid pressure reduction
or during the initial fill of the line must be made of materials that
are suitable for those low temperatures.
[Admt. 195-45, 56 FR 26925, June 12, 1991]
Sec. 195.104 Variations in pressure.
If, within a pipeline system, two or more components are to be
connected at a place where one will operate at a higher pressure than
another, the system must be designed so that any component operating at
the lower pressure will not be overstressed.
Sec. 195.106 Internal design pressure.
(a) Internal design pressure for the pipe in a pipeline is
determined in accordance with the following formula:
P=(2 St/D) x E x F
P=Internal design pressure in p.s.i. (kPa) gage.
S=Yield strength in pounds per square inch (kPa) determined in
accordance with paragraph (b) of this section.
t=Nominal wall thickness of the pipe in inches (millimeters). If
this is unknown, it is determined in accordance with paragraph (c) of
this section.
D=Nominal outside diameter of the pipe in inches (millimeters).
E=Seam joint factor determined in accordance with paragraph (e) of
this section.
F=A design factor of 0.72, except that a design factor of 0.60 is
used for pipe, including risers, on a platform located offshore or on a
platform in inland navigable waters, and 0.54 is used for pipe that has
been subjected to cold expansion to meet the specified minimum yield
strength and is subsequently heated, other than by welding or stress
relieving as a part of welding, to a
[[Page 153]]
temperature higher than 900 deg. F (482 deg. C) for any period of time
or over 600 deg. F (316 deg. C) for more than 1 hour.
(b) The yield strength to be used in determining the internal design
pressure under paragraph (a) of this section is the specified minimum
yield strength. If the specified minimum yield strength is not known,
the yield strength to be used in the design formula is one of the
following:
(1)(i) The yield strength determined by performing all of the
tensile tests of API Specification 5L on randomly selected specimens
with the following number of tests:
------------------------------------------------------------------------
Pipe size No. of tests
------------------------------------------------------------------------
Less than 6\5/8\ in (168 mm) nominal One test for each 200
outside diameter. lengths.
6 \5/8\ in through 12\3/4\ in (168 mm One test for each 100
through 324 mm) nominal outside diameter. lengths.
Larger than 12\3/4\ in (324 mm) nominal One test for each 50
outside diameter. lengths.
------------------------------------------------------------------------
(ii) If the average yield-tensile ratio exceeds 0.85, the yield
strength shall be taken as 24,000 p.s.i. (165,474 kPa). If the average
yield-tensile ratio is 0.85 or less, the yield strength of the pipe is
taken as the lower of the following:
(A) Eighty percent of the average yield strength determined by the
tensile tests.
(B) The lowest yield strength determined by the tensile tests.
(2) If the pipe is not tensile tested as provided in paragraph (b)
of this section, the yield strength shall be taken as 24,000 p.s.i.
(165,474 kPa).
(c) If the nominal wall thickness to be used in determining internal
design pressure under paragraph (a) of this section is not known, it is
determined by measuring the thickness of each piece of pipe at quarter
points on one end. However, if the pipe is of uniform grade, size, and
thickness, only 10 individual lengths or 5 percent of all lengths,
whichever is greater, need be measured. The thickness of the lengths
that are not measured must be verified by applying a gage set to the
minimum thickness found by the measurement. The nominal wall thickness
to be used is the next wall thickness found in commercial specifications
that is below the average of all the measurements taken. However, the
nominal wall thickness may not be more than 1.14 times the smallest
measurement taken on pipe that is less than 20 inches (508 mm) nominal
outside diameter, nor more than 1.11 times the smallest measurement
taken on pipe that is 20 inches (508 mm) or more in nominal outside
diameter.
(d) The minimum wall thickness of the pipe may not be less than 87.5
percent of the value used for nominal wall thickness in determining the
internal design pressure under paragraph (a) of this section. In
addition, the anticipated external loads and external pressures that are
concurrent with internal pressure must be considered in accordance with
Secs. 195.108 and 195.110 and, after determining the internal design
pressure, the nominal wall thickness must be increased as necessary to
compensate for these concurrent loads and pressures.
(e) The seam joint factor used in paragraph (a) of this section is
determined in accordance with the following table:
------------------------------------------------------------------------
Seam
Specification Pipe class joint
factor
------------------------------------------------------------------------
ASTM A53............................ Seamless.................. 1.00
Electric resistance welded 1.00
Furnace lap welded........ 0.80
Furnace butt welded....... 0.60
ASTM A106........................... Seamless.................. 1.00
ASTM A 333/A 333M................... Seamless.................. 1.00
Welded.................... 1.00
ASTM A381........................... Double submerged arc 1.00
welded.
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 lap welded........ 0.80
Furnace butt welded....... 0.60
------------------------------------------------------------------------
The seam joint factor for pipe which is not covered by this paragraph
must be approved by the Administrator.
[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982,
as amended by Amdt. 195-30, 49 FR 7569, Mar. 1, 1984; Amdt 195-37, 51 FR
15335, Apr. 23, 1986; Amdt 195-40, 54 FR 5628, Feb. 6, 1989; 58 FR
14524, Mar. 18, 1993; Amdt. 195-50, 59 FR 17281, Apr. 12, 1994; Amdt.
195-52, 59 FR 33396, 33397, June 28, 1994; Amdt. 195-63, 63 FR 37506,
July 13, 1998]
[[Page 154]]
Sec. 195.108 External pressure.
Any external pressure that will be exerted on the pipe must be
provided for in designing a pipeline system.
Sec. 195.110 External loads.
(a) Anticipated external loads (e.g.), earthquakes, vibration,
thermal expansion, and contraction must be provided for in designing a
pipeline system. In providing for expansion and flexibility, section 419
of ASME/ANSI B31.4 must be followed.
(b) The pipe and other components must be supported in such a way
that the support does not cause excess localized stresses. In designing
attachments to pipe, the added stress to the wall of the pipe must be
computed and compensated for.
[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended at 58 FR 14524,
Mar. 18, 1993]
Sec. 195.111 Fracture propagation.
A carbon dioxide pipeline system must be designed to mitigate the
effects of fracture propagation.
[Amdt. 195-45, 56 FR 26926, June 12, 1991]
Sec. 195.112 New pipe.
Any new pipe installed in a pipeline system must comply with the
following:
(a) The pipe must be made of steel of the carbon, low alloy-high
strength, or alloy type that is able to withstand the internal pressures
and external loads and pressures anticipated for the pipeline system.
(b) The pipe must be made in accordance with a written pipe
specification that sets forth the chemical requirements for the pipe
steel and mechanical tests for the pipe to provide pipe suitable for the
use intended.
(c) Each length of pipe with a nominal outside diameter of 4 \1/2\
in (114.3 mm) or more must be marked on the pipe or pipe coating with
the specification to which it was made, the specified minimum yield
strength or grade, and the pipe size. The marking must be applied in a
manner that does not damage the pipe or pipe coating and must remain
visible until the pipe is installed.
[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-52,
59 FR 33396, June 28, 1994; Amdt. 195-63, 63 FR 37506, July 13, 1998]
Sec. 195.114 Used pipe.
Any used pipe installed in a pipeline system must comply with
Sec. 195.112 (a) and (b) and the following:
(a) The pipe must be of a known specification and the seam joint
factor must be determined in accordance with Sec. 195.106(e). If the
specified minimum yield strength or the wall thickness is not known, it
is determined in accordance with Sec. 195.106 (b) or (c) as appropriate.
(b) There may not be any:
(1) Buckles;
(2) Cracks, grooves, gouges, dents, or other surface defects that
exceed the maximum depth of such a defect permitted by the specification
to which the pipe was manufactured; or
(3) Corroded areas where the remaining wall thickness is less than
the minimum thickness required by the tolerances in the specification to
which the pipe was manufactured.
However, pipe that does not meet the requirements of paragraph (b)(3) of
this section may be used if the operating pressure is reduced to be
commensurate with the remaining wall thickness.
[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982]
Sec. 195.116 Valves.
Each valve installed in a pipeline system must comply with the
following:
(a) The valve must be of a sound engineering design.
(b) Materials subject to the internal pressure of the pipeline
system, including welded and flanged ends, must be compatible with the
pipe or fittings to which the valve is attached.
(c) Each part of the valve that will be in contact with the carbon
dioxide or hazardous liquid stream must be made of materials that are
compatible with carbon dioxide or each hazardous liquid that it is
anticipated will flow through the pipeline system.
[[Page 155]]
(d) Each valve must be both hydrostatically shell tested and
hydrostatically seat tested without leakage to at least the requirements
set forth in section 5 of API Standard 6D.
(e) Each valve other than a check valve must be equipped with a
means for clearly indicating the position of the valve (open, closed,
etc.).
(f) Each valve must be marked on the body or the nameplate, with at
least the following:
(1) Manufacturer's name or trademark.
(2) Class designation or the maximum working pressure to which the
valve may be subjected.
(3) Body material designation (the end connection material, if more
than one type is used).
(4) Nominal valve size.
[Amdt. 195-22, 46 FR 38360, July 27, 1981 as amended by Amdt. 195-45, 56
FR 26926, June 12, 1991]
Sec. 195.118 Fittings.
(a) Butt-welding type fittings must meet the marking, end
preparation, and the bursting strength requirements of ASME/ANSI B16.9
or MSS Standard Practice SP-75.
(b) There may not be any buckles, dents, cracks, gouges, or other
defects in the fitting that might reduce the strength of the fitting.
(c) The fitting must be suitable for the intended service and be at
least as strong as the pipe and other fittings in the pipeline system to
which it is attached.
[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982,
as amended at 58 FR 14524, Mar. 18, 1993]
Sec. 195.120 Passage of internal inspection devices.
(a) Except as provided in paragraphs (b) and (c) of this section,
each new pipeline and each line section of a pipeline where the line
pipe, valve, fitting or other line component is replaced; must be
designed and constructed to accommodate the passage of instrumented
internal inspection devices.
(b) This section does not apply to:
(1) Manifolds;
(2) Station piping such as at pump stations, meter stations, or
pressure reducing stations;
(3) Piping associated with tank farms and other storage facilities;
(4) Cross-overs;
(5) Sizes of pipe for which an instrumented internal inspection
device is not commercially available;
(6) Offshore pipelines, other than main lines 10 inches (254
millimeters) or greater in nominal diameter, that transport liquids to
onshore facilities; and
(7) Other piping that the Administrator under Sec. 190.9 of this
chapter, finds in a particular case would be impracticable to design and
construct to accommodate the passage of instrumented internal inspection
devices.
(c) An operator encountering emergencies, construction time
constraints and other unforeseen construction problems need not
construct a new or replacement segment of a pipeline to meet paragraph
(a) of this section, if the operator determines and documents why an
impracticability prohibits compliance with paragraph (a) of this
section. Within 30 days after discovering the emergency or construction
problem the operator must petition, under Sec. 190.9 of this chapter,
for approval that design and construction to accommodate passage of
instrumented internal inspection devices would be impracticable. If the
petition is denied, within 1 year after the date of the notice of the
denial, the operator must modify that segment to allow passage of
instrumented internal inspection devices.
[Amdt. 195-50, 59 FR 17281, Apr. 12, 1994, as amended by Amdt. 195-63,
63 FR 37506, July 13, 1998]
Sec. 195.122 Fabricated branch connections.
Each pipeline system must be designed so that the addition of any
fabricated branch connections will not reduce the strength of the
pipeline system.
Sec. 195.124 Closures.
Each closure to be installed in a pipeline system must comply with
the ASME Boiler and Pressure Vessel Code, section VIII, Pressure
Vessels, Division
[[Page 156]]
1, and must have pressure and temperature ratings at least equal to
those of the pipe to which the closure is attached.
Sec. 195.126 Flange connection.
Each component of a flange connection must be compatible with each
other component and the connection as a unit must be suitable for the
service in which it is to be used.
Sec. 195.128 Station piping.
Any pipe to be installed in a station that is subject to system
pressure must meet the applicable requirements of this subpart.
Sec. 195.130 Fabricated assemblies.
Each fabricated assembly to be installed in a pipeline system must
meet the applicable requirements of this subpart.
195.132 Design and construction of aboveground breakout tanks.
(a) Each aboveground breakout tank must be designed and constructed
to withstand the internal pressure produced by the hazardous liquid to
be stored therein and any anticipated external loads.
(b) For aboveground breakout tanks first placed in service after
October 2, 2000, compliance with paragraph (a) of this section requires
one of the following:
(1) Shop-fabricated, vertical, cylindrical, closed top, welded steel
tanks with nominal capacities of 90 to 750 barrels (14.3 to 119.2 m \3\)
and with internal vapor space pressures that are approximately
atmospheric must be designed and constructed in accordance with API
Specification 12F.
(2) Welded, low-pressure (i.e., internal vapor space pressure not
greater than 15 psig (103.4 kPa)), carbon steel tanks that have wall
shapes that can be generated by a single vertical axis of revolution
must be designed and constructed in accordance with API Standard 620.
(3) Vertical, cylindrical, welded steel tanks with internal
pressures at the tank top approximating atmospheric pressures (i.e.,
internal vapor space pressures not greater than 2.5 psig (17.2 kPa), or
not greater than the pressure developed by the weight of the tank roof)
must be designed and constructed in accordance with API Standard 650.
(4) High pressure steel tanks (i.e., internal gas or vapor space
pressures greater than 15 psig (103.4 kPa)) with a nominal capacity of
2000 gallons (7571 liters) or more of liquefied petroleum gas (LPG) must
be designed and constructed in accordance with API Standard 2510.
[Amdt. 195-66, 64 FR 15935, Apr. 2, 1999]
Sec. 195.134 CPM leak detection.
This section applies to each hazardous liquid pipeline transporting
liquid in single phase (without gas in the liquid). On such systems,
each new computational pipeline monitoring (CPM) leak detection system
and each replaced component of an existing CPM system must comply with
section 4.2 of API 1130 in its design and with any other design criteria
addressed in API 1130 for components of the CPM leak detection system.
[Amdt. 195-62, 63 FR 36376, July 6, 1998]
Subpart D--Construction
Sec. 195.200 Scope.
This subpart prescribes minimum requirements for constructing new
pipeline systems with steel pipe, and for relocating, replacing, or
otherwise changing existing pipeline systems that are constructed with
steel pipe. However, this subpart does not apply to the movement of pipe
covered by Sec. 195.424.
Sec. 195.202 Compliance with specifications or standards.
Each pipeline system must be constructed in accordance with
comprehensive written specifications or standards that are consistent
with the requirements of this part.
Sec. 195.204 Inspection--general.
Inspection must be provided to ensure the installation of pipe or
pipeline systems in accordance with the requirements of this subpart. No
person may be used to perform inspections unless that person has been
trained and is
[[Page 157]]
qualified in the phase of construction to be inspected.
[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-52,
59 FR 33397, June 28, 1994]
Sec. 195.205 Repair, alteration and reconstruction of aboveground
breakout tanks that have been in service.
(a) Aboveground breakout tanks that have been repaired, altered, or
reconstructed and returned to service must be capable of withstanding
the internal pressure produced by the hazardous liquid to be stored
therein and any anticipated external loads.
(b) After October 2, 2000, compliance with paragraph (a) of this
section requires the following for the tanks specified:
(1) For tanks designed for approximately atmospheric pressure
constructed of carbon and low alloy steel, welded or riveted, and non-
refrigerated and tanks built to API Standard 650 or its predecessor
Standard 12C, repair, alteration, and reconstruction must be in
accordance with API Standard 653.
(2) For tanks built to API Specification 12F or API Standard 620,
the repair, alteration, and reconstruction must be in accordance with
the design, welding, examination, and material requirements of those
respective standards.
(3) For high pressure tanks built to API Standard 2510, repairs,
alterations, and reconstruction must be in accordance with API 510.
[Amdt. 195-66, 64 FR 15935, Apr. 2, 1999]
Sec. 195.206 Material inspection.
No pipe or other component may be installed in a pipeline system
unless it has been visually inspected at the site of installation to
ensure that it is not damaged in a manner that could impair its strength
or reduce its serviceability.
Sec. 195.208 Welding of supports and braces.
Supports or braces may not be welded directly to pipe that will be
operated at a pressure of more than 100 p.s.i. (689 kPa) gage.
[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-63,
63 FR 37506, July 13, 1998]
Sec. 195.210 Pipeline location.
(a) Pipeline right-of-way must be selected to avoid, as far as
practicable, areas containing private dwellings, industrial buildings,
and places of public assembly.
(b) No pipeline may be located within 50 feet (15 meters) of any
private dwelling, or any industrial building or place of public assembly
in which persons work, congregate, or assemble, unless it is provided
with at least 12 inches (305 millimeters) of cover in addition to that
prescribed in Sec. 195.248.
[Amdt. 195-22, 46 FR 39360, July 27, 1981, as amended by Amdt. 195-63,
63 FR 37506, July 13, 1998]
Sec. 195.212 Bending of pipe.
(a) Pipe must not have a wrinkle bend.
(b) Each field bend must comply with the following:
(1) A bend must not impair the serviceability of the pipe.
(2) Each bend must have a smooth contour and be free from buckling,
cracks, or any other mechanical damage.
(3) On pipe containing a longitudinal weld, the longitudinal weld
must be as near as practicable to the neutral axis of the bend unless--
(i) The bend is made with an internal bending mandrel; or
(ii) The pipe is 12\3/4\ in (324 mm) or less nominal outside
diameter or has a diameter to wall thickness ratio less than 70.
(c) Each circumferential weld which is located where the stress
during bending causes a permanent deformation in the pipe must be
nondestructively tested either before or after the bending process.
[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-52,
59 FR 33396, June 28, 1994; Amdt. 195-63, 63 FR 37506, July 13, 1998]
[[Page 158]]
Sec. 195.214 Welding: General.
(a) Welding must be performed by a qualified welder in accordance
with welding procedures qualified to produce welds meeting the
requirements of this subpart. The quality of the test welds used to
qualify the procedure shall be determined by destructive testing.
(b) Each welding procedure must be recorded in detail, including the
results of the qualifying tests. This record must be retained and
followed whenever the procedure is used.
[Amdt. 195-38, 51 FR 20297, June 4, 1986]
Sec. 195.216 Welding: Miter joints.
A miter joint is not permitted (not including deflections up to 3
degrees that are caused by misalignment).
Sec. 195.222 Welders: Qualification of welders.
Each welder must be qualified in accordance with section 3 of API
Standard 1104 or section IX of the ASME Boiler and Pressure Vessel Code,
except that a welder qualified under an earlier edition than listed in
Sec. 195.3 may weld but may not requalify under that earlier edition.
[Amdt. 195-32, 49 FR 36860, Sept. 20, 1984, as amended by Amdt. 195-38,
51 FR 20297, June 4, 1986]
Sec. 195.224 Welding: Weather.
Welding must be protected from weather conditions that would impair
the quality of the completed weld.
Sec. 195.226 Welding: Arc burns.
(a) Each arc burn must be repaired.
(b) An arc burn may be repaired by completely removing the notch by
grinding, if the grinding does not reduce the remaining wall thickness
to less than the minimum thickness required by the tolerances in the
specification to which the pipe is manufactured. If a notch is not
repairable by grinding, a cylinder of the pipe containing the entire
notch must be removed.
(c) A ground may not be welded to the pipe or fitting that is being
welded.
Sec. 195.228 Welds and welding inspection: Standards of acceptability.
(a) Each weld and welding must be inspected to insure compliance
with the requirements of this subpart. Visual inspection must be
supplemented by nondestructive testing.
(b) The acceptability of a weld is determined according to the
standards in section 6 of API Standard 1104. However, if a girth weld is
unacceptable under those standards for a reason other than a crack, and
if the Appendix to API Standard 1104 applies to the weld, the
acceptability of the weld may be determined under that appendix.
[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-52,
59 FR 33397, June 28, 1994]
Sec. 195.230 Welds: Repair or removal of defects.
(a) Each weld that is unacceptable under Sec. 195.228 must be
removed or repaired. Except for welds on an offshore pipeline being
installed from a pipelay vessel, a weld must be removed if it has a
crack that is more than 8 percent of the weld length.
(b) Each weld that is repaired must have the defect removed down to
sound metal and the segment to be repaired must be preheated if
conditions exist which would adversely affect the quality of the weld
repair. After repair, the segment of the weld that was repaired must be
inspected to ensure its acceptability.
(c) Repair of a crack, or of any defect in a previously repaired
area must be in accordance with written weld repair procedures that have
been qualified under Sec. 195.214. Repair procedures must provide that
the minimum mechanical properties specified for the welding procedure
used to make the original weld are met upon completion of the final weld
repair.
[Amdt. 195-29, 48 FR 48674, Oct. 20, 1983]
Sec. 195.234 Welds: Nondestructive testing.
(a) A weld may be nondestructively tested by any process that will
clearly indicate any defects that may affect the integrity of the weld.
(b) Any nondestructive testing of welds must be performed--
[[Page 159]]
(1) In accordance with a written set of procedures for
nondestructive testing; and
(2) With personnel that have been trained in the established
procedures and in the use of the equipment employed in the testing.
(c) Procedures for the proper interpretation of each weld inspection
must be established to ensure the acceptability of the weld under
Sec. 195.228.
(d) During construction, at least 10 percent of the girth welds made
by each welder during each welding day must be nondestructively tested
over the entire circumference of the weld.
(e) All girth welds installed each day in the following locations
must be nondestructively tested over their entire circumference, except
that when nondestructive testing is impracticable for a girth weld, it
need not be tested if the number of girth welds for which testing is
impracticable does not exceed 10 percent of the girth welds installed
that day:
(1) At any onshore location where a loss of hazardous liquid could
reasonably be expected to pollute any stream, river, lake, reservoir, or
other body of water, and any offshore area;
(2) Within railroad or public road rights-of-way;
(3) At overhead road crossings and within tunnels;
(4) Within the limits of any incorporated subdivision of a State
government; and
(5) Within populated areas, including, but not limited to,
residential subdivisions, shopping centers, schools, designated
commercial areas, industrial facilities, public institutions, and places
of public assembly.
(f) When installing used pipe, 100 percent of the old girth welds
must be nondestructively tested.
(g) At pipeline tie-ins, including tie-ins of replacement sections,
100 percent of the girth welds must be nondestructively tested.
[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-35,
50 FR 37192, Sept. 21, 1985; Amdt. 195-52, 59 FR 33397, June 28, 1994]
Sec. 195.236 External corrosion protection.
Each component in the pipeline system must be provided with
protection against external corrosion.
Sec. 195.238 External coating.
(a) No pipeline system component may be buried or submerged unless
that component has an external protective coating that--
(1) Is designed to mitigate corrosion of the buried or submerged
component;
(2) Has sufficient adhesion to the metal surface to prevent
underfilm migration of moisture;
(3) Is sufficiently ductile to resist cracking;
(4) Has enough strength to resist damage due to handling and soil
stress; and
(5) Supports any supplemental cathodic protection.
In addition, if an insulating-type coating is used it must have low
moisture absorption and provide high electrical resistance.
(b) All pipe coating must be inspected just prior to lowering the
pipe into the ditch or submerging the pipe, and any damage discovered
must be repaired.
Sec. 195.242 Cathodic protection system.
(a) A cathodic protection system must be installed for all buried or
submerged facilities to mitigate corrosion
that might result in structural failure. A test procedure must be
developed to determine whether adequate cathodic protection has been
achieved.
(b) A cathodic protection system must be installed not later than 1
year after completing the construction.
(c) For the bottoms of aboveground breakout tanks with greater than
500 barrels (79.5 m \3\) capacity built to API Specification 12F, API
Standard 620, or API Standard 650 (or its predecessor Standard 12C), the
installation of a cathodic protection system under paragraph (a) of this
section after October 2, 2000, must be in accordance with API
Recommended Practice 651, unless the operator notes in the procedural
manual (Sec. 195.402(c)) why compliance with
[[Page 160]]
all or certain provisions of API Recommended Practice 651 is not
necessary for the safety of a particular breakout tank.
(d) For the internal bottom of aboveground breakout tanks built to
API Specification 12F, API Standard 620, or API Standard 650 (or its
predecessor Standard 12C), the installation of a tank bottom lining
after October 2, 2000, must be in accordance with API Recommended
Practice 652, unless the operator notes in the procedural manual
(Sec. 195.402(c)) why compliance with all or certain provisions of API
Recommended Practice 652 is not necessary for the safety of a particular
breakout tank.
[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-66,
64 FR 15935, Apr. 2, 1999]
Sec. 195.244 Test leads.
(a) Except for offshore pipelines, electrical test leads used for
corrosion control or electrolysis testing must be installed at intervals
frequent enough to obtain electrical measurements indicating the
adequacy of the cathodic protection.
(b) Test leads must be installed as follows:
(1) Enough looping or slack must be provided to prevent test leads
from being unduly stressed or broken during backfilling.
(2) Each lead must be attached to the pipe so as to prevent stress
concentration on the pipe.
(3) Each lead installed in a conduit must be suitably insulated from
the conduit.
Sec. 195.246 Installation of pipe in a ditch.
(a) All pipe installed in a ditch must be installed in a manner that
minimizes the introduction of secondary stresses and the possibility of
damage to the pipe.
(b) Except for pipe in the Gulf of Mexico and its inlets, all
offshore pipe in water at least 3.7 m (12 ft) deep but not more than 61
m (200 ft) deep, as measured from the mean low tide, must be installed
so that the top of the pipe is below the natural bottom unless the pipe
is supported by stanchions, held in place by anchors or heavy concrete
coating, or protected by an equivalent means.
[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-52,
59 FR 33397, June 28, 1994; 59 FR 36256, July 15, 1994]
Sec. 195.248 Cover over buried pipeline.
(a) Unless specifically exempted in this subpart, all pipe must be
buried so that it is below the level of cultivation. Except as provided
in paragraph (b) of this section, the pipe must be installed so that the
cover between the top of the pipe and the ground level, road bed, river
bottom, or sea bottom, as applicable, complies with the following table:
------------------------------------------------------------------------
Cover inches (millimeters)
---------------------------
Location For normal For rock
excavation excavation \1\
------------------------------------------------------------------------
Industrial, commercial, and residential 36 (914) 30 (762)
areas......................................
Crossings of inland bodies of water with a 48 (1219) 18 (457)
width of at least 100 ft (30 mm) from high
water mark to high water mark..............
Drainage ditches at public roads and 36 (914) 36 (914)
railroads..................................
Deepwater port safety zone.................. 48 (1219) 24 (610)
Gulf of Mexico and its inlets and other 36 (914) 18 (457)
offshore areas under water less than 12 ft
(3.7 m) deep as measured from the mean low
tide.......................................
Any other area.............................. 30 (762) 18 (457)
------------------------------------------------------------------------
\1\ Rock excavation is any excavation that requires blasting or removal
by equivalent means.
(b) Except for the Gulf of Mexico and its inlets, less cover than
the minimum required by paragraph (a) of this section and Sec. 195.210
may be used if--
(1) It is impracticable to comply with the minimum cover
requirements; and
[[Page 161]]
(2) Additional protection is provided that is equivalent to the
minimum required cover.
[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982 as
amended by Amdt. 195-52, 59 FR 33397, June 28, 1994; 59 FR 36256, July
15, 1994; Amdt. 195-63, 63 FR 37506, July 13, 1998]
Sec. 195.250 Clearance between pipe and underground structures.
Any pipe installed underground must have at least 12 inches (305
millimeters) of clearance between the outside of the pipe and the
extremity of any other underground structure, except that for drainage
tile the minimum clearance may be less than 12 inches (305 millimeters)
but not less than 2 inches (51 millimeters). However, where 12 inches
(305 millimeters) of clearance is impracticable, the clearance may be
reduced if adequate provisions are made for corrosion control.
[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-63,
63 FR 37506, July 13, 1998]
Sec. 195.252 Backfilling.
Backfilling must be performed in a manner that protects any pipe
coating and provides firm support for the pipe.
Sec. 195.254 Above ground components.
(a) Any component may be installed above ground in the following
situations, if the other applicable requirements of this part are
complied with:
(1) Overhead crossings of highways, railroads, or a body of water.
(2) Spans over ditches and gullies.
(3) Scraper traps or block valves.
(4) Areas under the direct control of the operator.
(5) In any area inaccessible to the public.
(b) Each component covered by this section must be protected from
the forces exerted by the anticipated loads.
Sec. 195.256 Crossing of railroads and highways.
The pipe at each railroad or highway crossing must be installed so
as to adequately withstand the dynamic forces exerted by anticipated
traffic loads.
Sec. 195.258 Valves: General.
(a) Each valve must be installed in a location that is accessible to
authorized employees and that is protected from damage or tampering.
(b) Each submerged valve located offshore or in inland navigable
waters must be marked, or located by conventional survey techniques, to
facilitate quick location when operation of the valve is required.
Sec. 195.260 Valves: Location.
A valve must be installed at each of the following locations:
(a) On the suction end and the discharge end of a pump station in a
manner that permits isolation of the pump station equipment in the event
of an emergency.
(b) On each line entering or leaving a breakout storage tank area in
a manner that permits isolation of the tank area from other facilities.
(c) On each mainline at locations along the pipeline system that
will minimize damage or pollution from accidental hazardous liquid
discharge, as appropriate for the terrain in open country, for offshore
areas, or for populated areas.
(d) On each lateral takeoff from a trunk line in a manner that
permits shutting off the lateral without interrupting the flow in the
trunk line.
(e) On each side of a water crossing that is more than 100 feet (30
meters) wide from high-water mark to high-water mark unless the
Administrator finds in a particular case that valves are not justified.
(f) On each side of a reservoir holding water for human consumption.
[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982;
Amdt. 195-50, 59 FR 17281, Apr. 12, 1994; Amdt. 195-63, 63 FR 37506,
July 13, 1998]
Sec. 195.262 Pumping equipment.
(a) Adequate ventilation must be provided in pump station buildings
to prevent the accumulation of hazardous vapors. Warning devices must be
installed to warn of the presence of hazardous vapors in the pumping
station building.
(b) The following must be provided in each pump station:
[[Page 162]]
(1) Safety devices that prevent overpressuring of pumping equipment,
including the auxiliary pumping equipment within the pumping station.
(2) A device for the emergency shutdown of each pumping station.
(3) If power is necessary to actuate the safety devices, an
auxiliary power supply.
(c) Each safety device must be tested under conditions approximating
actual operations and found to function properly before the pumping
station may be used.
(d) Except for offshore pipelines, pumping equipment must be
installed on property that is under the control of the operator and at
least 15.2 m (50 ft) from the boundary of the pump station.
(e) Adequate fire protection must be installed at each pump station.
If the fire protection system installed requires the use of pumps,
motive power must be provided for those pumps that is separate from the
power that operates the station.
[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-52,
59 FR 33397, June 28, 1994]
Sec. 195.264 Impoundment, protection against entry, normal/emergency
venting or pressure/vacuum relief for aboveground breakout
tanks.
(a) A means must be provided for containing hazardous liquids in the
event of spillage or failure of an aboveground breakout tank.
(b) After October 2, 2000, compliance with paragraph (a) of this
section requires the following for the aboveground breakout tanks
specified:
(1) For tanks built to API Specification 12F, API Standard 620, and
others (such as API Standard 650 or its predecessor Standard 12C), the
installation of impoundment must be in accordance with the following
sections of NFPA 30:
(i) Impoundment around a breakout tank must be installed in
accordance with Section 2-3.4.3; and
(ii) Impoundment by drainage to a remote impounding area must be
installed in accordance with Section 2-3.4.2.
(2) For tanks built to API Standard 2510, the installation of
impoundment must be in accordance with Section 3 or 9 of API Standard
2510.
(c) Aboveground breakout tank areas must be adequately protected
against unauthorized entry.
(d) Normal/emergency relief venting must be provided for each
atmospheric pressure breakout tank. Pressure/vacuum-relieving devices
must be provided for each low-pressure and high-pressure breakout tank.
(e) For normal/emergency relief venting and pressure/vacuum-
relieving devices installed on aboveground breakout tanks after October
2, 2000, compliance with paragraph (d) of this section requires the
following for the tanks specified:
(1) Normal/emergency relief venting installed on atmospheric
pressure tanks built to API Specification 12F must be in accordance with
Section 4, and Appendices B and C, of API Specification 12F.
(2) Normal/emergency relief venting installed on atmospheric
pressure tanks (such as those built to API Standard 650 or its
predecessor Standard 12C) must be in accordance with API Standard 2000.
(3) Pressure-relieving and emergency vacuum-relieving devices
installed on low pressure tanks built to API Standard 620 must be in
accordance with Section 7 of API Standard 620 and its references to the
normal and emergency venting requirements in API Standard 2000.
(4) Pressure and vacuum-relieving devices installed on high pressure
tanks built to API Standard 2510 must be in accordance with Sections 5
or 9 of API Standard 2510.
[Amdt. 195-66, 64 FR 15935, Apr. 2, 1999]
Sec. 195.266 Construction records.
A complete record that shows the following must be maintained by the
operator involved for the life of each pipeline facility:
(a) The total number of girth welds and the number nondestructively
tested, including the number rejected and the disposition of each
rejected weld.
(b) The amount, location; and cover of each size of pipe installed.
(c) The location of each crossing of another pipeline.
(d) The location of each buried utility crossing.
[[Page 163]]
(e) The location of each overhead crossing.
(f) The location of each valve and corrosion test station.
[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-34,
50 FR 34474, Aug. 26, 1985]
Subpart E--Pressure Testing
Sec. 195.300 Scope.
This subpart prescribes minimum requirements for the pressure
testing of steel pipelines. However, this subpart does not apply to the
movement of pipe under Sec. 195.424.
[Amdt. 195-51, 59 FR 29384, June 7, 1994]
Sec. 195.302 General requirements.
(a) Except as otherwise provided in this section and in
Sec. 195.305(b), no operator may operate a pipeline unless it has been
pressure tested under this subpart without leakage. In addition, no
operator may return to service a segment of pipeline that has been
replaced, relocated, or otherwise changed until it has been pressure
tested under this subpart without leakage.
(b) Except for pipelines converted under Sec. 195.5, the following
pipelines may be operated without pressure testing under this subpart:
(1) Any hazardous liquid pipeline whose maximum operating pressure
is established under Sec. 195.406(a)(5) that is--
(i) An interstate pipeline constructed before January 8, 1971;
(ii) An interstate offshore gathering line constructed before August
1, 1977;
(iii) An intrastate pipeline constructed before October 21, 1985; or
(iv) A low-stress pipeline constructed before August 11, 1994 that
transports HVL.
(2) Any carbon dioxide pipeline constructed before July 12, 1991,
that--
(i) Has its maximum operating pressure established under
Sec. 195.406(a)(5); or
(ii) Is located in a rural area as part of a production field
distribution system.
(3) Any low-stress pipeline constructed before August 11, 1994 that
does not transport HVL.
(4) Those portions of older hazardous liquid and carbon dioxide
pipelines for which an operator has elected the risk-based alternative
under Sec. 195.303 and which are not required to be tested based on the
risk-based criteria.
(c) Except for pipelines that transport HVL onshore, low-stress
pipelines, and pipelines covered under Sec. 195.303, the following
compliance deadlines apply to pipelines under paragraphs (b)(1) and
(b)(2)(i) of this section that have not been pressure tested under this
subpart:
(1) Before December 7, 1998, for each pipeline each operator shall--
(i) Plan and schedule testing according to this paragraph; or
(ii) Establish the pipeline's maximum operating pressure under
Sec. 195.406(a)(5).
(2) For pipelines scheduled for testing, each operator shall--
(i) Before December 7, 2000, pressure test--
(A) Each pipeline identified by name, symbol, or otherwise that
existing records show contains more than 50 percent by mileage (length)
of electric resistance welded pipe manufactured before 1970; and
(B) At least 50 percent of the mileage (length) of all other
pipelines; and
(ii) Before December 7, 2003, pressure test the remainder of the
pipeline mileage (length).
[Amdt. 195-51, 59 FR 29384, June 7, 1994, as amended by Amdt. 195-53, 59
FR 35471, July 12, 1994; Amdt. 195-51B, 61 FR 43027, Aug. 20, 1996;
Amdt. 195-58, 62 FR 54592, Oct. 21, 1997; Amdt. 195-63, 63 FR 37506,
July 13, 1998; Amdt. 195-65, 63 FR 59479, Nov. 4, 1998]
Sec. 195.303 Risk-based alternative to pressure testing older hazardous
liquid and carbon dioxide pipelines.
(a) An operator may elect to follow a program for testing a pipeline
on risk-based criteria as an alternative to the pressure testing in
Sec. 195.302(b)(1)(i)-(iii) and Sec. 195.302(b)(2)(i) of this subpart.
Appendix B provides guidance on how this program will work. An operator
electing such a program shall assign a risk classification to each
pipeline segment according to the indicators described in paragraph (b)
of this section as follows:
(1) Risk Classification A if the location indicator is ranked as low
or medium risk, the product and volume indicators are ranked as low
risk, and the probability of failure indicator is ranked as low risk;
[[Page 164]]
(2) Risk Classification C if the location indicator is ranked as
high risk; or
(3) Risk Classification B.
(b) An operator shall evaluate each pipeline segment in the program
according to the following indicators of risk:
(1) The location indicator is--
(i) High risk if an area is non-rural or environmentally sensitive
\1\; or
(ii) Medium risk; or
(iii) Low risk if an area is not high or medium risk.
(2) The product indicator is <SUP>1</SUP>
---------------------------------------------------------------------------
\1\ (See Appendix B, Table C).
---------------------------------------------------------------------------
(i) High risk if the product transported is highly toxic or is both
highly volatile and flammable;
(ii) Medium risk if the product transported is flammable with a
flashpoint of less than 100 deg. F, but not highly volatile; or
(iii) Low risk if the product transported is not high or medium
risk.
(3) The volume indicator is--
(i) High risk if the line is at least 18 inches in nominal diameter;
(ii) Medium risk if the line is at least 10 inches, but less than 18
inches, in nominal diameter; or
(iii) Low risk if the line is not high or medium risk.
(4) The probability of failure indicator is--
(i) High risk if the segment has experienced more than three
failures in the last 10 years due to time-dependent defects (e.g.,
corrosion, gouges, or problems developed during manufacture,
construction or operation, etc.); or
(ii) Low risk if the segment has experienced three failures or less
in the last 10 years due to time-dependent defects.
(c) The program under paragraph (a) of this section shall provide
for pressure testing for a segment constructed of electric resistance-
welded (ERW) pipe and lapwelded pipe manufactured prior to 1970
susceptible to longitudinal seam failures as determined through
paragraph (d) of this section. The timing of such pressure test may be
determined based on risk classifications discussed under paragraph (b)
of this section. For other segments, the program may provide for use of
a magnetic flux leakage or ultrasonic internal inspection survey as an
alternative to pressure testing and, in the case of such segments in
Risk Classification A, may provide for no additional measures under this
subpart.
(d) All pre-1970 ERW pipe and lapwelded pipe is deemed susceptible
to longitudinal seam failures unless an engineering analysis shows
otherwise. In conducting an engineering analysis an operator must
consider the seam-related leak history of the pipe and pipe
manufacturing information as available, which may include the pipe
steel's mechanical properties, including fracture toughness; the
manufacturing process and controls related to seam properties, including
whether the ERW process was high-frequency or low-frequency, whether the
weld seam was heat treated, whether the seam was inspected, the test
pressure and duration during mill hydrotest; the quality control of the
steel-making process; and other factors pertinent to seam properties and
quality.
(e) Pressure testing done under this section must be conducted in
accordance with this subpart. Except for segments in Risk Classification
B which are not constructed with pre-1970 ERW pipe, water must be the
test medium.
(f) An operator electing to follow a program under paragraph (a)
must develop plans that include the method of testing and a schedule for
the testing by December 7, 1998. The compliance deadlines for completion
of testing are as shown in the table below:
Sec. 195.303--Test Deadlines
------------------------------------------------------------------------
Risk
Pipeline Segment classification Test deadline
------------------------------------------------------------------------
Pre-1970 Pipe susceptible to C or B............ 12/7/2000
longitudinal seam failures A................. 12/7/2002
[defined in Sec. 195.303(c) &
(d)].
All Other Pipeline Segments..... C................. 12/7/2002
B................. 12/7//2004
A................. Additional testing
not required
------------------------------------------------------------------------
(g) An operator must review the risk classifications for those
pipeline segments which have not yet been tested under paragraph (a) of
this section or otherwise inspected under paragraph (c) of this section
at intervals not to
[[Page 165]]
exceed 15 months. If the risk classification of an untested or
uninspected segment changes, an operator must take appropriate action
within two years, or establish the maximum operating pressure under
Sec. 195.406(a)(5).
(h) An operator must maintain records establishing compliance with
this section, including records verifying the risk classifications, the
plans and schedule for testing, the conduct of the testing, and the
review of the risk classifications.
(i) An operator may discontinue a program under this section only
after written notification to the Administrator and approval, if needed,
of a schedule for pressure testing.
[Amdt. 195-65, 63 FR 59480, Nov. 4, 1998]
Sec. 195.304 Test pressure.
The test pressure for each pressure test conducted under this
subpart must be maintained throughout the part of the system being
tested for at least 4 continuous hours at a pressure equal to 125
percent, or more, of the maximum operating pressure and, in the case of
a pipeline that is not visually inspected for leakage during the test,
for at least an additional 4 continuous hours at a pressure equal to 110
percent, or more, of the maximum operating pressure.
[Amdt. 195-51, 59 FR 29384, June 7, 1994. Redesignated by Amdt. 195-65,
63 FR 59480, Nov. 4, 1998]
Sec. 195.305 Testing of components.
(a) Each pressure test under Sec. 195.302 must test all pipe and
attached fittings, including components, unless otherwise permitted by
paragraph (b) of this section.
(b) A component, other than pipe, that is the only item being
replaced or added to the pipeline system need not be hydrostatically
tested under paragraph (a) of this section if the manufacturer certifies
that either--
(1) The component was hydrostatically tested at the factory; or
(2) The component was manufactured under a quality control system
that ensures each component is at least equal in strength to a prototype
that was hydrostatically tested at the factory.
[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-51,
59 FR 29385, June 7, 1994; Amdt. 195-52, 59 FR 33397, June 28, 1994.
Redesignated by Amdt. 195-65, 63 FR 59480, Nov. 4, 1998]
Sec. 195.306 Test medium.
(a) Except as provided in paragraphs (b), (c), and (d) of this
section, water must be used as the test medium.
(b) Except for offshore pipelines, liquid petroleum that does not
vaporize rapidly may be used as the test medium if--
(1) The entire pipeline section under test is outside of cities and
other populated areas;
(2) Each building within 300 feet (91 meters) of the test section is
unoccupied while the test pressure is equal to or greater than a
pressure which produces a hoop stress of 50 percent of specified minimum
yield strength;
(3) The test section is kept under surveillance by regular patrols
during the test; and
(4) Continuous communication is maintained along entire test
section.
(c) Carbon dioxide pipelines may use inert gas or carbon dioxide as
the test medium if--
(1) The entire pipeline section under test is outside of cities and
other populated areas;
(2) Each building within 300 feet (91 meters) of the test section is
unoccupied while the test pressure is equal to or greater than a
pressure that produces a hoop stress of 50 percent of specified minimum
yield strength;
(3) The maximum hoop stress during the test does not exceed 80
percent of specified minimum yield strength;
(4) Continuous communication is maintained along entire test
section; and
(5) The pipe involved is new pipe having a longitudinal joint factor
of 1.00.
(d) Air or inert gas may be used as the test medium in low-stress
pipelines.
[Amdt. 195-22, 46 FR 38360, July 27, 1991, as amended by Amdt. 195-45,
56 FR 26926, June 12, 1991; Amdt. 195-51, 59 FR 29385, June 7, 1994;
Amdt. 195-53, 59 FR 35471, July 12, 1994; Amdt. 195-51A, 59 FR 41260,
Aug. 11, 1994; Amdt. 195-63, 63 FR 37506, July 13, 1998]
[[Page 166]]
Sec. 195.307 Pressure testing aboveground breakout tanks.
(a) For aboveground breakout tanks built to API Specification 12F
and first placed in service after October 2, 2000, pneumatic testing
must be in accordance with section 5.3 of API Specification 12F.
(b) For aboveground breakout tanks built to API Standard 620 and
first placed in service after October 2, 2000, hydrostatic and pneumatic
testing must be in accordance with section 5.18 of API Standard 620.
(c) For aboveground breakout tanks built to API Standard 650 and
first placed in service after October 2, 2000, hydrostatic and pneumatic
testing must be in accordance with section 5.3 of API Standard 650.
(d) For aboveground atmospheric pressure breakout tanks constructed
of carbon and low alloy steel, welded or riveted, and non-refrigerated
and tanks built to API Standard 650 or its predecessor Standard 12C that
are returned to service after October 2, 2000, the necessity for the
hydrostatic testing of repair, alteration, and reconstruction is covered
in section 10.3 of API Standard 653.
(e) For aboveground breakout tanks built to API Standard 2510 and
first placed in service after October 2, 2000, pressure testing must be
in accordance with ASME Boiler and Pressure Vessel Code, Section VIII,
Division 1 or 2.
[Amdt. 195-66, 64 FR 15936, Apr. 2, 1999]
Sec. 195.308 Testing of tie-ins.
Pipe associated with tie-ins must be pressure tested, either with
the section to be tied in or separately.
[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by 195-51, 59 FR
29385, June 7, 1994]
Sec. 195.310 Records.
(a) A record must be made of each pressure test required by this
subpart, and the record of the latest test must be retained as long as
the facility tested is in use.
(b) The record required by paragraph (a) of this section must
include:
(1) The pressure recording charts;
(2) Test instrument calibration data;
(3) The name of the operator, the name of the person responsible for
making the test, and the name of the test company used, if any;
(4) The date and time of the test;
(5) The minimum test pressure;
(6) The test medium;
(7) A description of the facility tested and the test apparatus;
(8) An explanation of any pressure discontinuities, including test
failures, that appear on the pressure recording charts; and
(9) Where elevation differences in the section under test exceed 100
feet (30 meters), a profile of the pipeline that shows the elevation and
test sites over the entire length of the test section.
[Amdt. 195-34, 50 FR 34474, Aug. 26, 1985, as amended by Amdt. 195-51,
59 FR 29385, June 7, 1994; Amdt. 195-63, 63 FR 37506, July 13, 1998]
Subpart F--Operation and Maintenance
Sec. 195.400 Scope.
This subpart prescribes minimum requirements for operating and
maintaining pipeline systems constructed with steel pipe.
Sec. 195.401 General requirements.
(a) No operator may operate or maintain its pipeline systems at a
level of safety lower than that required by this subpart and the
procedures it is required to establish under Sec. 195.402(a) of this
subpart.
(b) Whenever an operator discovers any condition that could
adversely affect the safe operation of its pipeline system, it shall
correct it within a reasonable time. However, if the condition is of
such a nature that it presents an immediate hazard to persons or
property, the operator may not operate the affected part of the system
until it has corrected the unsafe condition.
(c) Except as provided in Sec. 195.5, no operator may operate any
part of any of the following pipelines unless it was designed and
constructed as required by this part:
(1) An interstate pipeline, other than a low-stress pipeline, on
which construction was begun after March 31, 1970, that transports
hazardous liquid.
(2) An interstate offshore gathering line, other than a low-stress
pipeline, on which construction was begun after
[[Page 167]]
July 31, 1977, that transports hazardous liquid.
(3) An intrastate pipeline, other than a low-stress pipeline, on
which construction was begun after October 20, 1985, that transports
hazardous liquid.
(4) A pipeline on which construction was begun after July 11, 1991,
that transports carbon dioxide.
(5) A low-stress pipeline on which construction was begun after
August 10, 1994.
[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-33,
50 FR 15899, Apr. 23, 1985; Amdt. 195-33A, 50 FR 39008, Sept. 26, 1985;
Amdt. 195-36, 51 FR 15008, Apr. 22, 1986; Amdt. 195-45, 56 FR 26926,
June 12, 1991; Amdt. 195-53, 59 FR 35471, July 12, 1994]
Sec. 195.402 Procedural manual for operations, maintenance, and
emergencies.
(a) General. Each operator shall prepare and follow for each
pipeline system a manual of written procedures for conducting normal
operations and maintenance activities and handling abnormal operations
and emergencies. This manual shall be reviewed at intervals not
exceeding 15 months, but at least once each calendar year, and
appropriate changes made as necessary to insure that the manual is
effective. This manual shall be prepared before initial operations of a
pipeline system commence, and appropriate parts shall be kept at
locations where operations and maintenance activities are conducted.
(b) 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.
(c) Maintenance and normal operations. The manual required by
paragraph (a) of this section must include procedures for the following
to provide safety during maintenance and normal operations:
(1) Making construction records, maps, and operating history
available as necessary for safe operation and maintenance.
(2) Gathering of data needed for reporting accidents under subpart B
of this part in a timely and effective manner.
(3) Operating, maintaining, and repairing the pipeline system in
accordance with each of the requirements of this subpart.
(4) Determining which pipeline facilities are located in areas that
would require an immediate response by the operator to prevent hazards
to the public if the facilities failed or malfunctioned.
(5) Analyzing pipeline accidents to determine their causes.
(6) Minimizing the potential for hazards identified under paragraph
(c)(4) of this section and the possibility of recurrence of accidents
analyzed under paragraph (c)(5) of this section.
(7) Starting up and shutting down any part of the pipeline system in
a manner designed to assure operation within the limits prescribed by
Sec. 195.406, consider the hazardous liquid or carbon dioxide in
transportation, variations in altitude along the pipeline, and pressure
monitoring and control devices.
(8) In the case of a pipeline that is not equipped to fail safe,
monitoring from an attended location pipeline pressure during startup
until steady state pressure and flow conditions are reached and during
shut-in to assure operation within limits prescribed by Sec. 195.406.
(9) In the case of facilities not equipped to fail safe that are
identified under paragraph 195.402(c)(4) or that control receipt and
delivery of the hazardous liquid or carbon dioxide, detecting abnormal
operating conditions by monitoring pressure, temperature, flow or other
appropriate operational data and transmitting this data to an attended
location.
(10) Abandoning pipeline facilities, including safe disconnection
from an operating pipeline system, purging of combustibles, and sealing
abandoned facilities left in place to minimize safety and environmental
hazards.
(11) Minimizing the likelihood of accidental ignition of vapors in
areas near facilities identified under paragraph (c)(4) of this section
where the
[[Page 168]]
potential exists for the presence of flammable liquids or gases.
(12) Establishing and maintaining liaison with fire, police, and
other appropriate public officials to learn the responsibility and
resources of each government organization that may respond to a
hazardous liquid or carbon dioxide pipeline emergency and acquaint the
officials with the operator's ability in respondinq to a hazardous
liquid or carbon dioxide pipeline emergency and means of communication.
(13) Periodically reviewing the work done by operator personnel to
determine the effectiveness of the procedures used in normal operation
and maintenance and taking corrective action where deficiencies are
found.
(14) Taking adequate precautions in excavated trenches to protect
personnel from the hazards of unsafe accumulations of vapor or gas, and
making available when needed at the excavation, emergency rescue
equipment, including a breathing apparatus and, a rescue harness and
line.
(d) Abnormal operation. The manual required by paragraph (a) of this
section must include procedures for the following to provide safety when
operating design limits have been exceeded:
(1) Responding to, investigating, and correcting the cause of:
(i) Unintended closure of valves or shutdowns;
(ii) Increase or decrease in pressure or flow rate outside normal
operating limits;
(iii) Loss of communications;
(iv) Operation of any safety device;
(v) Any other malfunction of a component, deviation from normal
operation, or personnel error which could cause a hazard to persons or
property.
(2) Checking variations from normal operation after abnormal
operation has ended at sufficient critical locations in the system to
determine continued integrity and safe operation.
(3) Correcting variations from normal operation of pressure and flow
equipment and controls.
(4) Notifying responsible operator personnel when notice of an
abnormal operation is received.
(5) Periodically reviewing the response of operator personnel to
determine the effectiveness of the procedures controlling abnormal
operation and taking corrective action where deficiencies are found.
(e) Emergencies. The manual required by paragraph (a) of this
section must include procedures for the following to provide safety when
an emergency condition occurs:
(1) Receiving, identifying, and classifying notices of events which
need immediate response by the operator or notice to fire, police, or
other appropriate public officials and communicating this information to
appropriate operator personnel for corrective action.
(2) Prompt and effective response to a notice of each type
emergency, including fire or explosion occurring near or directly
involving a pipeline facility, accidental release of hazardous liquid or
carbon dioxide from a pipeline facility, operational failure causing a
hazardous condition, and natural disaster affecting pipeline facilities.
(3) Having personnel, equipment, instruments, tools, and material
available as needed at the scene of an emergency.
(4) Taking necessary action, such as emergency shutdown or pressure
reduction, to minimize the volume of hazardous liquid or carbon dioxide
that is released from any section of a pipeline system in the event of a
failure.
(5) Control of released hazardous liquid or carbon dioxide at an
accident scene to minimize the hazards, including possible intentional
ignition in the cases of flammable highly volatile liquid.
(6) Minimization of public exposure to injury and probability of
accidental ignition by assisting with evacuation of residents and
assisting with halting traffic on roads and railroads in the affected
area, or taking other appropriate action.
(7) Notifying fire, police, and other appropriate public officials
of hazardous liquid or carbon dioxide pipeline emergencies and
coordinating with them preplanned and actual responses during an
emergency, including additional precautions necessary for an emergency
involving a pipeline system transporting a highly volatile liquid.
(8) In the case of failure of a pipeline system transporting a
highly volatile
[[Page 169]]
liquid, use of appropriate instruments to assess the extent and coverage
of the vapor cloud and determine the hazardous areas.
(9) Providing for a post accident review of employee activities to
determine whether the procedures were effective in each emergency and
taking corrective action where deficiencies are found.
(f) 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 Sec. 195.55.
[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982,
as amended by Amdt. 195-24, 47 FR 46852, Oct. 21, 1982; Amdt. 195-39, 53
FR 24951, July 1, 1988; Amdt. 195-45, 56 FR 26926, June 12, 1991; Amdt.
195-46, 56 FR 31090, July 9, 1991; Amdt. 195-49, 59 FR 6585, Feb. 11,
1994; Amdt. 195-55, 61 FR 18518, Apr. 26, 1996]
Sec. 195.403 Training.
(a) Each operator shall establish and conduct a continuing training
program to instruct operating and maintenance personnel to:
(1) Carry out the operating and maintenance, and emergency
procedures established under Sec. 195.402 that relate to their
assignments;
(2) Know the characteristics and hazards of the hazardous liquids or
carbon dioxide transported, including, in the case of flammable HVL,
flammability of mixtures with air, odorless vapors, and water reactions;
(3) Recognize conditions that are likely to cause emergencies,
predict the consequences of facility malfunctions or failures and
hazardous liquid or carbon dioxide spills, and to take appropriate
corrective action;
(4) Take steps necessary to control any accidental release of
hazardous liquid or carbon dioxide and to minimize the potential for
fire, explosion, toxicity, or environmental damage;
(5) Learn the proper use of firefighting procedures and equipment,
fire suits, and breathing apparatus by utilizing, where feasible, a
simulated pipeline emergency condition; and
(6) In the case of maintenance personnel, to safely repair
facilities using appropriate special precautions, such as isolation and
purging, when highly volatile liquids are involved.
(b) At intervals not exceeding 15 months, but at least once each
calendar year, each operator shall:
(1) Review with personnel their performance in meeting the
objectives of the training program set forth in paragraph (a) of this
section; and
(2) Make appropriate changes to the training program as necessary to
insure that it is effective.
(c) Each operator shall require and verify that its supervisors
maintain a thorough knowledge of that portion of the procedures
established under Sec. 195.402 for which they are responsible to insure
compliance.
[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982,
as amended by Amdt. 195-24, 47 FR 46852, Oct. 21, 1982; Amdt. 195-45, 56
FR 26926, June 12, 1991]
Effective Date Note: By Amdt. 195-67, 64 FR 46866, Aug. 27, 1999,
Sec. 195.403 was revised, effective Oct. 28, 2002. For the convenience
of the user, the revised text follows:
Sec. 195.403 Emergency response training.
(a) Each operator shall establish and conduct a continuing training
program to instruct emergency response personnel to:
(1) Carry out the emergency procedures established under 195.402
that relate to their assignments;
(2) Know the characteristics and hazards of the hazardous liquids or
carbon dioxide transported, including, in case of flammable HVL,
flammability of mixtures with air, odorless vapors, and water reactions;
(3) Recognize conditions that are likely to cause emergencies,
predict the consequences of facility malfunctions or failures and
hazardous liquids or carbon dioxide spills, and take appropriate
corrective action;
(4) Take steps necessary to control any accidental release of
hazardous liquid or carbon dioxide and to minimize the potential for
fire, explosion, toxicity, or environmental damage; and
(5) Learn the proper use of firefighting procedures and equipment,
fire suits, and breathing apparatus by utilizing, where feasible, a
simulated pipeline emergency condition.
(b) At the intervals not exceeding 15 months, but at least once each
calendar year, each operator shall:
[[Page 170]]
(1) Review with personnel their performance in meeting the
objectives of the emergency response training program set forth in
paragraph (a) of this section; and
(2) Make appropriate changes to the emergency response training
program as necessary to ensure that it is effective.
(c) Each operator shall require and verify that its supervisors
maintain a thorough knowledge of that portion of the emergency response
procedures established under 195.402 for which they are responsible to
ensure compliance.
[Amdt. 195-67, 64 FR 46866, Aug. 27, 1999]
Sec. 195.404 Maps and records.
(a) Each operator shall maintain current maps and records of its
pipeline systems that include at least the following information:
(1) Location and identification of the following pipeline
facilities:
(i) Breakout tanks;
(ii) Pump stations;
(iii) Scraper and sphere facilities;
(iv) Pipeline valves;
(v) Cathodically protected facilities;
(vi) Facilities to which Sec. 195.402(c)(9) applies;
(vii) Rights-of-way; and
(viii) Safety devices to which Sec. 195.428 applies.
(2) All crossings of public roads, railroads, rivers, buried
utilities, and foreign pipelines.
(3) The maximum operating pressure of each pipeline.
(4) The diameter, grade, type, and nominal wall thickness of all
pipe.
(b) Each operator shall maintain for at least 3 years daily
operating records that indicate--
(1) The discharge pressure at each pump station; and
(2) Any emergency or abnormal operation to which the procedures
under Sec. 195.402 apply.
(c) Each operator shall maintain the following records for the
periods specified:
(1) The date, location, and description of each repair made to pipe
shall be maintained for the useful life of the pipe.
(2) The date, location, and description of each repair made to parts
of the pipeline system other than pipe shall be maintained for at least
1 year.
(3) A record of each inspection and test required by this subpart
shall be maintained for at least 2 years or until the next inspection or
test is performed, whichever is longer.
[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-34,
50 FR 34474, Aug. 26, 1985]
Sec. 195.405 Protection against ignitions and safe access/egress
involving floating roofs.
(a) After October 2, 2000, protection provided against ignitions
arising out of static electricity, lightning, and stray currents during
operation and maintenance activities involving aboveground breakout
tanks must be in accordance with API Recommended Practice 2003, unless
the operator notes in the procedural manual (Sec. 195.402(c)) why
compliance with all or certain provisions of API Recommended Practice
2003 is not necessary for the safety of a particular breakout tank.
(b) The hazards associated with access/egress onto floating roofs of
in-service aboveground breakout tanks to perform inspection, service,
maintenance or repair activities (other than specified general
considerations, specified routine tasks or entering tanks removed from
service for cleaning) are addressed in API Publication 2026. After
October 2, 2000, the operator must review and consider the potentially
hazardous conditions, safety practices and procedures in API Publication
2026 for inclusion in the procedure manual (Sec. 195.402(c)).
[Amdt. 195-66, 64 FR 15936, Apr. 2, 1999]
Sec. 195.406 Maximum operating pressure.
(a) Except for surge pressures and other variations from normal
operations, no operator may operate a pipeline at a pressure that
exceeds any of the following:
(1) The internal design pressure of the pipe determined in
accordance with Sec. 195.106. However, for steel pipe in pipelines being
converted under Sec. 195.5, if one or more factors of the design formula
(Sec. 195.106) are unknown, one of the following pressures is to be used
as design pressure:
(i) Eighty percent of the first test pressure that produces yield
under section N5.0 of appendix N of ASME B31.8,
[[Page 171]]
reduced by the appropriate factors in Secs. 195.106 (a) and (e); or
(ii) If the pipe is 12 \3/4\ inch (324 mm) or less outside diameter
and is not tested to yield under this paragraph, 200 p.s.i. (1379 kPa)
gage.
(2) The design pressure of any other component of the pipeline.
(3) Eighty percent of the test pressure for any part of the pipeline
which has been pressure tested under subpart E of this part.
(4) Eighty percent of the factory test pressure or of the prototype
test pressure for any individually installed component which is excepted
from testing under Sec. 195.305.
(5) For pipelines under Secs. 195.302(b)(1) and (b)(2)(i) that have
not been pressure tested under subpart E of this part, 80 percent of the
test pressure or highest operating pressure to which the pipeline was
subjected for 4 or more continuous hours that can be demonstrated by
recording charts or logs made at the time the test or operations were
conducted.
(b) No operator may permit the pressure in a pipeline during surges
or other variations from normal operations to exceed 110 percent of the
operating pressure limit established under paragraph (a) of this
section. Each operator must provide adequate controls and protective
equipment to control the pressure within this limit.
[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-33,
50 FR 15899, Apr. 23, 1985; 50 FR 38660, Sept. 24, 1985; Amdt. 195-51,
59 FR 29385, June 7, 1994; Amdt. 195-52, 59 FR 33397, June 28, 1994;
Amdt. 195-63, 63 FR 37506, July 13, 1998; Amdt. 195-65, 63 FR 59480,
Nov. 4, 1998]
Sec. 195.408 Communications.
(a) Each operator must have a communication system to provide for
the transmission of information needed for the safe operation of its
pipeline system.
(b) The communication system required by paragraph (a) of this
section must, as a minimum, include means for:
(1) Monitoring operational data as required by Sec. 195.402(c)(9);
(2) Receiving notices from operator personnel, the public, and
public authorities of abnormal or emergency conditions and sending this
information to appropriate personnel or government agencies for
corrective action;
(3) Conducting two-way vocal communication between a control center
and the scene of abnormal operations and emergencies; and
(4) Providing communication with fire, police, and other appropriate
public officials during emergency conditions, including a natural
disaster.
Sec. 195.410 Line markers.
(a) Except as provided in paragraph (b) of this section, each
operator shall place and maintain line markers over each buried pipeline
in accordance with the following:
(1) Markers must be located at each public road crossing, at each
railroad crossing, and in sufficient number along the remainder of each
buried line so that its location is accurately known.
(2) The marker must state at least the following on a background of
sharply contrasting color:
(i) The word ``Warning,'' ``Caution,'' or ``Danger'' followed by the
words ``Petroleum (or the name of the hazardous liquid transported)
Pipeline'', or ``Carbon Dioxide Pipeline,'' all of which, except for
markers in heavily developed urban areas, must be in letters at least 1
inch (25 millimeters) high with an approximate stroke of \1/4\ inch (6.4
millimeters).
(ii) The name of the operator and a telephone number (including area
code) where the operator can be reached at all times.
(b) Line markers are not required for buried pipelines located--
(1) Offshore or at crossings of or under waterways and other bodies
of water; or
(2) In heavily developed urban areas such as downtown business
centers where--
(i) The placement of markers is impractical and would not serve the
purpose for which markers are intended; and
(ii) The local government maintains current substructure records.
(c) Each operator shall provide line marking at locations where the
line is
[[Page 172]]
above ground in areas that are accessible to the public.
[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-27,
48 FR 25208, June 6, 1983; Amdt. 195-54, 60 FR 14650, Mar. 20, 1995;
Amdt. 195-63, 63 FR 37506, July 13, 1998]
Sec. 195.412 Inspection of rights-of-way and crossings under navigable
waters.
(a) Each operator shall, at intervals not exceeding 3 weeks, but at
least 26 times each calendar year, inspect the surface conditions on or
adjacent to each pipeline right-of-way. Methods of inspection include
walking, driving, flying or other appropriate means of traversing the
right-of-way.
(b) Except for offshore pipelines, each operator shall, at intervals
not exceeding 5 years, inspect each crossing under a navigable waterway
to determine the condition of the crossing.
[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-24,
47 FR 46852, Oct. 21, 1982; Amdt. 195-52, 59 FR 33397, June 28, 1994]
Sec. 195.413 Underwater inspection and reburial of pipelines in the
Gulf of Mexico and its inlets.
(a) Except for gathering lines of 4 \1/2\ inches (114 mm) nominal
outside diameter or smaller, each operator shall, in accordance with
this section, conduct an underwater inspection of its pipelines in the
Gulf of Mexico and its inlets. The inspection must be conducted after
October 3, 1989 and before November 16, 1992.
(b) If, as a result of an inspection under paragraph (a) of this
section, or upon notification by any person, an operator discovers that
a pipeline it operates is exposed on the seabed or constitutes a hazard
to navigation, the operator shall--
(1) Promptly, but not later than 24 hours after discovery, notify
the National Response Center, telephone: 1-800-424-8802 of the location,
and, if available, the geographic coordinates of that pipeline;
(2) Promptly, but not later than 7 days after discovery, mark the
location of the pipeline in accordance with 33 CFR part 64 at the ends
of the pipeline segment and at intervals of not over 500 yards (457
meters) long, except that a pipeline segment less than 200 yards (183
meters) long need only be marked at the center; and
(3) Within 6 months after discovery, or not later than November 1 of
the following year if the 6 month period is after November 1 of the year
that the discovery is made, place the pipeline so that the top of the
pipe is 36 inches (914 millimeters) below the seabed for normal
excavation or 18 inches (457 millimeters) for rock excavation.
[Amdt. 195-47, 56 FR 63771, Dec. 5, 1991, as amended by Amdt. 195-52, 59
FR 33396, June 28, 1994; Amdt. 195-63, 63 FR 37506, July 13, 1998]
Sec. 195.414 Cathodic protection.
(a) No operator may operate a hazardous liquid interstate pipeline
after March 31, 1973, a hazardous liquid intrastate pipeline after
October 19, 1988, or a carbon dioxide pipeline after July 12, 1993 that
has an effective external surface coating material, unless that pipeline
is cathodically protected. This paragraph does not apply to breakout
tank areas and buried pumping station piping. For the purposes of this
subpart, a pipeline does not have an effective external coating, and
shall be considered bare, if its cathodic pr