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Pt. 154
[(Phase III oil removal actions) or (hazardous substance removal actions)],
and reasonable costs related thereto
are proper for payment from the Pollution Fund. The following actions were
not authorized by me and are not subject to reimbursement from the Pollution Fund:
llllllllllllllllllllllll
(OSC Signature)
llllllllllllllllllllllll
(Incident title)
llllllllllllllllllllllll
(Pollution incident project number)
[CGD 84–067, 51 FR 17967, May 16, 1986]
PART 154—FACILITIES TRANSFERRING OIL OR HAZARDOUS MATERIAL IN BULK
Subpart A—General
Sec.
154.100 Applicability.
154.105 Definitions.
154.106 Incorporation by reference: Where
can I get a copy of the publications incorporated by reference in this part?
154.107 Alternatives.
154.108 Exemptions.
154.110 Letter of intent.
154.120 Facility examinations.
154.T150 Temporary suspension of requirements to permit support of deepwater horizon spill response.
Subpart B—Operations Manual
154.300 Operations
154.310 Operations
154.320 Operations
154.325 Operations
examination.
manual: General.
manual: Contents.
manual: Amendment.
manual: Procedures for
Subpart C—Equipment Requirements
154.500 Hose assemblies.
154.510 Loading arms.
154.520 Closure devices.
154.525 Monitoring devices.
154.530 Small discharge containment.
154.540 Discharge removal.
154.545 Discharge containment equipment.
154.550 Emergency shutdown.
154.560 Communications.
154.570 Lighting.
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Subpart D—Facility Operations
154.700 General.
154.710 Persons in charge: Designation and
qualification.
154.730 Persons in charge: Evidence of designation.
154.735
154.740
154.750
Safety requirements.
Records.
Compliance with operations manual.
Subpart E—Vapor Control Systems
154.800 Applicability.
154.802 Definitions.
154.804 Review, certification, and initial inspection.
154.806 Application for acceptance as a certifying entity.
154.808 Vapor control system, general.
154.810 Vapor line connections.
154.812 Facility requirements for vessel liquid overfill protection.
154.814 Facility requirements for vessel
vapor overpressure and vacuum protection.
154.820 Fire, explosion, and detonation protection.
154.822 Detonation arresters, flame arresters, and flame screens.
154.824 Inerting, enriching, and diluting systems.
154.826 Vapor compressors and blowers.
154.828 Vapor recovery and vapor destruction units.
154.840 Personnel training.
154.850 Operational requirements.
Subpart F—Response Plans for Oil Facilities
154.1010 Purpose.
154.1015 Applicability.
154.1016 Facility classification by COTP.
154.1017 Response plan submission requirements.
154.1020 Definitions.
154.1025 Operating restrictions and interim
operating authorization.
154.1026 Qualified individual and alternate
qualified individual.
154.1028 Methods of ensuring the availability of response resources by contract
or other approved means.
154.1029 Worst case discharge.
154.1030 General response plan contents.
154.1035 Specific requirements for facilities
that could reasonably be expected to
cause significant and substantial harm
to the environment.
154.1040 Specific requirements for facilities
that could reasonably be expected to
cause substantial harm to the environment.
154.1041 Specific response information to be
maintained on mobile MTR facilities.
154.1045 Response plan development and
evaluation criteria for facilities that
handle, store, or transport Group I
through Group IV petroleum oils.
154.1047 Response plan development and
evaluation criteria for facilities that
handle, store, or transport Group V petroleum oils.
154.1050 Training.
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§ 154.100
33 CFR Ch. I (7–1–10 Edition)
154.1055 Exercises.
154.1057 Inspection and maintenance of response resources.
154.1060 Submission and approval procedures.
154.1065 Plan review and revision procedures.
154.1070 Deficiencies.
154.1075 Appeal process.
Subpart G—Additional Response Plan Requirements for a Trans-Alaska Pipeline
Authorization Act (TAPAA) Facility Operating in Prince William Sound, Alaska
154.1110 Purpose and applicability.
154.1115 Definitions.
154.1120 Operating restrictions and interim
operating authorization.
154.1125 Additional response plan requirements.
154.1130 Requirements for prepositioned response equipment.
154.1135 Response plan development and
evaluation criteria.
154.1140 TAPAA facility contracting with a
vessel.
Subpart H—Response Plans for Animal Fats
and Vegetable Oils Facilities
154.1210 Purpose and applicability.
154.1216 Facility classification.
154.1220 Response plan submission requirements.
154.1225 Specific response plan development
and evaluation criteria and other requirements for fixed facilities that handle, store, or transport animal fats or
vegetable oils.
154.1228 Methods of ensuring the availability of response resources by contract
or other approved means.
154.1240 Specific requirements for animal
fats and vegetable oils facilities that
could reasonably be expected to cause
substantial harm to the environment.
Subpart I—Response Plans for Other NonPetroleum Oil Facilities
154.1310 Purpose and applicability.
154.1320 Response plan submission requirements.
154.1325 Response plan development and
evaluation criteria for facilities that
handle, store, or transport other non-petroleum oils.
APPENDIX A TO PART 154—GUIDELINES FOR
DETONATION FLAME ARRESTERS
APPENDIX B TO PART 154—STANDARD SPECIFICATION FOR TANK VENT FLAME ARRESTerowe on DSK5CLS3C1PROD with CFR
ERS
APPENDIX C TO PART 154—GUIDELINES FOR
DETERMINING AND EVALUATING REQUIRED
RESPONSE RESOURCES FOR FACILITY RESPONSE PLANS
APPENDIX D TO PART 154—TRAINING ELEMENTS FOR OIL SPILL RESPONSE PLANS
AUTHORITY: 33 U.S.C. 1231, 1321(j)(1)(C),
(j)(5), (j)(6), and (m)(2); sec. 2, E.O. 12777, 56
FR 54757; Department of Homeland Security
Delegation No. 0170.1. Subpart F is also
issued under 33 U.S.C. 2735.
Subpart A—General
§ 154.100 Applicability.
(a) This part applies to each facility
that is capable of transferring oil or
hazardous materials, in bulk, to or
from a vessel, where the vessel has a
total capacity, from a combination of
all bulk products carried, of 39.75 cubic
meters (250 barrels) or more. This part
does not apply to the facility when it is
in a caretaker status. This part does
not apply to any offshore facility operating under the jurisdiction of the Secretary of the Department of Interior.
(b) Upon written notice to the facility operator, the COTP may apply, as
necessary for the safety of the facility,
its personnel, or the public, all or portions of § 154.735 to each facility that is
capable of transferring oil or hazardous
material, in bulk, only to or from a
vessel with a capacity of less than 250
barrels. If the facility is in caretaker
status, the COTP may not apply the
provisions of § 154.735 to the facility if
its storage tanks and piping are gas
free.
(c) Upon a determination by the
COTP under § 154.1016 that an MTR facility, as defined in subpart F, could
reasonably be expected to cause substantial harm to the environment by
discharging oil into or on the navigable
waters, adjoining shorelines, or exclusive economic zone, subpart F of this
part is applicable to the facility.
(d) The following sections of this part
apply to mobile facilities:
(1) Section 154.105 Definitions.
(2) Section 154.107 Alternatives.
(3) Section 154.108 Exemptions.
(4) Section 154.110 Letter of Intent.
(5) Section 154.120 Facility examinations.
(6) Section 154.300 Operations Manual: General.
(7) Section 154.310 Operations Manual: Contents. Paragraphs (a)(2), (a)(3),
(a)(5) through (a)(7), (a)(9), (a)(12),
(a)(14),
(a)(16),
(a)(17)(ii)
through
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Coast Guard, DHS
§ 154.105
(a)(17)(iv), (a)(18), (a)(20) through (23),
(c) and (d).
(8) Section 154.320 Operations Manual: Amendment.
(9) Section 154.325 Operations Manual: Procedures for examination.
(10) Section 154.500 Hose assemblies.
Paragraphs (a), (b), (c), (d)(1) through
(3) and (e)(1) through (3).
(11) Section 154.520 Closure devices.
(12) Section 154.530 Small discharge
containment.
Paragraphs
(a)(1)
through (3) and (d).
(13) Section 154.545 Discharge containment equipment.
(14) Section 154.550 Emergency shutdown.
(15) Section 154.560 Communications.
(16) Section 154.570 Lighting. Paragraphs (c) and (d).
(17) Section 154.700 General.
(18) Section 154.710 Persons in charge:
Designation and qualification. Paragraphs (a) through (c), (d)(1) through
(3), (d)(7) and (e).
(19) Section 154.730 Persons in charge:
Evidence of designation.
(20) Section 154.735 Safety requirements. Paragraphs (d), (f), (g), (j)(1)
through (2), (k)(1) through (2), (m), (o)
through (q), (r)(1) through (3), (s) and
(v).
(21) Section 154.740 Records. Paragraphs (a) through (f) and (j).
(22) Section 154.750 Compliance with
Operations Manual.
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[CGD 86–034, 55 FR 36252, Sept. 4, 1990, as
amended by CGD 91–036, 58 FR 7352, Feb. 5,
1993; CGD 93–056, 61 FR 41457, Aug. 8, 1996]
§ 154.105 Definitions.
As used in this part:
Barrel means a quantity of liquid
equal to 42 U.S. gallons.
Boundary Line means any of the lines
described in 46 CFR part 7.
Captain of the Port (COTP) means the
U.S. Coast Guard officer commanding a
Captain of the Port Zone described in
part 3 of this chapter, or that person’s
authorized representative.
Caretaker status denotes a facility
where all piping, hoses, loading arms,
storage tanks, and related equipment
in the marine transfer area are completely free of oil or hazardous materials, where these components have
been certified as being gas free, where
piping, hoses, and loading arms termi-
nating near any body of water have
been blanked, and where the facility
operator has notified the COTP that
the facility will be in caretaker status.
Commandant means the Commandant
of the Coast Guard or an authorized
representative.
Contiguous Zone means the entire
zone established by the United States
under Article 24 of the Convention on
the Territorial Sea and the Contiguous
Zone, but not extending beyond 12
miles from the baseline from which the
breadth of the territorial sea is measured.
District Commander means the officer
of the Coast Guard designated by the
Commandant to command a Coast
Guard District, as described in part 3 of
this chapter or an authorized representative.
Facility means either an onshore or
offshore facility, except for an offshore
facility operating under the jurisdiction of the Secretary of the Department of Interior, and includes, but is
not limited to, structure, equipment,
and appurtenances thereto, used or capable of being used to transfer oil or
hazardous materials to or from a vessel
or public vessel. Also included are facilities that tank clean or strip and
any floating structure that is used to
support an integral part of the facility’s operation. A facility includes federal, state, municipal, and private facilities.
Facility operator means the person
who owns, operates, or is responsible
for the operation of the facility.
Hazardous material means a liquid
material or substance, other than oil
or liquefied gases, listed under 46 CFR
153.40 (a), (b), (c), or (e).
Marine transfer area means that part
of a waterfront facility handling oil or
hazardous materials in bulk between
the vessel, or where the vessel moors,
and the first manifold or shutoff valve
on the pipeline encountered after the
pipeline enters the secondary containment required under 40 CFR 112.7 or 49
CFR 195.264 inland of the terminal
manifold or loading arm, or, in the absence of secondary containment, to the
valve or manifold adjacent to the bulk
storage tank, including the entire pier
or wharf to which a vessel transferring
oil or hazardous materials is moored.
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§ 154.106
33 CFR Ch. I (7–1–10 Edition)
MARPOL 73/78 means the International Convention for the Prevention
of Pollution from Ships, 1973 (done at
London, November 2, 1973) as modified
by the Protocol of 1978 relating to the
International Convention for the Prevention of Pollution from Ships, 1973
(done at London, February 17, 1978).
Mobile facility means any facility that
can readily change location, such as a
tank truck or tank car, other than a
vessel or public vessel.
Monitoring device means any fixed or
portable sensing device used to monitor for a discharge of oil or hazardous
material onto the water, within or
around a facility, and designed to notify operating personnel of a discharge
of oil or hazardous material.
Officer in Charge, Marine Inspection
(OCMI) means the U.S. Coast Guard officer commanding a Marine Inspection
Zone described in part 3 of this chapter, or an authorized representative.
Offshore facility means any facility of
any kind located in, on, or under, any
of the navigable waters of the United
States, and any facility of any kind
which is subject to the jurisdiction of
the United States and is located in, on,
or under any other waters, other than
a vessel or a public vessel.
Oil means oil of any kind or in any
form, including but not limited to, petroleum, fuel oil, sludge, oil refuse, and
oil mixed with wastes other than
dredged spoil.
Onshore facility means any facility
(including, but not limited to, motor
vehicles and rolling stock) of any kind
located in, on, or under any land within the United States other than submerged land.
Person in charge means an individual
designated as a person in charge of
transfer operations under § 154.710 (for
facilities) or § 155.700 (for vessels) of
this chapter.
STCW means the International Convention on Standards of Training, Certification, and Watchkeeping for Seafarers, 1978.
Self-propelled tank vessel means a selfpropelled tank vessel other than a
tankship.
Tank barge means a non-self-propelled tank vessel.
Tankship means a self-propelled tank
vessel constructed or adapted pri-
marily to carry oil or hazardous material in bulk in the cargo spaces.
Tank vessel means a vessel that is
constructed or adapted to carry, or
that carries, oil or hazardous material
in bulk as cargo or cargo residue, and
that—
(a) Is a vessel of the United States;
(b) Operates on the navigable waters
of the United States; or
(c) Transfers oil or hazardous material in a port or place subject to the jurisdiction of the United States.
Transfer means any movement of oil
or hazardous material to, from, or
within a vessel by means of pumping,
gravitation, or displacement. A transfer is considered to begin when the person in charge on the transferring vessel
or facility and the person in charge on
the receiving facility or vessel first
meet to begin completing the declaration of inspection as required by
§ 156.150 of this chapter. A transfer is
considered to be complete when all the
connections for the transfer have been
uncoupled and secured with blanks or
other closure devices and both of the
persons in charge have completed the
declaration of inspection to include the
date and time the transfer was complete.
Vessel operator means a person who
owns, operates, or is responsible for the
operation of a vessel.
[CGD 75–124, 45 FR 7169, Jan. 31, 1980, as
amended by CGD 86–034, 55 FR 36252, Sept. 4,
1990; CGD 79–116, 60 FR 17141, Apr. 4, 1995;
CGD 93–056, 61 FR 41458, Aug. 8, 1996; 62 FR
3610, Jan. 24, 1997; CGD 79–116, 62 FR 25125,
May 8, 1997]
§ 154.106 Incorporation by reference:
Where can I get a copy of the publications incorporated by reference
in this part?
(a) Certain material is incorporated
by reference (IBR) into this part with
the approval of the Director of the Federal Register under 5 U.S.C. 552(a) and
1 CFR part 51. To enforce any edition
other than that specified in this section, the Coast Guard must publish notice of change in the FEDERAL REGISTER and the material must be available to the public. All approved material is available for inspection at the
National Archives and Records Administration (NARA). For information on
the availability of this material at
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Coast Guard, DHS
§ 154.106
NARA, call 202–741–6030 or go to http://
www.archives.gov/federallregister/
codeloflfederallregulations/
ibrllocations.html. Also, it is available
for inspection at the Coast Guard, Office of Port and Facility Activities,
Cargo and Facilities Division (CG–5332),
2100 2nd St., SW., Stop 7363, Washington, DC 20593–7363, 202–372–2234 and
is available from the sources indicated
in this section below.
(b) American Petroleum Institute
(API), 1220 L Street NW., Washington,
DC
20037,
202–682–8000,
http://
www.api.org/:
(1) API Standard 2000, Venting Atmospheric and Low-Pressure Storage
Tanks (Nonrefrigerated and Refrigerated), Third Edition, January 1982
(reaffirmed December 1987), IBR approved for § 154.814.
(2) API Recommended Practice 550,
Manual on Installation of Refinery Instruments and Control Systems, Part
II—Process Stream Analyzers, Section
1—Oxygen Analyzers, Fourth Edition,
February 1985, IBR approved for
§ 154.824.
(c) American National Standards Institute (ANSI), 11 West 42nd Street,
New York, NY 10036, 202–293–8020, http://
www.ansi.org:
(1) ANSI B16.5, Steel Pipe Flanges
and Flanged Fittings, 1988, IBR approved for §§ 154.500, 154.808, and 154.810.
(2) ANSI B16.24, Bronze Pipe Flanges
and Flange Fittings Class 150 and 300,
1979, IBR approved for §§ 154.500 and
154.808.
(3) ANSI B31.3, Chemical Plant and
Petroleum Refinery Piping, 1987 (including B31.3a–1988, B31.3b–1988, and
B31.3c–1989 addenda), IBR approved for
§§ 154.510 and 154.808.
(d) ASTM International, 100 Barr
Harbor Drive, West Conshohocken, PA
19428–2959,
610–832–9585,
http://
www.astm.org/:
(1) ASTM F631–93, Standard Guide for
Collecting Skimmer Performance Data
in Controlled Environments, IBR approved for Appendix C.
(2) ASTM F715–95, Standard Test
Methods for Coated Fabrics Used for
Oil Spill Control and Storage, IBR approved for Appendix C.
(3) ASTM F722–82 (1993), Standard
Specification for Welded Joints for
Shipboard Piping Systems, IBR approved for Appendix A and Appendix B.
(4) ASTM F1122–87 (1992), Standard
Specification for Quick Disconnect
Couplings, IBR approved for § 154.500.
(5) ASTM F1155–98, Standard Practice
for Selection and Application of Piping
System Materials, IBR approved for
Appendix A and Appendix B.
(6) ASTM F1413–07, Standard Guide
for Oil Spill Dispersant Application
Equipment: Boom and Nozzle Systems,
IBR approved for § 154.1045.
(7) ASTM F1737–07, Standard Guide
for Use of Oil Spill Dispersant Application Equipment During Spill Response:
Boom and Nozzle Systems, IBR approved for § 154.1045.
(8) ASTM F1779–08, Standard Practice
for Reporting Visual Observations of
Oil on Water, IBR approved for
§ 154.1045.
(e) International Electrotechnical
Commission (IEC), Bureau Central de
la Commission Electrotechnique Internationale, 1 rue de Varembe, Geneva,
Switzerland, +41–22–919–02–11, http://
www.iec.ch/:
(1) IEC 309–1—Plugs, Socket-Outlets
and Couplers for Industrial Purposes:
Part 1, General Requirements, 1979,
IBR approved for § 154.812.
(2) IEC 309–2—Plugs, Socket-Outlets
and Couplers for Industrial Purposes:
Part 2, Dimensional Interchangeability
Requirements for Pin and Contact-tube
Accessories, 1981, IBR approved for
§ 154.812.
(f) National Electrical Manufacturers
Association (NEMA), 1300 North 17th
Street, Suite 1752, Rosslyn, Virginia
22209, 703–841–3200, http://www.nema.org/:
(1) ANSI NEMA WD–6—Wiring Devices, Dimensional Requirements, 1988,
IBR approved for § 154.812.
(2) [Reserved]
(g) National Fire Protection Association (NFPA), 1 Batterymarch Park,
Quincy, MA 02269–9101, 617–770–3000,
http://www.nfpa.org/:
(1) NFPA 51B, Standard for Fire Prevention in Use of Cutting and Welding
Processes, 1994, IBR approved for
§ 154.735.
(2) NFPA 70, National Electrical
Code, 2008, IBR approved for § 154.812.
(h) Oil Companies International Marine Forum (OCIMF), 29 Queen Anne’s
Gate, London, SW1H 9BU, England,
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§ 154.107
33 CFR Ch. I (7–1–10 Edition)
+44–0–20–7654–1200, http://www.ocimf.com/
:
(1) International Safety Guide for Oil
Tankers and Terminals, Section 6.10,
Fourth Ed., 1996, IBR approved for
§ 154.810.
(2) International Safety Guide for Oil
Tankers and Terminals, Sections 9.1,
9.2, 9.3 and 9.5, Fourth Ed., 1996, IBR
approved for § 154.735.
[USCG–2001–8661, 74 FR 45022, Aug. 31, 2009, as
amended at USCG–2010–0351, 75 FR 36284,
June 25, 2010]
§ 154.107 Alternatives.
(a) The COTP may consider and approve alternative procedures, methods,
or equipment standards to be used by a
facility operator in lieu of any requirement in this part if:
(1) Compliance with the requirement
is economically or physically impractical;
(2) The alternative provides an equivalent level of safety and protection
from pollution by oil or hazardous material, which is documented in the request; and
(3) The facility operator submits a
written request for the alternative.
(b) The COTP takes final approval or
disapproval action on the request, submitted in accordance with paragraph
(a) of this section, in writing within 30
days of receipt of the request.
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[CGD 75–124, 45 FR 7169, Jan. 31, 1980, as
amended by CGD 86–034, 55 FR 36252, Sept. 4,
1990; CGD 93–056, 61 FR 41458, Aug. 8, 1996]
§ 154.108 Exemptions.
(a) The Assistant Commandant for
Marine Safety, Security and Environmental Protection, acting for the Commandant, grants an exemption or partial exemption from compliance with
any requirement in this part if:
(1) A facility operator submits an application for the exemption via the
COTP; and
(2) It is determined, from the application, that:
(i) Compliance with the requirement
is economically or physically impractical;
(ii) No alternative procedures, methods, or equipment standards exist that
would provide an equivalent level of
safety and protection from pollution by
oil or hazardous material; and
(iii) The likelihood of oil or hazardous material being discharged is not
substantially increased as a result of
the exemption.
(b) If requested, the applicant must
submit any appropriate information,
including an environmental and economic assessment of the effects of and
reasons for the exemption, and proposed procedures, methods or equipment standards.
(c) The exemption may specify the
procedures, methods, or equipment
standards that will apply.
(d) An exemption is granted or denied
in writing. The decision of the Assistant Commandant for Marine Safety,
Security and Environmental Protection is a final agency action.
[CGD 75–124, 45 FR 7169, Jan. 31, 1980, as
amended by CGD 88–052, 53 FR 25122, July 1,
1988; CGD 86–034, 55 FR 36252, Sept. 4, 1990; 55
FR 49997, Dec. 4, 1990; CGD 96–026, 61 FR
33666, June 28, 1996; CGD 93–056, 61 FR 41458,
Aug. 8, 1996; CGD 97–023, 62 FR 33364, June 19,
1997; USCG–2002–12471, 67 FR 41333, June 18,
2002]
§ 154.110
Letter of intent.
(a) The facility operator of any facility to which this part applies must submit a letter of intent to operate a facility or to conduct mobile facility operations to the COTP not less than 60
days before the intended operations unless a shorter period is allowed by the
COTP. Previously submitted letters of
intent need not be resubmitted.
(b) The letter of intent required by
paragraph (a) of this section may be in
any form but must contain:
(1) The names, addresses, and telephone numbers of the facility operator
and the facility owner;
(2) The name, address, and telephone
number of the facility or, in the case of
a mobile facility, the dispatching office; and
(3) Except for a mobile facility, the
geographical location of the facility in
relation to the associated body of navigable waters.
(c) The facility operator of any facility for which a letter of intent has been
submitted, shall within five (5) days advise the COTP in writing of any
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Coast Guard, DHS
§ 154.300
changes of information and shall cancel, in writing, the letter for any facility at which transfer operations are no
longer conducted.
[CGD 75–124, 45 FR 7169, Jan. 31, 1980, as
amended by CGD 86–034, 55 FR 36252, Sept. 4,
1990; CGD 93–056, 61 FR 41458, Aug. 8, 1996]
§ 154.120 Facility examinations.
(a) The facility operator shall allow
the Coast Guard, at any time, to make
any examination and shall perform,
upon request, any test to determine
compliance with this part and part 156,
as applicable. The facility operator
shall conduct all required testing of facility equipment in a manner acceptable to the Coast Guard.
(b) The COTP shall provide the facility operator with a written report of
the results of the examination for the
record required by § 154.740(e) and shall
list the deficiencies in the report when
the facility is not in compliance with
the requirements in this part and part
156 of this chapter.
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[CGD 75–124, 45 FR 7169, Jan. 31, 1980]
§ 154.T150 Temporary suspension of
requirements to permit support of
deepwater horizon spill response.
(a) Applicability. This section applies
to—
(1) Any facility described in § 154.100
of this part, that has contracted with
any oil spill removal organization
(OSRO), as defined in § 154.1020 of this
part, if the OSRO’s response resources,
as defined in § 154.1020 of this part, are
deployed in coordination with the OnScene Coordinator (OSC), as defined in
40 CFR 300.5, in support of the response
to the Deepwater Horizon Spill of National Significance; and
(2) Any facility described in § 154.100
of this part, that owns, operates, or has
under its direct control, response resources, as defined in § 154.1020 of this
part, deployed in coordination with the
OSC, as described in 40 CFR 300.5, in
support of the response to the Deepwater Horizon Spill of National Significance.
(b) Suspension of certain response time
requirements. From June 30, 2010
through December 31, 2010, the stipulated response times, including the response times contained in any written
contractual agreement with any OSRO,
for the availability of response resources, as defined in § 154.1020 of this
part, for a maximum most probable
discharge and a worst case discharge
are not necessary to meet the requirements of this part.
(c) Other response time requirements
still effective. Any response time requirements for the availability of response resources, as defined in § 154.1020
of this part, for an average most probable discharge, as required by this part,
remain in effect.
(d) Armed Forces installation planning
factors. The Coast Guard authorizes the
Armed Forces to revise Armed Forces
installation response times to below
that which is necessary to respond to
an average most probable discharge at
those installations that have deployed
assets in support of the response to the
Deepwater Horizon Spill of National
Significance in response to a request
from the OSC, as described in 40 CFR
300.5, for such assets.
EFFECTIVE DATE NOTE: By USCG–2010–0592,
75 FR 37719, June 30, 2010, temporary
§ 154.T150 was added, effective June 30, 2010
through Dec. 31, 2010.
Subpart B—Operations Manual
§ 154.300
Operations manual: General.
(a) The facility operator of each facility to which this part applies shall
submit, with the letter of intent, two
copies of an Operations Manual that:
(1) Describes how the applicant meets
the operating rules and equipment requirements prescribed by this part and
part 156 of this chapter;
(2) Describes the responsibilities of
personnel under this part and part 156
of this chapter in conducting transfer
operations; and
(3) Includes translations into a language or languages understood by all
designated persons in charge of transfer operations employed by the facility.
(b) The facility operator shall maintain the operations manual so that it
is:
(1) Current; and
(2) Readily available for examination
by the COTP.
(c) The COTP shall examine the Operations Manual when submitted, after
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§ 154.310
33 CFR Ch. I (7–1–10 Edition)
any substantial amendment, and as
otherwise required by the COTP.
(d) In determining whether the manual meets the requirements of this part
and part 156 of this chapter the COTP
shall consider the size, complexity, and
capability of the facility.
(e) If the manual meets the requirements of this part and part 156 of this
chapter, the COTP will return one copy
of the manual marked ‘‘Examined by
the Coast Guard’’ as described in
§ 154.325.
(f) The facility operator shall ensure
that a sufficient number of copies of
the examined Operations Manual, including a sufficient number of the
translations required by paragraph
(a)(3) of this section, are readily available for each facility person in charge
while conducting a transfer operation.
NOTE: The facility operator may request
that the contents of the operations manual
or portions thereof be considered commercial
or financial information that is privileged or
confidential. Under the Freedom of Information Act, the Coast Guard would withhold
any part of the contents of the operations
manual from public disclosure upon determining that it is commercial or financial information that is privileged or confidential.
erowe on DSK5CLS3C1PROD with CFR
[CGD 75–124, 45 FR 7169, Jan. 31, 1980, as
amended by CGD 86–034, 55 FR 36253, Sept. 4,
1990; CGD 93–056, 61 FR 41458, Aug. 8, 1996]
§ 154.310 Operations manual: Contents.
(a) Each operations manual required
by § 154.300 must contain:
(1) The geographic location of the facility;
(2) A physical description of the facility including a plan and/or plans, maps,
drawings, aerial photographs or diagrams, showing the boundaries of the
facility subject to Coast Guard jurisdiction, mooring areas, transfer locations, control stations, wharfs, the extent and scope of the piping subject to
the tests required by § 156.170(c)(4) of
this chapter, and the locations of safety equipment. For mobile facilities, a
physical description of the facility;
(3) The hours of operation of the facility;
(4) The sizes, types, and number of
vessels that the facility can transfer
oil or hazardous material to or from simultaneously;
(5) For each product transferred at
the facility:
(i) Generic or chemical name; and
(ii) The following cargo information:
(a) The name of the cargo as listed
under appendix II of annex II of
MARPOL 73/78, Table 30.25–1 of 46 CFR
30.25–1, Table 151.05 of 46 CFR 151.05–1,
or Table 1 of 46 CFR part 153.
(b) A description of the appearance of
the cargo;
(c) A description of the odor of the
cargo;
(d) The hazards involved in handling
the cargo;
(e) Instructions for safe handling of
the cargo;
(f) The procedures to be followed if
the cargo spills or leaks, or if a person
is exposed to the cargo; and
(g) A list of fire fighting procedures
and extinguishing agents effective with
fires involving the cargo.
(6) The minimum number of persons
on duty during transfer operations and
their duties;
(7) The name and telephone number
of the qualified individual identified
under § 154.1026 of this part and the
title and/or position and telephone
number of the Coast Guard, State,
local, and other personnel who may be
called by the employees of the facility
in an emergency;
(8) The duties of watchmen, required
by § 155.810 of this chapter and 46 CFR
35.05–15, for unmanned vessels moored
at the facility;
(9) A description of each communication system required by this part;
(10) The location and facilities of
each personnel shelter, if any;
(11) A description and instructions
for the use of drip and discharge collection and vessel slop reception facilities, if any;
(12) A description and the location of
each emergency shutdown system;
(13) Quantity, types, locations, and
instructions for use of monitoring devices if required by § 154.525;
(14) Quantity, type, location, instructions for use, and time limits for gaining access to the containment equipment required by § 154.545;
(15) Quantity, type, location, and instructions for use of fire extinguishing
equipment required by § 154.735(d) of
this part;
(16) The maximum allowable working
pressure (MAWP) of each loading arm,
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Coast Guard, DHS
§ 154.320
transfer pipe system, and hose assembly required to be tested by § 156.170 of
this chapter, including the maximum
relief valve setting (or maximum system pressure when relief valves are not
provided) for each transfer system;
(17) Procedures for:
(i) Operating each loading arm including the limitations of each loading
arm;
(ii) Transferring oil or hazardous material;
(iii) Completion of pumping; and
(iv) Emergencies;
(18) Procedures for reporting and initial containment of oil or hazardous
material discharges;
(19) A brief summary of applicable
Federal, state, and local oil or hazardous material pollution laws and regulations;
(20) Procedures for shielding portable
lighting authorized by the COTP under
§ 154.570(c); and
(21) A description of the training and
qualification program for persons in
charge.
(22) Statements explaining that each
hazardous materials transfer hose is
marked with either the name of each
product which may be transferred
through the hose or with letters, numbers, symbols, color codes or other system acceptable to the COTP representing all such products and the location in the Operations Manual where
a chart or list of symbols utilized is located and a list of the compatible products which may be transferred through
the hose can be found for consultation
before each transfer; and
(23) For facilities that conduct tank
cleaning or stripping operations, a description of their procedures.
(b) lf a facility collects vapors emitted from vessel cargo tanks for recovery, destruction, or dispersion, the operations manual must contain a description of the vapor collection system at the facility which includes:
(1) A line diagram or simplified piping and instrumentation diagram
(P&ID) of the facility’s vapor control
system piping, including the location
of each valve, control device, pressurevacuum relief valve, pressure indicator, flame arrester, and detonation
arrester; and
(2) A description of the vapor control
system’s design and operation including the:
(i) Vapor line connection;
(ii) Startup and shutdown procedures;
(iii) Steady state operating procedures;
(iv) Provisions for dealing with
pyrophoric sulfide (for facilities which
handle inerted vapors of cargoes containing sulfur);
(v) Alarms and shutdown devices; and
(vi) Pre-transfer equipment inspection requirements.
(c) The facility operator shall incorporate a copy of each amendment to
the operations manual under § 154.320 in
each copy of the manual with the related existing requirement, or add the
amendment at the end of each manual
if not related to an existing requirement.
(d) The operations manual must be
written in the order specified in paragraph (a) of this section, or contain a
cross-referenced index page in that
order.
(Approved by the Office of Management and
Budget under control number 1625–0093)
[CGD 75–124, 45 FR 7171, Jan. 31, 1980, as
amended by CGD 88–102, 55 FR 25428, June 21,
1990; CGD 86–034, 55 FR 36253, Sept. 4, 1990;
CGD 92–027, 58 FR 39662, July 26, 1993; CGD
93–056, 61 FR 41459, Aug. 8, 1996; USCG–2006–
25150, 71 FR 39209, July 12, 2006]
§ 154.320 Operations manual: Amendment.
(a) Using the following procedures,
the COTP may require the facility operator to amend the operations manual
if the COTP finds that the operations
manual does not meet the requirements in this part:
(1) The COTP will notify the facility
operator in writing of any inadequacies
in the Operations Manual. The facility
operator may submit written information, views, and arguments regarding
the inadequacies identified, and proposals for amending the Manual, within 45 days from the date of the COTP
notice. After considering all relevant
material presented, the COTP shall notify the facility operator of any amendment required or adopted, or the COTP
shall rescind the notice. The amendment becomes effective 60 days after
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erowe on DSK5CLS3C1PROD with CFR
§ 154.325
33 CFR Ch. I (7–1–10 Edition)
the facility operator receives the notice, unless the facility operator petitions the Commandant to review the
COTP’s notice, in which case its effective date is delayed pending a decision
by the Commandant. Petitions to the
Commandant must be submitted in
writing via the COTP who issued the
requirement to amend the Operations
Manual.
(2) If the COTP finds that there is a
condition requiring immediate action
to prevent the discharge or risk of discharge of oil or hazardous material
that makes the procedure in paragraph
(a)(1) of this section impractical or
contrary to the public interest, the
COTP may issue an amendment effective on the date the facility operator
receives notice of it. In such a case, the
COTP shall include a brief statement of
the reasons for the findings in the notice. The owner or operator may petition the Commandant to review the
amendment, but the petition does not
delay the amendment.
(b) The facility operator may propose
amendments to the operations manual
by:
(1) Submitting any proposed amendment and reasons for the amendment
to the COTP not less than 30 days before the requested effective date of the
proposed amendment; or
(2) If an immediate amendment is
needed, requesting the COTP to approve the amendment immediately.
(c) The COTP shall respond to proposed amendments submitted under
paragraph (b) of this section by:
(1) Approving or disapproving the
proposed amendments;
(2) Advising the facility operator
whether the request is approved, in
writing, before the requested date of
the amendments;
(3) Including any reasons in the written response if the request is disapproved; and
(4) If the request is made under paragraph (b)(2) of this section immediately
approving or rejecting the request.
(d) Amendments to personnel and
telephone number lists required by
§ 154.310(a)(7) of this part do not require
examination by the COTP, but the
COTP must be advised of such amendments as they occur.
[CGD 75–124, 45 FR 7171, Jan. 31, 1980, as
amended by CGD 86–034, 55 FR 36253, Sept. 4,
1990; CGD 93–056, 61 FR 41459, Aug. 8, 1996]
§ 154.325 Operations manual:
dures for examination.
(a) The operator of a facility shall
submit two copies of the Operations
Manual to the Captain of the Port of
the zone in which the facility is located.
(b) Not less than 60 days prior to any
transfer operation, the operator of a
new facility shall submit, with the letter of intent, two copies of the Operations Manual to the Captain of the
Port of the zone in which the facility is
located.
(c) After a facility is removed from
caretaker status, not less than 30 days
prior to any transfer operation the operator of that facility shall submit two
copies of the Operations Manual to the
COTP of the zone in which the facility
is located unless the manual has been
previously examined and no changes
have been made since the examination.
(d) If the COTP finds that the Operations Manual meets the requirements
of this part and part 156 of this chapter,
the COTP will return one copy of the
manual to the operator marked ‘‘Examined by the Coast Guard’’.
(e) If the COTP finds that the Operations Manual does not meet the requirements of this part and/or part 156
of this chapter, the COTP will return
the manuals with an explanation of
why it does not meet the requirements
of this chapter.
(f) No person may use any Operations
Manual for transfer operations as required by this chapter unless the Operations Manual has been examined by
the COTP.
(g) The Operations Manual is voided
if the facility operator—
(1) Amends the Operations Manual
without following the procedures in
§ 154.320 of this part;
(2) Fails to amend the Operations
Manual when required by the COTP; or
(3) Notifies the COTP in writing that
the facility will be placed in caretaker
status.
[CGD 93–056, 61 FR 41459, Aug. 8, 1996]
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Coast Guard, DHS
§ 154.520
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Subpart C—Equipment
Requirements
§ 154.500 Hose assemblies.
Each hose assembly used for transferring oil or hazardous material must
meet the following requirements:
(a) The minimum design burst pressure for each hose assembly must be at
least four times the sum of the pressure of the relief valve setting (or four
times the maximum pump pressure
when no relief valve is installed) plus
the static head pressure of the transfer
system, at the point where the hose is
installed.
(b) The maximum allowable working
pressure (MAWP) for each hose assembly must be more than the sum of the
pressure of the relief valve setting (or
the maximum pump pressure when no
relief valve is installed) plus the static
head pressure of the transfer system,
at the point where the hose is installed.
(c) Each nonmetallic hose must be
usable for oil or hazardous material
service.
(d) Each hose assembly must either
have:
(1) Full threaded connections;
(2) Flanges that meet ANSI B16.5 or
B16.24 (both incorporated by reference;
see § 154.106); or
(3) Quick-disconnect couplings that
meet ASTM F 1122 (incorporated by
reference, see § 154.106).
(e) Each hose must be marked with
one of the following:
(1) The name of each product for
which the hose may be used; or
(2) For oil products, the words ‘‘OIL
SERVICE’’; or
(3) For hazardous materials, the
words
‘‘HAZMAT
SERVICE—SEE
LIST’’ followed immediately by a letter, number or other symbol that corresponds to a list or chart contained in
the facility’s operations manual or the
vessel’s transfer procedure documents
which identifies the products that may
be transferred through a hose bearing
that symbol.
(f) Each hose also must be marked
with the following, except that the information required by paragraphs (f)(2)
and (3) of this section need not be
marked on the hose if it is recorded in
the hose records of the vessel or facil-
ity, and the hose is marked to identify
it with that information:
(1) Maximum allowable working pressure;
(2) Date of manufacture; and
(3) Date of the latest test required by
§ 156.170.
(g) The hose burst pressure and the
pressure used for the test required by
§ 156.170 of this chapter must not be
marked on the hose and must be recorded elsewhere at the facility as described in paragraph (f) of this section.
(h) Each hose used to transfer fuel to
a vessel that has a fill pipe for which
containment can not practically be
provided must be equipped with an
automatic back pressure shutoff nozzle.
[CGD 75–124, 45 FR 7172, Jan. 31, 1980, as
amended by CGD 86–034, 55 FR 36253, Sept. 4,
1990; CGD 88–032, 56 FR 35820, July 29, 1991;
CGD 92–027, 58 FR 39662, July 26, 1993; CGD
93–056, 61 FR 41459, Aug. 8, 1996; USCG–2000–
7223, 65 FR 40057, June 29, 2000; USCG–2001–
8661, 74 FR 45022, Aug. 31, 2009]
§ 154.510 Loading arms.
(a) Each mechanical loading arm
used for transferring oil or hazardous
material and placed into service after
June 30, 1973, must meet the design,
fabrication, material, inspection, and
testing requirements in ANSI B31.3 (incorporated by reference; see § 154.106).
(b) The manufacturer’s certification
that the standard in paragraph (a) of
this section has been met must be permanently marked on the loading arm
or recorded elsewhere at the facility
with the loading arm marked to identify it with that information.
(c) Each mechanical loading arm
used for transferring oil or hazardous
material must have a means of being
drained or closed before being disconnected after transfer operations are
completed.
[CGD 75–124, 45 FR 7172, Jan. 31, 1980, as
amended by CGD 86–034, 55 FR 36253, Sept. 4,
1990; USCG–2001–8661, 74 FR 45022, Aug. 31,
2009]
§ 154.520 Closure devices.
(a) Except as provided in paragraph
(b) of this section, each facility to
which this part applies must have
enough butterfly valves, wafer-type resilient seated valves, blank flanges, or
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§ 154.525
33 CFR Ch. I (7–1–10 Edition)
other means acceptable to the COTP to
blank off the ends of each hose or loading arm that is not connected for the
transfer of oil or hazardous material.
Such hoses and/or loading arms must
be blanked off during the transfer of oil
or hazardous material. A suitable material in the joints and couplings shall
be installed on each end of the hose assembly or loading arm not being used
for transfer to ensure a leak-free seal.
(b) A new, unused hose, and a hose
that has been cleaned and is gas free, is
exempt from the requirements of paragraph (a) of this section.
[CGD 93–056, 61 FR 41459, Aug. 8, 1996]
§ 154.525
Monitoring devices.
The COTP may require the facility to
install monitoring devices if the installation of monitoring devices at the facility would significantly limit the size
of a discharge of oil or hazardous material and either:
(a) The environmental sensitivity of
the area requires added protection;
(b) The products transferred at the
facility pose a significant threat to the
environment; or
(c) The size or complexity of the
transfer operation poses a significant
potential for a discharge of oil or hazardous material.
[CGD 75–124, 45 FR 7172, Jan. 31, 1980, as
amended by CGD 86–034, 55 FR 36253, Sept. 4,
1990]
erowe on DSK5CLS3C1PROD with CFR
§ 154.530
Small discharge containment.
(a) Except as provided in paragraphs
(c), (d), and (e) of this section, each facility to which this part applies must
have fixed catchments, curbing, or
other fixed means to contain oil or hazardous material discharged in at
least—
(1) Each hose handling and loading
arm area (that area on the facility that
is within the area traversed by the free
end of the hose or loading arm when
moved from its normal stowed or idle
position into a position for connection);
(2) Each hose connection manifold
area; and
(3) Under each hose connection that
will be coupled or uncoupled as part of
the transfer operation during coupling,
uncoupling, and transfer.
(b) The discharge containment means
required by paragraph (a) of this section must have a capacity of at least:
(1) Two barrels if it serves one or
more hoses of 6-inch inside diameter or
smaller, or loading arms of 6-inch
nominal pipe size diameter or smaller;
(2) Three barrels if it serves one or
more hoses with an inside diameter of
more than 6-inches, but less than 12
inches, or loading arms with a nominal
pipe size diameter of more than 6
inches, but less than 12 inches; or
(3) Four barrels if it serves one or
more hoses of 12-inch inside diameter
or larger, or loading arms of 12-inch
nominal pipe size diameter or larger.
(c) The facility may use portable
means of not less than 1⁄2 barrel capacity each to meet the requirements of
paragraph (a) of this section for part or
all of the facility if the COTP finds
that fixed means to contain oil or hazardous material discharges are not feasible.
(d) A mobile facility may have portable means of not less than five gallons
capacity to meet the requirements of
paragraph (a) of this section.
(e) Fixed or portable containment
may be used to meet the requirements
of paragraph (a)(3) of this section.
[CGD 75–124, 45 FR 7172, Jan. 31, 1980, as
amended by CGD 86–034, 55 FR 36253, Sept. 4,
1990; CGD 93–056, 61 FR 41460, Aug. 8, 1996]
§ 154.540
Discharge removal.
Each facility to which this part applies must have a means to safely remove discharged oil or hazardous material, within one hour of completion of
the transfer, from the containment required by § 154.530 of this part without
discharging the oil or hazardous material into the water.
[CGD 93–056, 61 FR 41460, Aug. 8, 1996]
§ 154.545 Discharge
equipment.
containment
(a) Each facility must have ready access to enough containment material
and equipment to contain any oil or
hazardous material discharged on the
water from operations at that facility.
(b) For the purpose of this section,
‘‘access’’ may be by direct ownership,
joint ownership, cooperative venture,
or contractual agreement.
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Coast Guard, DHS
§ 154.560
(c) Each facility must establish time
limits, subject to approval by the
COTP, for deployment of the containment material and equipment required
by paragraph (a) of this section considering:
(1) Oil or hazardous material handling rates;
(2) Oil or hazardous material capacity susceptible to being spilled;
(3) Frequency of facility operations;
(4) Tidal and current conditions;
(5) Facility age and configuration;
and
(6) Past record of discharges.
(d) The COTP may require a facility
to surround each vessel conducting an
oil or hazardous material transfer operation with containment material before commencing a transfer operation
if—
(1) The environmental sensitivity of
the area requires the added protection;
(2) The products transferred at the
facility pose a significant threat to the
environment;
(3) The past record of discharges at
the facility is poor; or
(4) The size or complexity of the
transfer operation poses a significant
potential for a discharge of oil or hazardous material; and
(5) The use of vessel containment
provides the only practical means to
reduce the extent of environmental
damage.
(e) Equipment and procedures maintained to satisfy the provisions of this
chapter may be utilized in the planning
requirements of subpart F and subpart
H of this part.
erowe on DSK5CLS3C1PROD with CFR
[CGD 75–124, 45 FR 7172, Jan. 31, 1980, as
amended by CGD 86–034, 55 FR 36253, Sept. 4,
1990; CGD 93–056, 61 FR 41460, Aug. 8, 1996;
USCG–1999–5149, 65 FR 40825, June 30, 2000]
§ 154.550 Emergency shutdown.
(a) The facility must have an emergency means to enable the person in
charge of the transfer on board the vessel, at that person’s usual operating
station, to stop the flow of oil or hazardous material from the facility to
the vessel. The means must be—
(1) An electrical, pneumatic, or mechanical linkage to the facility; or
(2) An electronic voice communications system continuously operated by
a person on the facility who can stop
the flow of oil or hazardous material
immediately.
(b) The point in the transfer system
at which the emergency means stops
the flow of oil or hazardous material on
the facility must be located near the
dock manifold connection to minimize
the loss of oil or hazardous material in
the event of the rupture or failure of
the hose, loading arm, or manifold
valve.
(c) For oil transfers, the means used
to stop the flow under paragraph (a) of
this section must stop that flow within—
(1) 60 seconds on any facility or portion of a facility that first transferred
oil on or before November 1, 1980; and
(2) 30 seconds on any facility that
first transfers oil after November 1,
1980.
(d) For hazardous material transfers,
the means used to stop the flow under
paragraph (a) of this section must stop
that flow within—
(1) 60 seconds on any facility or portion of a facility that first transferred
hazardous material before October 4,
1990; and
(2) 30 seconds on any facility that
first transfers hazardous material on or
after October 4, 1990.
[CGD 86–034, 55 FR 36253, Sept. 4, 1990]
§ 154.560 Communications.
(a) Each facility must have a means
that enables continuous two-way voice
communication between the person in
charge of the vessel transfer operation
and the person in charge of the facility
transfer operation.
(b) Each facility must have a means,
which may be the communications system itself, that enables a person on
board a vessel or on the facility to effectively indicate the desire to use the
means of communication required by
paragraph (a) of this section.
(c) The means required by paragraph
(a) of this section must be usable and
effective in all phases of the transfer
operation and all conditions of weather
at the facility.
(d) A facility may use the system in
§ 154.550(a)(2) to meet the requirement
of paragraph (a) of this section.
(e) Portable radio devices used to
comply with paragraph (a) of this section during the transfer of flammable
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§ 154.570
33 CFR Ch. I (7–1–10 Edition)
or combustible liquids must be marked
as intrinsically safe by the manufacturer of the device and certified as intrinsically safe by a national testing
laboratory or other certification organization approved by the Commandant
as defined in 46 CFR 111.105–11. As an
alternative to the marking requirement, facility operators may maintain
documentation at the facility certifying that the portable radio devices in
use at the facility are in compliance
with this section.
[CGD 75–124, 45 FR 7172, Jan. 31, 1980; 45 FR
43705, June 30, 1980, as amended by CGD 93–
056, 61 FR 41460, Aug. 8, 1996]
§ 154.570
Lighting.
erowe on DSK5CLS3C1PROD with CFR
(a) Except as provided in paragraph
(c) of this section, for operations between sunset and sunrise, a facility
must have fixed lighting that adequately illuminates:
(1) Each transfer connection point on
the facility;
(2) Each transfer connection point in
use on any barge moored at the facility
to or from which oil or hazardous material is being transferred;
(3) Each transfer operations work
area on the facility; and
(4) Each transfer operation work area
on any barge moored at the facility to
or from which oil or hazardous material is being transferred.
(b) Where the illumination is apparently inadequate, the COTP may require verification by instrument of the
levels of illumination. On a horizontal
plane 3 feet above the barge deck or
walking surface, illumination must
measure at least:
(1) 5.0 foot candles at transfer connection points; and
(2) 1.0 foot candle in transfer operations work areas.
(c) For small or remote facilities, the
COTP may authorize operations with
an adequate level of illumination provided by the vessel or by portable
means.
(d) Lighting must be located or
shielded so as not to mislead or otherwise interfere with navigation on the
adjacent waterways.
[CGD 75–124, 45 FR 7172, Jan. 31, 1980, as
amended by CGD 86–034, 55 FR 36253, Sept. 4,
1990]
Subpart D—Facility Operations
§ 154.700
General.
No person may operate a facility unless the equipment, personnel, and operating procedures of that facility
meet the requirements of this part.
[CGD 75–124, 45 FR 7173, Jan. 31, 1980]
§ 154.710 Persons in charge: Designation and qualification.
No person may serve, and the facility
operator may not use the services of a
person, as person in charge of facility
transfer operations unless:
(a) The facility operator has designated that person as a person in
charge;
(b) The person has had at least 48
hours of experience in transfer operations at a facility in operations to
which this part applies. The person
also has enough experience at the facility for which qualification is desired to
enable the facility operator to determine that the person’s experience is
adequate;
(c) The person has completed a training and qualification program established by the facility operator and described in the Operations Manual in accordance with § 154.310(a)(21), that provides the person with the knowledge
and training necessary to properly operate the transfer equipment at the facility, perform the duties described in
paragraph (d) of this section, follow the
procedures required by this part, and
fulfill the duties required of a person in
charge during an emergency, except
that the COTP may approve alternative experience and training requirements for new facilities; and
(d) The facility operator must certify
that each person in charge has the
knowledge of, and skills necessary to—
(1) The hazards of each product to be
transferred;
(2) The rules in this part and in part
156 of this chapter;
(3) The facility operating procedures
as described in the operations manual;
(4) Vessel transfer systems, in general;
(5) Vessel transfer control systems,
in general;
(6) Each facility transfer control system to be used;
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Coast Guard, DHS
§ 154.735
(7) Follow local discharge reporting
procedures; and
(8) Carry out the facility’s response
plan for discharge reporting and containment.
(e) Training conducted to comply
with the hazard communication programs required by the Occupational
Safety and Health Administration
(OSHA) of the Department of Labor
(DOL) (29 CFR 1910.1200) or the Environmental Protection Agency (EPA)
(40 CFR 311.1), or to meet the requirements of subpart F of this part may be
used to satisfy the requirements in
paragraphs (c) and (d) of this section,
as long as the training addresses the
requirements in paragraphs (c) and (d)
of this section.
(Sec. 311(j)(1)(C) of the Federal Water Pollution Control Act (86 Stat. 816, 868); 33 U.S.C.
1161(j)(1)(C); EO 11548, 3 CFR, 1966–1970 Comp.,
p. 949; 49 CFR 1.46(m))
[CGD 71–160R, 37 FR 28253, Dec. 21, 1972, as
amended by CGD 86–034, 55 FR 36253, Sept. 4,
1990; CGD 93–056, 61 FR 41460, Aug. 8, 1996]
§ 154.730 Persons in charge: Evidence
of designation.
Each person in charge shall carry
evidence of his designation as a person
in charge when he is engaged in transfer operations unless such evidence is
immediately available at the facility.
(Sec. 311(j)(1)(C) of the Federal Water Pollution Control Act (86 Stat. 816, 868); 33 U.S.C.
1161(j)(1)(C); EO 11548, 3 CFR, 1966–1970 Comp.,
p. 949; 49 CFR 1.46(m))
erowe on DSK5CLS3C1PROD with CFR
[CGD 71–160R, 37 FR 28253, Dec. 21, 1972]
§ 154.735 Safety requirements.
Each operator of a facility to which
this part applies shall ensure that the
following safety requirements are met
at the facility:
(a) Access to the facility by firefighting personnel, fire trucks, or other
emergency personnel is not impeded.
(b) Materials which are classified as
hazardous under 49 CFR parts 170
through 179 are kept only in the quantities needed for the operation or maintenance of the facility and are stored
in storage compartments.
(c) Gasoline or other fuel is not
stored on a pier, wharf, or other similar structure.
(d) A sufficient number of fire extinguishers approved by an independent
laboratory listed in 46 CFR 162.028–5 for
fighting small, localized fires are in
place throughout the facility and
maintained in a ready condition.
(e) The location of each hydrant,
standpipe, hose station, fire extinguisher, and fire alarm box is conspicuously marked and readily accessible.
(f) Each piece of protective equipment is ready to operate.
(g) Signs indicating that smoking is
prohibited are posted in areas where
smoking is not permitted.
(h) Trucks and other motor vehicles
are operated or parked only in designated locations.
(i) All rubbish is kept in receptacles.
(j) All equipment with internal combustion engines used on the facility—
(1) Does not constitute a fire hazard;
and
(2) Has a fire extinguisher attached
that is approved by an independent laboratory listed in 46 CFR 162.028–5, unless such a fire extinguisher is readily
accessible nearby on the facility.
(k) Spark arresters are provided on
chimneys or appliances which—
(1) Use solid fuel; or
(2) Are located where sparks constitute a hazard to nearby combustible
material.
(l) All welding or hot work conducted
on or at the facility is the responsibility of the facility operator. The
COTP may require that the operator of
the facility notify the COTP before any
welding or hot work operations are
conducted. Any welding or hot work
operations conducted on or at the facility must be conducted in accordance
with NFPA 51B (incorporated by reference; see § 154.106). The facility operator shall ensure that the following additional conditions or criteria are met:
(1) Welding or hot work is prohibited
during gas freeing operations, within
30.5 meters (100 feet) of bulk cargo operations involving flammable or combustible materials, within 30.5 meters
(100 feet) of fueling operations, or within 30.5 meters (100 feet) of explosives or
15.25 meters (50 feet) of other hazardous
materials.
(2) If the welding or hot work is on
the boundary of a compartment (i.e.,
bulkhead, wall or deck) an additional
fire watch shall be stationed in the adjoining compartment.
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erowe on DSK5CLS3C1PROD with CFR
§ 154.735
33 CFR Ch. I (7–1–10 Edition)
(3) Personnel on fire watch shall have
no other duties except to watch for the
presence of fire and to prevent the development of hazardous conditions.
(4) Flammable vapors, liquids or solids must first be completely removed
from any container, pipe or transfer
line subject to welding or hot work.
(5) Tanks used for storage of flammable or combustible substances must
be tested and certified gas free prior to
starting hot work.
(6) Proper safety precautions in relation to purging, inserting, or venting
shall be followed for hot work on containers;
(7) All local laws and ordinances shall
be observed;
(8) In case of fire or other hazard, all
cutting, welding or other hot work
equipment shall be completely secured.
(m) Heating equipment has sufficient
clearance to prevent unsafe heating of
nearby combustible material.
(n) Automotive equipment having an
internal combustion engine is not refueled on a pier, wharf, or other similar
structure.
(o) There are no open fires or open
flame lamps.
(p) Electric wiring and equipment is
maintained in a safe condition so as to
prevent fires.
(q) Electrical wiring and electrical
equipment installed after October 4,
1990, meet NFPA 70.
(r) Electrical equipment, fittings,
and devices installed after October 4,
1990, show approval for that use by—
(1) Underwriters Laboratories;
(2) Factory Mutual Research Corporation; or
(3) Canadian Standards Association.
(s) Tank cleaning or gas freeing operations conducted by the facility on vessels carrying oil residues or mixtures
shall be conducted in accordance with
sections 9.1, 9.2, 9.3, and 9.5 of the
OCIMF International Safety Guide for
Oil Tankers and Terminals (ISGOTT)
(incorporated
by
reference;
see
§ 154.106), except that—
(1) Prohibitions in ISGOTT against
the use of recirculated wash water do
not apply if the wash water is first
processed to remove product residues;
(2) The provision in ISGOTT section
9.2.10 concerning flushing the bottom
of tanks after every discharge of leaded
gasoline does not apply;
(3) The provision in ISGOTT section
9.2.11 concerning that removal of
sludge, scale, and sediment does not
apply if personnel use breathing apparatus which protect them from the
tank atmosphere; and
(4) Upon the request of the facility
owner or operator in accordance with
§ 154.107, the COTP may approve the use
of alternative standards to ISGOTT if
the COTP determines that the alternative standards provide an equal level
of protection to the ISGOTT standards.
(t) Guards are stationed, or equivalent controls acceptable to the COTP
are used to detect fires, report emergency conditions, and ensure that access to the marine transfer area is limited to—
(1) Personnel who work at the facility including persons assigned for
transfer operations, vessel personnel,
and delivery and service personnel in
the course of their business;
(2) Coast Guard personnel;
(3) Other Federal, State, or local governmental officials; and
(4) Other persons authorized by the
operator.
(u) Smoking shall be prohibited at
the facility except that facility owners
or operators may authorize smoking in
designated areas if—
(1) Smoking areas are designated in
accordance with local ordinances and
regulations;
(2) Signs are conspicuously posted
marking such authorized smoking
areas; and
(3) ‘‘No Smoking’’ signs are conspicuously posted elsewhere on the facility.
(v) Warning signs shall be displayed
on the facility at each shoreside entry
to the dock or berth, without obstruction, at all times for fixed facilities
and for mobile facilities during coupling, transfer operation, and uncoupling. The warning signs shall conform
to 46 CFR 151.45–2(e)(1) or 46 CFR
153.955.
[CGD 86–034, 55 FR 36253, Sept. 4, 1990, as
amended by CGD 93–056, 61 FR 41460, Aug. 8,
1996; USCG–2001–8661, 74 FR 45022, Aug. 31,
2009]
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Coast Guard, DHS
§ 154.740
§ 154.802
Subpart E—Vapor Control Systems
Records.
Each facility operator shall maintain
at the facility and make available for
examination by the COTP:
(a) A copy of the letter of intent for
the facility;
(b) The name of each person designated as a person in charge of transfer operations at the facility and certification that each person in charge
has completed the training requirements of § 154.710 of this part;
(c) The date and result of the most
recent test or examination of each
item tested or examined under § 156.170
of this chapter;
(d) The hose information required by
§ 154.500 (e) and (g) except that marked
on the hose;
(e) The record of all examinations of
the facility by the COTP within the
last 3 years;
(f) The Declaration of Inspection required by § 156.150(f) of this chapter;
(g) A record of all repairs made within the last three years involving any
component of the facility’s vapor control system required by subpart E of
this part;
(h) A record of all automatic shut
downs of the facility’s vapor control
system within the last 3 years; and
(i) Plans, calculations, and specifications of the facility’s vapor control
system certified under § 154.804 of this
part.
(j) If they are not marked as such,
documentation that the portable radio
devices in use at the facility under
§ 154.560 of this part are intrinsically
safe.
(Approved by the Office of Management and
Budget under control number 1625–0060)
[CGD 75–124, 45 FR 7173, Jan. 31, 1980, as
amended by CGD 88–102, 55 FR 25429, June 21,
1990; CGD 86–034, 55 FR 36254, Sept. 4, 1990;
CGD 93–056, 61 FR 41461, Aug. 8, 1996; USCG–
2006–25150, 71 FR 39209, July 12, 2006]
erowe on DSK5CLS3C1PROD with CFR
§ 154.750 Compliance with operations
manual.
The facility operator shall require facility personnel to use the procedures
in the operations manual prescribed by
§ 154.300 for operations under this part.
[CGD 75–124, 45 FR 7174, Jan. 31, 1980]
SOURCE: CGD 88–102, 55 FR 25429, June 21,
1990, unless otherwise noted.
§ 154.800 Applicability.
(a) Except as specified by paragraph
(c) of this section, this subpart applies
to:
(1) Each facility which collects vapors of crude oil, gasoline blends, or
benzene emitted from vessel cargo
tanks;
(2) A vessel which is not a tank vessel
that has a vapor processing unit located on board for recovery, destruction, or dispersion of crude oil, gasoline
blends, or benzene vapors from a tank
vessel; and
(3) Certifying entities which review,
inspect, test, and certify facility vapor
control systems.
(b) A facility which collects vapors of
flammable or combustible cargoes
other than crude oil, gasoline blends,
or benzene, must meet the requirements prescribed by the Commandant
(CG–522).
(c) A facility with an existing Coast
Guard approved vapor control system
which was operating prior to July 23,
1990 is subject only to § 154.850 of this
subpart as long as it receives cargo
vapor only from the specific vessels for
which it was approved.
(d) This subpart does not apply to the
collection of vapors of liquefied flammable gases as defined in 46 CFR 30.10–
39.
(e) When a facility vapor control system which receives cargo vapor from a
vessel is connected to a facility vapor
control system that serves tank storage areas and other refinery processes,
the specific requirements of this subpart apply between the vessel vapor
connection and the point where the
vapor control system connects to the
facility’s main vapor control system.
[CGD 88–102, 55 FR 25429, June 21, 1990, as
amended by CGD 96–026, 61 FR 33666, June 28,
1996; USCG–2010–0351, 75 FR 36284, June 25,
2010]
§ 154.802 Definitions.
As used in this subpart:
Certifying entity means an individual
or organization accepted by the Commandant (CG–522) to review plans and
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erowe on DSK5CLS3C1PROD with CFR
§ 154.804
33 CFR Ch. I (7–1–10 Edition)
calculations for vapor control system
designs, and to conduct initial inspections and witness tests of vapor control
system installations.
Existing vapor control system means a
vapor control system which was operating prior to July 23, 1990.
Facility vapor connection means the
point in a facility’s vapor collection
system where it connects to a vapor
collection hose or the base of a vapor
collection arm.
Inerted means the oxygen content of
the vapor space in a tank vessel’s cargo
tank is reduced to 8 percent by volume
or less in accordance with the inert gas
requirements of 46 CFR 32.53 or 46 CFR
153.500.
Liquid knockout vessel means a device
to separate liquid from vapor.
Maximum
allowable
transfer
rate
means the maximum volumetric rate
at which a vessel may receive cargo or
ballast.
New vapor control system means a
vapor control system which is not an
existing vapor control system.
Vapor balancing means the transfer of
vapor displaced by incoming cargo
from the tank of a vessel receiving
cargo into a tank of the vessel or facility delivering cargo via a vapor collection system.
Vapor collection system means an arrangement of piping and hoses used to
collect vapor emitted from a vessel’s
cargo tanks and transport the vapor to
a vapor processing unit.
Vapor control system means an arrangement of piping and equipment
used to control vapor emissions collected from a vessel, and includes the
vapor collection system and the vapor
processing unit.
Vapor destruction unit means a vapor
processing unit that destroys cargo
vapor by a means such as incineration.
Vapor dispersion system means a vapor
processing unit which releases cargo
vapor to the atmosphere through a
venting system not located on the vessel being loaded or ballasted.
Vapor processing unit means the components of a vapor control system that
recovers, destroys, or disperses vapor
collected from a vessel.
Vapor recovery unit means a vapor
processing unit that recovers cargo
vapor by a non-destructive means such
as lean oil absorbtion, carbon bed adsorption, or refrigeration.
Vessel vapor connection means the
point in a vessel’s fixed vapor collection system where it connects to a
vapor collection hose or arm.
[CGD 88–102, 55 FR 25429, June 21, 1990, as
amended by CGD 96–026, 61 FR 33666, June 28,
1996; USCG–2010–0351, 75 FR 36284, June 25,
2010]
§ 154.804 Review, certification, and initial inspection.
(a) A new vapor control system installation must be certified by a certifying entity as meeting the requirements of this subpart prior to operating.
(b) [Reserved]
(c) An existing vapor control system
installation that has been Coast Guard
approved for operation with specific
vessels must be certified by a certifying entity prior to receiving vapors
from other vessels.
(d) Plans and information submitted
to the certifying entity must include a
qualitative failure analysis. The analysis must demonstrate the following:
(1) The vapor control system is designed to permit the system to continuously operate safely when receiving cargo vapors from tankships and
barges over the full range of transfer
rates expected at the facility;
(2) The vapor control system is provided with the proper alarms and automatic control systems to prevent unsafe operation;
(3) The vapor control system is
equipped with sufficient automatic or
passive devices to minimize damage to
personnel, property, and the environment if an accident were to occur; and
(4) If a quantitative failure analysis
is also conducted, the level of safety
attained is at least one order of magnitude greater than that calculated for
operating without a vapor control system.
NOTE: The American Institute of Chemical
Engineers publication, ‘‘Guidelines for Hazard
Evaluation Procedures’’ may be used as guidance when preparing a qualitative failure
analysis. Military Standard MIL-STD-882B
may be used as guidance when preparing a
quantitative failure analysis.
(e) The certifying entity must conduct all initial inspections and witness
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Coast Guard, DHS
§ 154.806
all tests required to demonstrate that
the facility:
(1) Conforms to certified plans and
specifications;
(2) Meets the requirements of this
subpart; and
(3) Is operating properly.
(f) Upon receipt of written certification from the certifying entity that
a facility’s vapor control system complies with the requirements of this part
the COTP shall endorse the letter of
adequacy required by § 154.325 of this
part to indicate that the facility is acceptable for collecting vapors of crude
oil, gasoline blends, benzene, or any
other vapors for which it is certified.
(g) Any design or configuration alteration involving a certified vapor control system must be reviewed by a certifying entity. After conducting any inspections and witnessing tests necessary to verify that the modified
vapor control system meets the requirements of this subpart, the certifying entity must recertify the installation.
(h) Certifications issued in accordance with this section and a copy of
the plans, calculations, and specifications for the vapor control system
must be maintained at the facility.
(i) A certifying entity accepted under
§ 154.806 of this subpart may not certify
a facility vapor control system if it
was involved in the design or installation of the system.
(Approved by the Office of Management and
Budget under control number 1625–0060)
erowe on DSK5CLS3C1PROD with CFR
[CGD 88–102, 55 FR 25429, June 21, 1990, as
amended by USCG–1998–3799, 63 FR 35531,
June 30, 1998; USCG–2006–25150, 71 FR 39209,
July 12, 2006]
§ 154.806 Application for acceptance as
a certifying entity.
(a) An individual or organization
seeking acceptance as a certifying entity must apply in writing to the Commandant (Stop 7363, Washington, DC
20593–7363). Each application must be
signed and certified to be correct by
the applicant or, if the applicant is an
organization, by an authorized officer
or official representative of the organization, and must include a letter of intent from a facility owner or operator
to use the services of the individual or
organization to certify a vapor control
system installation. Any false statement or misrepresentation, or the
knowing and willful concealment of a
material fact may subject the applicant to prosecution under the provisions of 18 U.S.C. 1001, and denial or
termination of acceptance as a certifying entity.
(b) The applicant must possess the
following minimum qualifications, and
be able to demonstrate these qualifications to the satisfaction of the Commandant (Stop 7363, Washington, DC
20593–7363):
(1) The ability to review and evaluate
design drawings and failure analyses;
(2) A knowledge of the applicable regulations of this subpart, including the
standards incorporated by reference in
these regulations;
(3) The ability to monitor and evaluate test procedures and results;
(4) The ability to perform inspections
and witness tests of bulk liquid cargo
handling systems;
(5) That it is not controlled by an
owner or operator of a vessel or facility
engaged in controlling vapor emissions; and
(6) That it is not dependent upon
Coast Guard acceptance under this section to remain in business.
(c) Each application for acceptance
must contain the following:
(1) The name and address of the applicant, including subsidiaries and divisions if applicable;
(2) A statement that the applicant is
not controlled by an owner or operator
of a vessel or facility engaged in controlling vapor emissions, or a full disclosure of any ownership or controlling
interest held by such owners or operators;
(3) A description of the experience
and qualifications of the person(s) who
would be reviewing or testing the systems;
(4) A statement that the person(s)
who would be reviewing or testing the
systems is/are familiar with the regulations in this subpart; and
(5) A statement that the Coast Guard
may verify the information submitted
in the application and may examine
the person(s) who would be reviewing
or testing the systems to determine
their qualifications.
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§ 154.808
33 CFR Ch. I (7–1–10 Edition)
(d) The acceptance of a certifying entity may be terminated by the Commandant (Stop 7363, Washington, DC
20593–7363) if the entity fails to properly review, inspect, or test a system in
accordance with this subpart.
NOTE: A list of entities accepted to certify
facility vapor control system installations is
available from the Commandant (Stop 7363,
Washington, DC 20593–7363).
(Approved by the Office of Management and
Budget under control number 1625–0060)
[CGD 88–102, 55 FR 25429, June 21, 1990,
amended by CGD 96–026, 61 FR 33666, June
1996; USCG–2006–25150, 71 FR 39210, July
2006; USCG–2010–0351, 75 FR 36284, June
2010]
erowe on DSK5CLS3C1PROD with CFR
§ 154.808
eral.
as
28,
12,
25,
Vapor control system, gen-
(a) A vapor control system design
and installation must eliminate potential overfill hazards, overpressure and
vacuum hazards, and sources of ignition to the maximum practical extent.
Each remaining hazard source which is
not eliminated must be specifically addressed in the protection system design
and operational requirements.
(b) Vapor collection system piping
and fittings must be in accordance
with ANSI B31.3 (incorporated by reference; see § 154.106) and designed for a
maximum allowable working pressure
of at least 150 psig. Valves and flanges
must be in accordance with ANSI B16.5
or B16.24 (both incorporated by reference; see § 154.106), 150 pound class.
(c) All electrical equipment used in a
vapor control system must comply
with NFPA 70.
(d) Any pressure, flow, or concentration indication required by this part
must provide a remote indicator on the
facility where the cargo transfer and
vapor control systems are controlled.
(e) Any alarm condition specified in
this part must activate an audible and
visible alarm where the cargo transfer
and vapor control systems are controlled.
(f) The vapor control system must be
separated or insulated from external
heat sources to limit vapor control system piping surface temperature to not
more than 177 °C. (350 °F.) during normal operation.
(g) A means must be provided to
eliminate any liquid condensate from
the vapor collection system which carries over from the vessel or condenses
as a result of an enrichment process.
(h) If a liquid knockout vessel is installed it must have:
(1) A means to indicate the level of
liquid in the device;
(2) A high liquid level sensor that activates an alarm; and
(3) A high high level sensor that
closes the remotely operated cargo
vapor shutoff valve required by
§ 154.810(a) of this subpart and shuts
down any compressors or blowers prior
to liquid carrying over from the vessel
to the compressor or blower.
(i) Vapor collection piping must be
electrically grounded and electrically
continuous.
(j) If the facility handles inerted vapors of cargoes containing sulfur, provisions must be made to control heating from pyrophoric iron sulfide deposits in the vapor collection line.
[CGD 88–102, 55 FR 25429, June 21, 1990, as
amended by USCG–2001–8661, 74 FR 45023,
Aug. 31, 2009]
§ 154.810 Vapor line connections.
(a) A remotely operated cargo vapor
shutoff valve must be installed in the
vapor collection line between the facility vapor connection and the nearest
point where any inerting, enriching, or
diluting gas is introduced into the
vapor collection line or where a detonation arrester is fitted. The valve
must:
(1) Close within thirty (30) seconds
after detection of a shutdown condition
by a component required by this subpart;
(2) Close automatically if the control
signal is lost;
(3) Activate an alarm when a signal
to shut down is received;
(4) Be capable of manual operation or
manual activation;
(5) Have a local valve position indicator or be designed so that the valve
position can be readily determined
from the valve handle or valve stem position; and
(6) If the valve seat is fitted with resilient material, not allow appreciable
leakage when the resilient material is
damaged or destroyed.
(b) Except when a vapor collection
arm is used, the last 1.0 meter (3.3 feet)
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erowe on DSK5CLS3C1PROD with CFR
Coast Guard, DHS
§ 154.812
of vapor piping before the facility
vapor connection must be:
(1) Painted red/yellow/red with:
(i) The red bands 0.1 meter (0.33 feet)
wide, and
(ii) The middle yellow band 0.8 meter
(2.64 feet) wide; and
(2) Labeled ‘‘VAPOR’’ in black letters
at least 50 millimeters (2 inches) high.
(c) Each facility vapor connection
flange must have a permanently attached 0.5 inch diameter stud at least
1.0 inch long projecting outward from
the flange face. The stud must be located at the top of the flange, midway
between bolt holes, and in line with the
bolt hole pattern.
(d) Each hose used for transferring
vapors must:
(1) Have a design burst pressure of at
least 25 psig;
(2) Have a maximum allowable working pressure of at least 5 psig;
(3) Be capable of withstanding at
least 2.0 psi vacuum without collapsing
or constricting;
(4) Be electrically continuous with a
maximum resistance of ten thousand
(10,000) ohms;
(5) Have flanges with:
(i) A bolt hole arrangement complying with the requirements for 150
pound class ANSI B16.5 (incorporated
by reference; see § 154.106) flanges, and
(ii) One or more 0.625 inch diameter
holes in the flange located midway between bolt holes and in line with the
bolt hole pattern;
(6) Be abrasion resistant and resistant to kinking; and
(7) Have the last 1.0 meter (3.3 feet) of
each end of the vapor hose marked in
accordance with paragraph (b) of this
section.
(e) Vapor hose handling equipment
must be provided with hose saddles
which provide adequate support to prevent kinking or collapse of hoses.
(f) Fixed vapor collection arms must:
(1) Meet the requirements of paragraphs (d)(1) through (d)(5) of this section;
(2) Have the last 1.0 meter (3.3 feet) of
the arm marked in accordance with
paragraph (b) of this section.
(g) The facility vapor connection
must be electrically insulated from the
vessel vapor connection in accordance
with section 6.10 of the OCIMF Inter-
national Safety Guide for Oil Tankers
and Terminals (incorporated by reference; see § 154.106).
(h) A vapor collection system fitted
with an enriching system that operates
at a positive gauge pressure at the facility vapor connection must be fitted
with:
(1) A manual isolation valve between
each facility vapor connection and the
remotely operated cargo vapor shutoff
valve required by paragraph (a) of this
section; and
(2) A means to prevent backflow of
enriched vapor to the vessel’s vapor
collection system.
[CGD 88–102, 55 FR 25429, June 21, 1990, as
amended by USCG–2001–8661, 74 FR 45023,
Aug. 31, 2009]
§ 154.812 Facility requirements for vessel liquid overfill protection.
(a) Each facility which receives cargo
vapor from a tank barge which is fitted
with overfill protection in accordance
with 46 CFR 39.20–9(a) as its only means
of overfill protection must provide a
120 volt, 20 amp explosion proof receptacle which meets:
(1) ANSI/NEMA WD6 (incorporated by
reference; see § 154.106);
(2) NFPA 70, National Electrical
Code, Articles 410–57 and 501–12; incorporated by reference; see § 154.106); and
(3) 46 CFR 111.105–9.
(b) Each facility that receives cargo
vapor from a tank barge fitted with an
intrinsically safe cargo tank level sensor system complying with 46 CFR
39.20–9(b) as its only means of overfill
protection must have an overfill control panel on the dock capable of
powering and receiving an alarm and
shutdown signal from the cargo tank
level sensor system that:
(1) Closes the remotely operated
cargo vapor shutoff valve required by
§ 154.810(a) of this subpart and activates
the emergency shutdown system required by § 154.550 of this part when:
(i) A tank overfill signal is received
from the barge, or
(ii) Electrical continuity of the cargo
tank level sensor system is lost;
(2) Activates an alarm which is audible and visible to barge personnel and
facility personnel when a tank overfill
signal, or an optional high level signal
corresponding to a liquid level lower
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§ 154.814
33 CFR Ch. I (7–1–10 Edition)
than the tank overfill sensor setting, is
received from the barge;
(3) Has a means to electrically and
mechanically test the alarms and automatic shutdown systems prior to transferring cargo to or ballasting the tank
barge;
(4) Has suitable means, such as approved intrinsic safety barriers able to
accept passive devices, to ensure that
the overfill and optional alarm circuits
on the barge side of the overfill control
panel, including cabling, normally
closed switches, and pin and sleeve connectors, are intrinsically safe;
(5) Is labeled with the maximum allowable inductance and capacitance to
be connected to the panel, as specified
by the equipment manufacturer; and
(6) Has a female connecting plug for
the tank barge level sensor system
with a 5 wire, 16 amp connector body
meeting IEC 309–1/309–2 (incorporated
by reference; see § 154.106) which is:
(i) Configured with pins S2 and R1 for
the tank overfill sensor circuit, pin G
connected to the cabling shield, and
pins N and T3 reserved for an optional
high level alarm connection;
(ii) Labeled ‘‘Connector for Barge
Overflow Control System’’; and
(iii) Connected to the overfill control
panel by a shielded flexible cable.
erowe on DSK5CLS3C1PROD with CFR
[CGD 88–102, 55 FR 25429, June 21, 1990, as
amended by USCG–2001–8661, 74 FR 45023,
Aug. 31, 2009]
§ 154.814 Facility requirements for vessel vapor overpressure and vacuum
protection.
(a) A facility’s vapor collection system must have the capacity for collecting cargo vapor at a rate of not less
than 1.25 times the facility’s maximum
liquid transfer rate for cargo for which
vapor collection is required plus any
inerting, diluting, or enriching gas
which may be added to the system, unless the vapor growth for turbulent
loading of the most volatile liquid handled by the facility is less than 25 percent.
(b) A facility vapor collection system
must maintain the pressure in a vessel’s cargo tanks between 80 percent of
the highest setting of any of the vessel’s vacuum relief valves and 80 percent of the lowest setting of any of the
vessel’s pressure relief valves for a non-
inerted tank vessel, and between 0.2
psig and 80 percent of the lowest setting of any of the vessel’s pressure relief valves for an inerted tank vessel.
The system must be capable of maintaining the pressure in the vessel’s
cargo tanks within this range at any
cargo transfer rate less than or equal
to the maximum transfer rate determined at the pre-transfer conference
required by § 156.120(w) of this chapter.
(c) The pressure measured at the facility vapor connection must be corrected for pressure drops across the
vessel’s vapor collection system and
the vapor collection hose or arm.
(d) A pressure sensing device must be
provided which activates an alarm
when the pressure at the facility vapor
connection exceeds either the pressure
corresponding to the upper pressure determined in paragraph (b) of this section or a lower pressure agreed upon at
the pre-transfer conference required by
§ 156.120(w) of this chapter.
(e) A pressure sensing device must be
provided which activates an alarm
when the pressure at the facility vapor
connection falls below either the pressure corresponding to the lower pressure determined in paragraph (b) of
this section or a higher pressure agreed
upon at the pre-transfer conference required by § 156.120(w) of this chapter.
(f) A pressure sensing device must be
provided which activates the emergency shutdown system required by
§ 154.550 of this part and closes the remotely operated cargo vapor shutoff
valve required by § 154.810(a) of this
subpart when the pressure at the facility vapor connection exceeds 2.0 psi, or
a lower pressure agreed upon at the
pre-transfer conference required by
§ 156.120(w) of this chapter. The sensing
device must be independent of the device used to activate the alarm required by paragraph (d) of this section.
(g) A pressure sensing device must be
provided which closes the remotely operated cargo vapor shutoff valve required by § 154.810(a) of this subpart
when the vacuum at the facility vapor
connection is more than 1.0 psi, or a
lesser vacuum set at the pre-transfer
conference required by § 156.120(w) of
this chapter. The sensing device must
be independent of the device used to
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§ 154.820
activate the alarm required by paragraph (e) of this section.
(h) The pressure sensing devices required by paragraphs (d) and (f) of this
section must be located in the vapor
collection line between the facility
vapor connection and the manual isolation valve, if required by § 154.810(h) of
this subpart, unless an interlock is provided which prevents operation of the
system when the isolation valve is
closed.
(i) A pressure indicating device must
be provided which indicates the pressure in the vapor collection line.
(j) If a compressor, blower, or eductor
capable of drawing more than 1.0 psi
vacuum is used to draw vapor from the
vessel, a vacuum relief valve must be
installed in the vapor collection line
between the compressor, blower, or
eductor and the facility vapor connection, which:
(1) Relieves at a pressure such that
the pressure in the vapor collection
system at the facility vapor connection
does not exceed 1.0 psi vacuum;
(2) Has a relieving capacity equal to
or greater than the capacity of the
compressor, blower, or eductor;
(3) Has a flame screen fitted at the
vacuum relief opening; and
(4) Has been tested for relieving capacity in accordance with paragraph
1.5.1.3 of API 2000 (incorporated by reference; see § 154.106) with a flame screen
fitted.
(k) When a facility collects cargo
vapor through an undersea pipeline
from a vessel moored offshore, the vacuum relief valve may be set at a vacuum greater than 1.0 psi vacuum provided the pressure controls take into
account the pressure drop across the
vessel’s vapor collection system, any
vapor collection hoses, and the undersea pipeline as a function of the actual
transfer rate.
(l) If the pressure in the vapor collection system can exceed 2.0 psig due to
a malfunction in an inerting, enriching, or diluting system a pressure relief
valve must:
(1) Be installed between the point
where inerting, enriching, or diluting
gas is introduced into the vapor collection system and the facility vapor connection;
(2) Relieve at a pressure such that
the pressure in the vapor collection
system at the facility vapor connection
does not exceed 2.0 psig;
(3) Have a relieving capacity equal to
or greater than the maximum capacity
of the facility inerting, enriching, or
diluting gas source;
(4) If not designed to insure a minimum vapor discharge velocity of 30
meters (98.4 ft.) per second, have a
flame screen fitted at the discharge
opening; and
(5) Have been tested for relieving capacity in accordance with paragraph
1.5.1.3 of API 2000.
(m) The relieving capacity test required by paragraph (l)(5) must be carried out with a flame screen fitted at
the discharge opening if the pressure
relief valve is not designed to insure a
minimum vapor discharge velocity of
30 meters (98.4 ft.) per second.
[CGD 88–102, 55 FR 25429, June 21, 1990, as
amended by USCG–1998–3799, 63 FR 35531,
June 30, 1998; USCG–2001–8661, 74 FR 45023,
Aug. 31, 2009]
§ 154.820 Fire, explosion, and detonation protection.
(a) A vapor control system with a
single facility vapor connection that
receives vapor only from a vessel with
inerted cargo tanks and processes
vapor with a vapor recovery unit must:
(1) Be capable of inerting the vapor
collection line in accordance with
§ 154.824(a) of this subpart prior to receiving vapors from the vessel;
(2) Have at least one oxygen analyzer
that samples the vapor concentration
continuously at a point not more than
6 meters (19.7 ft.) from the facility
vapor connection; and
(3) Meet § 154.824 (f)(1), (f)(2), (g),
(h)(2), and (h)(3) of this subpart.
(b) A vapor control system with a
single facility vapor connection that
receives vapor only from a vessel with
inerted cargo tanks and processes
vapor with a vapor destruction unit
must:
(1) Have a detonation arrester located not more than 6 meters (19.7 ft.)
from the facility vapor connection; or
(2) Have an inerting system that
meets the requirements of § 154.824 of
this subpart.
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33 CFR Ch. I (7–1–10 Edition)
(c) A vapor control system with a
single facility vapor connection that
receives vapor from a vessel with cargo
tanks that are not inerted and processes vapor with a vapor recovery unit
must:
(1) Have a detonation arrester located not more than 6 meters (19.7 ft.)
from the facility vapor connection; or
(2) Have an inerting, enriching, or diluting system that meets the requirements of § 154.824 of this subpart.
(d) A vapor control system with a
single facility vapor connection that
receives vapor from a vessel with cargo
tanks that are not inerted and processes the vapor with a vapor destruction unit must:
(1) Have a detonation arrester located not more than 6 meters (19.7 ft.)
from the facility vapor connection; and
(2) Have an inerting, enriching, or diluting system that meets the requirements of § 154.824 of this subpart.
(e) A vapor control system with multiple facility vapor connections that
processes vapor with a vapor recovery
unit must have a detonation arrester
located not more than 6 meters (19.7
ft.) from each facility vapor connection.
(f) A vapor control system with multiple facility vapor connections that
processes vapor with a vapor destruction unit must:
(1) Have a detonation arrester located not more than 6 meters (19.7 ft.)
from each facility vapor connection;
and
(2) Have an inerting, enriching, or diluting system that meets the requirements of § 154.824 of this subpart.
(g) A vapor control system that uses
a vapor balancing system in which
cargo vapor from a vessel is transferred
through the facility vapor collection
system to facility storage tanks must:
(1) Have a detonation arrester located not more than 6 meters (19.7 ft.)
from each facility vapor connection;
(2) Have a detonation arrester located within the storage tank containment area as close as practical to the
vapor return connection of each facility storage tank; and
(3) Have facility storage tank high
level alarm systems and facility storage tank overfill control systems ar-
ranged to prevent cargo from entering
the vapor return line.
(h) Except for a discharge vent from
a vapor destruction unit, each outlet of
a vapor control system that vents to
atmosphere and is not isolated with a
pressure-vacuum relief valve must
have a flame arrester located at the
outlet.
§ 154.822 Detonation arresters, flame
arresters, and flame screens.
(a) Each detonation arrester required
by this part must:
(1) Be capable of arresting a detonation from either side of the device; and
(2) Be acceptable to the Commandant
(CG–522). A detonation arrester designed, built, and tested in accordance
with appendix A of this part will be acceptable to the Commandant (G-MSO).
(b) Each flame arrester required by
this part must be acceptable to the
Commandant (CG–522). A flame arrester designed, built, and tested in accordance with appendix B of this part
will be acceptable to the Commandant
(G-MSO).
(c) Each flame screen required by
this part must be either a single screen
of corrosion resistant wire of at least
30 by 30 mesh, or two screens, both of
corrosion resistant wire, of at least 20
by 20 mesh, spaced not less than 12.7
millimeters (1⁄2 in.) or more than 38.1
millimeters (11⁄2 in.) apart.
[CGD 88–102, 55 FR 25429, June 21, 1990; 55 FR
39270, Sept. 26, 1990, as amended by CGD 96–
026, 61 FR 33666, June 28, 1996; USCG–2002–
12471, 67 FR 41333, June 18, 2002; USCG–2010–
0351, 75 FR 36284, June 25, 2010]
§ 154.824 Inerting, enriching, and diluting systems.
(a) A vapor control system which
uses inerting, enriching, or diluting gas
must be capable of inerting, enriching,
or diluting the vapor collection line
prior to receiving cargo vapor.
(b) Except as permitted by § 154.820(a)
of this subpart, a vapor control system
which uses an inerting, enriching, or
diluting system must be equipped with
a gas injection and mixing arrangement located as close as practical but
not more than 10 meters (32.8 ft.) from
the facility vapor connection that ensures complete mixing of the gases
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§ 154.824
within 20 pipe diameters of the injection point;
(c) A vapor control system that uses
an inerting or enriching system may
not be operated at a vacuum after the
injection point unless:
(1) There are no sleeve-type pipe couplings, vacuum relief valves, or other
devices which could allow air into the
vapor collection system downstream of
the injection point; or
(2) An additional analyzer is used to
monitor the downstream vapor concentration and a means is provided to
inject additional inerting or enriching
gas.
(d) A vapor control system that uses
analyzers to control the amount of
inerting, enriching, or diluting gas injected into the vapor collection line
must be equipped with at least 2 analyzers. The analyzers must be connected so that:
(1) When oxygen analyzers are used,
the higher oxygen concentration reading controls the inerting or enriching
system and activates the alarm and
automatic shutdown system required
by paragraph (h), (j) or (k)(2) of this
section;
(2) When hydrocarbon analyzers are
used, the lower hydrocarbon concentration reading controls the enriching system and activates the alarm and automatic shutdown system required by
paragraph (i) or (k)(1) of this section;
and
(3) When hydrocarbon analyzers are
used, the higher hydrocarbon concentration reading controls the diluting system and activates the alarm and
automatic shutdown system required
by paragraph (l) of this section.
(e) A vapor control system that uses
volumetric measurements to control
the amount of inerting, enriching, or
diluting gas injected into the vapor
collection line must be equipped with
at least one analyzer to activate the
alarms and automatic shutdown systems required by this section.
(f) Each oxygen or hydrocarbon analyzer required by this section must:
(1) Be installed in accordance with
API Recommended Practice 550 (incorporated by reference; see § 154.106);
(2) Have a response time of not more
than 30 seconds from the time the
vapor is sampled; and
(3) Sample the vapor concentration
continuously not more than 30 pipe diameters from the gas injection point.
(g) Oxygen analyzers which operate
at elevated temperatures (i.e., zirconia
oxide or thermomagnetic) must not be
used.
(h) An inerting system must:
(1) Supply sufficient inert gas to the
vapor stream to ensure that the oxygen
concentration throughout the vapor
collection system is maintained below
8.0 percent by volume;
(2) Activate an alarm when the oxygen concentration in the vapor collection line exceeds 8.0 percent by volume;
(3) Close the remotely operated cargo
vapor shutoff valve required by
§ 154.810(a) of this part when the oxygen
concentration in the vapor collection
line exceeds 9.0 percent by volume; and
(4) If a combustion device is used to
produce the inert gas, have a hydraulic
seal and non-return valve between the
combustion device and the vapor collection line.
(i) An enriching system must:
(1) Supply sufficient compatible hydrocarbon vapor to the vapor stream to
ensure that the hydrocarbon concentration throughout the vapor collection system is maintained above 170
percent by volume of the upper flammable limit;
(2) Activate an alarm when the hydrocarbon concentration in the vapor
collection line falls below 170 percent
by volume of the upper flammable
limit; and
(3) Close the remotely operated cargo
vapor shutoff valve required by
§ 154.810(a) of this subpart when the hydrocarbon concentration in the vapor
collection line falls below 150 percent
by volume of the upper flammable
limit.
(j) Oxygen analyzers may be used in
lieu of hydrocarbon analyzers in an enriching system at a facility that receives cargo vapor only from a vessel
with non-inerted cargo tanks, provided
that the analyzers:
(1) Activate an alarm when the oxygen concentration in the vapor collection line exceeds 15.5 percent by volume; and
(2) Close the remotely operated cargo
vapor shutoff valve required by
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§ 154.826
33 CFR Ch. I (7–1–10 Edition)
§ 154.810(a) of this subpart when the oxygen concentration in the vapor collection line exceeds 16.5 percent by volume.
(k) An enriching system may be used
in a vapor collection system that receives cargo vapor from a vessel with
inerted cargo tanks if:
(1) Hydrocarbon analyzers are used to
comply with paragraph (i)(2) and (i)(3)
of this section; or
(2) If oxygen analyzers are used, the
analyzers activate an alarm when the
oxygen concentration in the vapor collection line exceeds 8 percent by volume, and close the remotely operated
cargo vapor shutoff valve required by
§ 154.810(a) of this subpart when the oxygen concentration exceeds 9 percent
by volume.
(l) An air dilution system must:
(1) Supply sufficient additional air to
the vapor stream to ensure that the hydrocarbon concentration throughout
the vapor collection system is maintained below 30 percent by volume of
the lower flammable limit;
(2) Activate an alarm when the hydrocarbon concentration in the vapor
collection line exceeds 30 percent by
volume of the lower flammable limit;
and
(3) Close the remotely operated cargo
vapor shutoff valve required by
§ 154.810(a) of this subpart when the hydrocarbon concentration in the vapor
collection line exceeds 50 percent by
volume of the lower flammable limit.
[CGD 88–102, 55 FR 25429, June 21, 1990; 55 FR
39270, Sept. 26, 1990, as amended by USCG–
2001–8661, 74 FR 45023, Aug. 31, 2009]
erowe on DSK5CLS3C1PROD with CFR
§ 154.826
ers.
Vapor compressors and blow-
(a) Each inlet and outlet to a compressor or blower which handles vapor
that has not been inerted, enriched, or
diluted in accordance with § 154.824 of
this subpart must be fitted with:
(1) A detonation arrester;
(2) A flame arrester; or
(3) An explosion suppression system
acceptable to the Commandant (CG–
522).
(b) If a reciprocating or screw-type
compressor handles vapor in the vapor
collection system, it must be provided
with indicators and audible and visible
alarms to warn against the following
conditions:
(1) Excessive discharge gas temperature at each compressor chamber or
cylinder;
(2) Excessive cooling water temperature;
(3) Excessive vibration;
(4) Low lube oil level;
(5) Low lube oil pressure; and
(6) Excessive shaft bearing temperatures.
(c) If a liquid ring-type compressor
handles vapor in the vapor collection
system, it must be provided with indicators and audible and visible alarms
to warn against the following conditions:
(1) Low level of liquid sealing medium;
(2) Lack of flow of liquid sealing medium;
(3) Excessive temperature of the liquid sealing medium;
(4) Low lube oil level;
(5) Low lube oil pressure, if pressurized lubricating system; and
(6) Excessive shaft bearing temperature.
(d) If a centrifugal compressor, fan,
or lobe blower handles vapor in the
vapor collection system, construction
of the blades and/or housing must meet
one of the following:
(1) Blades or housing of nonmetallic
construction;
(2) Blades and housing of nonferrous
material;
(3) Blades and housing of corrosion
resistant steel;
(4) Ferrous blades and housing with
one-half inch or more design tip clearance; or
(5) Blades of aluminum or magnesium alloy and a ferrous housing with
a nonferrous insert sleeve at the periphery of the impeller.
[CGD 88–102, 55 FR 25429, June 21, 1990, as
amended by CGD 96–026, 61 FR 33666, June 28,
1996; USCG–2010–0351, 75 FR 36284, June 25,
2010]
§ 154.828 Vapor recovery and vapor
destruction units.
(a) The inlet to a vapor recovery unit
which receives cargo vapor that has
not been inerted, enriched, or diluted
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Coast Guard, DHS
§ 154.850
in accordance with § 154.824 of this subpart must be fitted with one of the following:
(1) A detonation arrester;
(2) A flame arrester; or
(3) An explosion suppression system
acceptable to the Commandant (CG–
522).
(b) The inlet to a vapor destruction
unit must:
(1) Have a liquid seal; and
(2) Have two quick-closing stop
valves installed in the vapor line.
(c) A vapor destruction unit must:
(1) Not be within 30 meters (98.8 ft.)
of any tank vessel berth or mooring at
the facility;
(2) Have a flame arrester or detonation arrester fitted in the vapor line;
and
(3) Alarm and shut down when a
flame is detected on the flame arrester
or detonation arrester.
(d) When a vapor destruction unit
shuts down or has a flame-out condition the vapor destruction unit control
system must:
(1) Close the quick-closing stop
valves required by paragraph (b)(2) of
this section; and
(2) Close the remotely operated cargo
vapor shutoff valve required by
§ 154.810(a) of this subpart.
erowe on DSK5CLS3C1PROD with CFR
[CGD 88–102, 55 FR 25429, June 21, 1990, as
amended by CGD 96–026, 61 FR 33666, June 28,
1996; USCG–2010–0351, 75 FR 36284, June 25,
2010]
§ 154.840 Personnel training.
(a) A person in charge of a transfer
operation utilizing a vapor control system must have completed a training
program covering the particular system installed at the facility. Training
must include drills or demonstrations
using the installed vapor control system covering normal operations and
emergency procedures.
(b) The training program required by
paragraph (a) of this section must
cover the following subjects:
(1) Purpose of a vapor control system;
(2) Principles of the vapor control
system;
(3) Components of the vapor control
system;
(4) Hazards associated with the vapor
control system;
(5) Coast Guard regulations in this
subpart;
(6) Operating procedures, including:
(i) Testing and inspection requirements,
(ii) Pre-transfer procedures,
(iii) Connection sequence,
(iv) Start-up procedures, and
(v) Normal operations; and
(7) Emergency procedures.
§ 154.850 Operational requirements.
(a) A facility must receive vapors
only from a vessel which has its certificate of inspection or certificate of compliance endorsed in accordance with 46
CFR 39.10–13(e).
(b) The following must be performed
not more than 24 hours prior to each
transfer operation:
(1) All alarms and automatic shutdown systems required by this part
must be tested; and
(2) The analyzers required by
§ 154.820(a), § 154.824 (d) and (e) of this
subpart must be checked for calibration by use of a span gas.
(c) The position of all valves in the
vapor line between the vessel’s tanks
and the facility vapor collection system must be verified prior to the start
of the transfer operation.
(d) A tank barge overfill control system that meets the requirements of 46
CFR 39.20–9(b) must not be connected
to an overfill sensor circuit that exceeds the system’s rated cable length,
inductance, and capacitance.
(e) When vapor is being received from
a vessel with inerted cargo tanks, the
remotely operated cargo vapor shutoff
valve required by § 154.810(a) of this
subpart must not be opened until the
pressure at the facility vapor connection exceeds the pressure on the downstream side of the remotely operated
cargo vapor shutoff valve.
(f) The initial cargo transfer rate
must not exceed the rate agreed upon
at the pre-transfer conference required
by § 156.120(w) of this chapter and 46
CFR 39.30–1(h).
(g) The cargo transfer rate must not
exceed the maximum allowable transfer rate as determined by the lesser of
the following:
(1) A transfer rate corresponding to
the maximum vapor processing rate for
the vapor control system, as specified
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§ 154.1010
33 CFR Ch. I (7–1–10 Edition)
in the facility operations manual required by § 154.300 of this chapter; or
(2) The vessel’s maximum transfer
rate determined in accordance with 46
CFR 39.30–1(d).
(h) While transferring cargo to a vessel connected to a vapor control system, compressed air or gas may be used
to clear cargo hoses and loading arms,
but must not be used to clear cargo
lines.
(i) If one of the two analyzers required by § 154.824(d) of this subpart becomes inoperable during a transfer operation, the operation may continue
provided the remaining analyzer remains operational; however, no further
transfer operations may be started
until the inoperable analyzer is replaced or repaired.
(j) Whenever a condition results in a
shutdown of the vapor control system,
the person in charge shall immediately
terminate cargo loading.
(k) If it is suspected that a flare in
the vapor control system has had a
flare-back, or if a flame is detected on
the
flame
arrester
required
by
§ 154.828(c)(2) of this subpart, the transfer operation must be stopped and not
be restarted until the flame arrester
has been inspected and found to be in
satisfactory condition.
Subpart F—Response Plans for Oil
Facilities
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SOURCE: CGD 91–036, 61 FR 7917, Feb. 29,
1996, unless otherwise noted.
§ 154.1010 Purpose.
This subpart establishes oil spill response plan requirements for all marine transportation-related (MTR) facilities (hereafter also referred to as facilities) that could reasonably be expected to cause substantial harm or
significant and substantial harm to the
environment by discharing oil into or
on the navigable waters, adjoining
shorelines, or exclusive economic zone.
The development of a response plan
prepares the facility owner or operator
to respond to an oil spill. These requirements specify criteria to be used
during the planning process to determine the appropriate response resources. The specific criteria for response resources and their arrival
times are not performance standards.
The criteria are based on a set of assumptions that may not exist during
an actual oil spill incident.
§ 154.1015 Applicability.
(a) This subpart applies to all MTR
facilities that because of their location
could reasonably be expected to cause
at least substantial harm to the environment by discharging oil into or on
the navigable waters, adjoining shorelines, or exclusive economic zone.
(b) The following MTR facilities that
handle, store, or transport oil, in bulk,
could reasonably be expected to cause
substantial harm to the environment
by discharging oil into or on the navigable waters or adjoining shorelines
and are classified as substantial harm
MTR facilities:
(1) Fixed MTR onshore facilities capable of transferring oil to or from a
vessel with a capacity of 250 barrels or
more and deepwater ports;
(2) Mobile MTR facilities used or intended to be used to transfer oil to or
from a vessel with a capacity of 250
barrels or more; and
(3) Those MTR facilities specifically
designated as substantial harm facilities by the COTP under § 154.1016.
(c) The following MTR facilities that
handle, store, or transport oil in bulk
could not only reasonably be expected
to cause substantial harm, but also significant and substantial harm, to the
environment by discharging oil into or
on the navigable waters, adjoining
shorelines, or exclusive economic zone
and are classified as significant and
substantial harm MTR facilities:
(1) Deepwater ports, and fixed MTR
onshore facilities capable of transferring oil to or from a vessel with a capacity of 250 barrels or more except for
facilities that are part of a non-transportation-related fixed onshore facility
with a storage capacity of less than
42,000 gallons; and
(2) Those MTR facilities specifically
designated as significant and substantial harm facilities by the COTP under
§ 154.1016.
(d) An MTR facility owner or operator who believes the facility is improperly classified may request review
and reclassification in accordance with
§ 154.1075.
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Coast Guard, DHS
§ 154.1020
§ 154.1016 Facility classification by
COTP.
(a) The COTP may upgrade the classification of:
(1) An MTR facility not specified in
§ 154.1015 (b) or (c) to a facility that
could reasonably be expected to cause
substantial harm to the environment;
or
(2) An MTR facility specified in
§ 154.1015(b) to a facility that could reasonably be expected to cause significant and substantial harm to the environment.
(b) The COTP may downgrade, the
classification of:
(1) An MTR facility specified in
§ 154.1015(c) to a facility that could reasonably be expected to cause substantial harm to the environment; or
(2) An MTR facility specified in
§ 154.1015(b) to a facility that could not
reasonably be expected to cause substantial, or significant and substantial
harm to the environment.
(3) The COTP will consider downgrading an MTR facility’s classification only upon receiving a written request for a downgrade of classification
from the facility’s owner or operator.
(c) When changing a facility classification the COTP may, as appropriate,
consider all relevant factors including,
but not limited to: Type and quantity
of oils handled in bulk; facility spill
history; age of facility; proximity to
public and commercial water supply intakes; proximity to navigable waters
based on the definition of navigable
waters in 33 CFR 2.36; and proximity to
fish and wildlife and sensitive environments.
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[CGD 91–036, 61 FR 7917, Feb. 29, 1996, as
amended by USCG–2008–0179, 73 FR 35014,
June 19, 2008]
§ 154.1017 Response plan submission
requirements.
(a) The owner or operator of an MTR
facility identified only in § 154.1015(b),
or designated by the COTP as a substantial harm facility, shall prepare
and submit to the cognizant COTP a
response plan that meets the requirements of §§ 154.1030, 154.1040, 154.1045, or
§ 154.1047, as appropriate. This applies
to:
(1) A mobile MTR facility used or intended to be used to transfer oil to or
from a vessel with a capacity of 250
barrels or more; and
(2) A fixed MTR facility specifically
designated as a substantial harm facility by the COTP under § 154.1016.
(b) The owner or operator of an MTR
facility identified in § 154.1015(c) or designated by the COTP as a significant
and substantial harm facility shall prepare and submit for review and approval of the cognizant COTP a response plan that meets the requirements of §§ 154.1030, 154.1035, 154.1045, or
154.1047, as appropriate. This applies to:
(1) A fixed MTR facility capable of
transferring oil, in bulk, to or from a
vessel with a capacity of 250 barrels or
more; and
(2) An MTR facility specifically designated as a significant and substantial
harm facility by the COTP under
§ 154.1016.
(c) In addition to the requirements in
paragraphs (a) and (b) of this section,
the response plan for a mobile MTR facility must meet the requirements of
§ 154.1041 subpart F.
§ 154.1020
Definitions.
Except as otherwise defined in this
section, the definition in 33 CFR 154.105
apply to this subpart and subparts H
and I.
Adverse weather means the weather
conditions that will be considered when
identifying response systems and
equipment in a response plan for the
applicable operating environment. Factors to consider include, but are not
limited to, significant wave height as
specified in §§ 154.1045, 154.1047, 154.1225,
or 154.1325, as appropriate; ice conditions, temperatures, weather-related
visibility, and currents within the
COTP zone in which the systems or
equipment are intended to function.
Animal fat means a non-petroleum
oil, fat, or grease derived from animals,
and not specifically identified elsewhere in this part.
Average most probable discharge means
a discharge of the lesser of 50 barrels or
1 percent of the volume of the worst
case discharge.
Captain of the Port (COTP) Zone
means a zone specified in 33 CFR part
3 and, where applicable, the seaward
extension of that zone to the outer
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§ 154.1020
33 CFR Ch. I (7–1–10 Edition)
boundary of the exclusive economic
zone (EEZ).
Complex means a facility possessing a
combination of marine-transportation
related and non-transportation-related
components that is subject to the jurisdiction of more than one Federal agency under section 311(j) of the Clean
Water Act.
Dispersant-application platform means
the vessel or aircraft outfitted with the
dispersant-application equipment acting as the delivery system for the dispersant onto the oil spill.
Dispersant Mission Planner 2 or
(DMP2)
means
an
Internetdownloadable application that estimates EDAC for different dispersant
response systems. The NSFCC will use
DPMP2 for evaluating OSRO dispersant
classification levels.
Effective Daily Application Capacity or
EDAC means the estimated amount of
dispersant that can be applied to a discharge by an application system given
the availability of supporting dispersant stockpiles, when operated in accordance with approved standards and
within acceptable environmental conditions.
Exclusive economic zone (EEZ) means
the zone contiguous to the territorial
sea of the United States extending to a
distance up to 200 nautical miles from
the baseline from which the breadth of
the territorial sea is measured.
Facility that could reasonably be expected to cause significant and substantial harm means any MTR facility (including piping and any structures that
are used for the transfer of oil between
a vessel and a facility) classified as a
‘‘significant and substantial harm’’ facility under § 154.1015(c) and § 154.1216.
Facility that could reasonably be expected to cause substantial harm means
any MTR facility classified as a ‘‘substantial
harm’’
facility
under
§ 154.1015(b) and § 154.1216.
Fish and Wildlife and Sensitive Environment means areas that may be identified by either their legal designation
or by Area Committees in the applicable Area Contingency Plan (ACP) (for
planning) or by members of the Federal
On-Scene Coordinator’s spill response
structure (during responses). These
areas may include: Wetlands, national
and state parks, critical habitats for
endangered or threatened species, wilderness and natural resource areas,
marine sanctuaries and estuarine reserves, conservation areas, preserves,
wildlife areas, wildlife refuges, wild
and scenic rivers, areas of economic
importance, recreational areas, national forests, Federal and state lands
that are research areas, heritage program areas, land trust areas, and historical and archaeological sites and
parks. These areas may also include
unique habitats such as: aquaculture
sites and agricultural surface water intakes, bird nesting areas, critical biological resource areas, designated migratory routes, and designated seasonal habitats.
Great Lakes means Lakes Superior,
Michigan, Huron, Erie, and Ontario,
their connecting and tributary waters,
the Saint Lawrence River as far as
Saint Regis, and adjacent port areas.
Gulf Coast means, for the purposes of
dispersant-application
requirements,
the region encompassing the following
Captain of the Port Zones:
(1) Corpus Christi, TX.
(2) Houston/Galveston, TX.
(3) Port Arthur, TX.
(4) Morgan City, LA.
(5) New Orleans, LA.
(6) Mobile, AL.
(7) St. Petersburg, FL.
Higher volume port area means the following ports:
(1) Boston, MA.
(2) New York, NY.
(3) Delaware Bay and River to Philadelphia, PA.
(4) St. Croix, VI.
(5) Pascagoula, MS.
(6) Mississippi River from Southwest
Pass, LA. to Baton Rouge, LA.
(7) Louisiana Offshore Oil Port
(LOOP), LA.
(8) Lake Charles, LA.
(9) Sabine-Neches River, TX.
(10) Galveston Bay and Houston Ship
Channel, TX.
(11) Corpus Christi, TX.
(12) Los Angeles/Long Beach harbor,
CA.
(13) San Francisco Bay, San Pablo
Bay, Carquinez Strait, and Suisun Bay
to Antioch, CA.
(14) Straits of Juan De Fuca from
Port Angeles, WA, to and including
Puget Sound, WA.
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Coast Guard, DHS
§ 154.1020
(15) Prince William Sound, AK.
Inland area means the area shoreward
of the boundary lines defined in 46 CFR
part 7, except in the Gulf of Mexico. In
the Gulf of Mexico, it means the area
shoreward of the lines of demarcation
(COLREG lines) defined in §§ 80.740
through 80.850 of this chapter. The inland area does not include the Great
Lakes.
Marine transportation-related facility
(MTR facility) means any onshore facility or segment of a complex regulated under section 311(j) of the Federal
Water Pollution Control Act (FWPCA)
by two or more Federal agencies, including piping and any structure used
or intended to be used to transfer oil to
or from a vessel, subject to regulation
under this part and any deepwater port
subject to regulation under part 150 of
this chapter. For a facility or segment
of a complex regulated by two or more
Federal agencies under section 311(j) of
the FWPCA, the MTR portion of the
complex extends from the facility oil
transfer system’s connection with the
vessel to the first valve inside the secondary containment surrounding tanks
in the non-transportation-related portion of the facility or, in the absence of
secondary containment, to the valve or
manifold adjacent to the tanks comprising the non-transportation-related
portion of the facility, unless another
location has otherwise been agreed to
by the COTP and the appropriate Federal official.
Maximum extent practicable means the
planned capability to respond to a
worst case discharge in adverse weather, as contained in a response plan that
meets the criteria in this subpart or in
a specific plan approved by the cognizant COTP.
Maximum most probable discharge
means a discharge of the lesser of 1,200
barrels or 10 percent of the volume of a
worst case discharge.
Nearshore area means the area extending seaward 12 miles from the
boundary lines defined in 46 CFR part
7, except in the Gulf of Mexico. In the
Gulf of Mexico, it means the area extending seaward 12 miles from the line
of demarcation (COLREG lines) defined
in §§ 80.740–80.850 of this chapter.
Non-persistent or Group I oil means a
petroleum-based oil that, at the time
of shipment, consists of hydrocarbon
fractions—
(1) At least 50 percent of which by
volume, distill at a temperature of 340
degrees C (645 degrees F); and
(2) At least 95 percent of which by
volume, distill at a temperature of 370
degrees C (700 degrees F).
Ocean means the offshore area and
nearshore area as defined in this subpart.
Offshore area means the area beyond
12 nautical miles measured from the
boundary lines defined in 46 CFR part 7
extending seaward to 50 nautical miles,
except in the Gulf of Mexico. In the
Gulf of Mexico, it is the area beyond 12
nautical miles of the line of demarcation (COLREG lines) defined in
§§ 80.740–80.850 of this chapter extending
seaward to 50 nautical miles.
Oil means oil of any kind or in any
form, including, but not limited to, petroleum, fuel oil, sludge, oil refuse, oil
mixed with wastes other than dredge
spoil.
Oil spill removal organization (OSRO)
means an entity that provides response
resources.
On-Scene Coordinator (OSC) means the
definition in the National Oil and Hazardous Substances Pollution Contingency Plan (40 CFR part 300).
Operating area means Rivers and Canals, Inland, Nearshore, Great Lakes,
or Offshore geographic location(s) in
which a facility is handling, storing, or
transporting oil.
Operating environment means Rivers
and Canals, Inland, Great Lakes, or
Ocean. These terms are used to define
the conditions in which response equipment is designed to function.
Operating in compliance with the plan
means operating in compliance with
the provisions of this subpart including, ensuring the availability of the response resources by contract or other
approved means, and conducting the
necessary training and drills.
Operational effectiveness monitoring
means monitoring concerned primarily
with determining whether the dispersant was properly applied and how the
dispersant is affecting the oil.
Other non-petroleum oil means a nonpetroleum oil of any kind that is not
generally an animal fat or vegetable
oil.
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§ 154.1025
33 CFR Ch. I (7–1–10 Edition)
Persistent oil means a petroleumbased oil that does not meet the distillation criteria for a non-persistent
oil. For the purposes of this subpart,
persistent oils are further classified
based on specific gravity as follows:
(1) Group II—specific gravity of less
than .85.
(2) Group III—specific gravity equal
to or greater than .85 and less than .95.
(3) Group IV—specific gravity equal
to or greater than .95 and less than or
equal to 1.0.
(4) Group V—specific gravity greater
than 1.0.
Pre-authorization for dispersant use
means an agreement, adopted by a regional response team in coordination
with area committees, which authorizes the use of dispersants at the discretion of the Federal On-Scene Coordinator without the further approval of
other Federal or State authorities.
These pre-authorization areas are generally limited to particular geographic
areas within each region.
Primary dispersant staging site means a
site designated within a Captain of the
Port zone that has been identified as a
forward staging area for dispersant application platforms and the loading of
dispersant stockpiles. Primary staging
sites are typically the planned locations where platforms load or reload
dispersants before departing for application at the site of the discharge and
may not be the locations where dispersant stockpiles are stored or application platforms are home-based.
Qualified individual and alternate
qualified individual means a person located in the United States who meets
the requirements of § 154.1026.
Response activities means the containment and removal of oil from the land,
water, and shorelines, the temporary
storage and disposal of recovered oil, or
the taking of other actions as necessary to minimize or mitigate damage
to the public health or welfare or the
environment.
Response resources means the personnel, equipment, supplies, and other
capability necessary to perform the response activities identified in a response plan.
Rivers and canals means a body of
water confined within the inland area,
including the Intracoastal Waterways
and other waterways artificially created for navigation, that has a project
depth of 12 feet or less.
Specific gravity means the ratio of the
mass of a given volume of liquid at 15
°C (60 °F) to the mass of an equal volume of pure water at the same temperature.
Spill management team means the personnel identified to staff the organizational structure identified in a response plan to manage response plan
implementation.
Substantial threat of a discharge means
any incident or condition involving a
facility that may create a risk of discharge of oil. Such incidents include,
but are not limited to storage tank or
piping failures, above ground or underground leaks, fires, explosions, flooding, spills contained within the facility, or other similar occurrences.
Tier means the combination of required response resources and the
times within which the resources must
arrive on scene.
[NOTE: Tiers are applied in three categories:
(1) Higher Volume Port Areas,
(2) Great Lakes, and
(3) All other operating environments, including rivers and canals, inland, nearshore,
and offshore areas.
Appendix C, Table 4 of this part, provides
specific guidance on calculating response resources. Sections 154.1045(f) and 154.1135, set
forth the required times within which the response resources must arrive on-scene.]
Vegetable oil means a non-petroleum
oil or fat derived from plant seeds,
nuts, kernels or fruits, and not specifically identified elsewhere in this part.
Worst case discharge means in the case
of an onshore facility and deepwater
port, the largest foreseeable discharge
in adverse weather conditions meeting
the requirements of § 154.1029.
[CGD 91–036, 61 FR 7917, Feb. 29, 1996, as
amended by USCG–1999–5149, 65 FR 40825,
June 30, 2000; USCG–2001–8661, 74 FR 45023,
Aug. 31, 2009]
§ 154.1025 Operating restrictions and
interim operating authorization.
(a) The owner or operator of an MTR
facility who submitted a response plan
prior to May 29, 1996, may elect to comply with any of the provisions of this
final rule by revising the appropriate
section of the previously submitted
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§ 154.1026
plan in accordance with § 154.1065. An
owner or operator of an MTR facility
who elects to comply with all sections
of this final rule must resubmit the
plan in accordance with § 154.1060 of
this part.
(b) No facility subject to this subpart
may handle, store, or transport oil unless it is operating in full compliance
with a submitted response plan. No facility categorized under § 154.1015(c) as
a significant and substantial harm facility may handle, store, or transport
oil unless the submitted response plan
has been approved by the COTP. The
owner or operator of each new facility
to which this subpart applies must submit a response plan meeting the requirements listed in § 154.1017 not less
than 60 days prior to handling, storing,
or transporting oil. Where applicable,
the response plan shall be submitted
along with the letter of intent required
under § 154.110.
(c) Notwithstanding the requirements of paragraph (b) of this section,
a facility categorized under § 154.1015(c)
as a significant and substantial harm
facility may continue to handle, store,
or transport oil for 2 years after the
date of submission of a response plan,
pending approval of that plan. To continue to handle, store, or transport oil
without a plan approved by the COTP,
the facility owner or operator shall
certify in writing to the COTP that the
owner or operator has ensured, by contract or other approved means as described in § 154.1028(a), the availability
of the necessary private personnel and
equipment to respond, to the maximum
extend practicable to a worst case discharge or substantial threat of such a
discharge from the facility. Provided
that the COTP is satisfied with the certification of response resources provided by the owner or operator of the
facility, the COTP will provide written
authorization for the facility to handle, store, or transport oil while the
submitted response plan is being reviewed. Pending approval of the submitted response plan, deficiencies
noted by the COTP must be corrected
in accordance with § 154.1070.
(d) A facility may not continue to
handle, store, or transport oil if—
(1) The COTP determines that the response resources identified in the facil-
ity certification statement or reference
response plan do not substantially
meet the requirements of this subpart;
(2) The contracts or agreements cited
in the facility’s certification statement
or referenced response plans are no
longer valid;
(3) The facility is not operating in
compliance with the submitted plan;
(4) The response plan has not been resubmitted or approved within the last 5
years; or
(5) The period of the authorization
under paragraph (c) of this section has
expired.
§ 154.1026 Qualified individual and alternate qualified individual.
(a) The response plan must identify a
qualified individual and at least one alternate who meet the requirements of
this section. The qualified individual
or alternate must be available on a 24hour basis and be able to arrive at the
facility in a reasonable time.
(b) The qualified individual and alternate must:
(1) Be located in the United States;
(2) Speak fluent English;
(3) Be familiar with the implementation of the facility response plan; and
(4) Be trained in the responsibilities
of the qualified individual under the response plan.
(c) The owner or operator shall provide each qualified individual and alternate qualified individual identified
in the plan with a document designating them as a qualified individual
and specifying their full authority to:
(1) Activate and engage in contracting with oil spill removal organization(s);
(2) Act as a liaison with the
predesignated Federal On-Scene Coordinator (OSC); and
(3) Obligate funds required to carry
out response activities.
(d) The owner or operator of a facility may designate an organization to
fulfill the role of the qualified individual and the alternate qualified individual. The organization must then
identify a qualified individual and at
least one alternate qualified individual
who meet the requirements of this section. The facility owner or operator is
required to list in the response plan the
organization, the person identified as
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§ 154.1028
33 CFR Ch. I (7–1–10 Edition)
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the qualified individual, and the person
or person(s) identified as the alternate
qualified individual(s).
(e) The qualified individual is not responsible for—
(1) The adequacy of response plans
prepared by the owner or operator; or
(2) Contracting or obligating funds
for response resources beyond the authority contained in their designation
from the owner or operator of the facility.
(f) The liability of a qualified individual is considered to be in accordance with the provisions of 33 USC
1321(c)(4).
§ 154.1028 Methods of ensuring the
availability of response resources
by contract or other approved
means.
(a) When required in this subpart, the
availability of response resources must
be ensured by the following methods:
(1) A written contractual agreement
with an oil spill removal organization.
The agreement must identify and ensure the availability of specified personnel and equipment required under
this subpart within stipulated response
times in the specified geographic areas;
(2) Certification by the facility owner
or operator that specified personnel
and equipment required under this subpart are owned, operated, or under the
direct control of the facility owner or
operator, and are available within stipulated response times in the specified
geographic areas;
(3) Active membership in a local or
regional oil spill removal organization
that has identified specified personnel
and equipment required under this subpart that are available to respond to a
discharge within stipulated response
times in the specified geographic areas;
(4) A document which—
(i) Identifies the personnel, equipment, and services capable of being
provided by the oil spill removal organization within stipulated response
times in the specified geographic areas;
(ii) Sets out the parties’ acknowledgment that the oil spill removal organization intends to commit the resources
in the event of a response;
(iii) Permits the Coast Guard to
verify the availability of the identified
response resources through tests, inspections, and drills; and
(iv) Is referenced in the response
plan; or
(5) The identification of an oil spill
removal organization with specified
equipment and personnel available
within stipulated response times in
specified geographic areas. The organization must provide written consent to
being identified in the plan.
(b) The contracts and documents required in paragraph (a) of this section
must be retained at the facility and
must be produced for review upon request by the COTP.
§ 154.1029 Worst case discharge.
(a) The response plan must use the
appropriate criteria in this section to
develop the worst case discharge.
(b) For the MTR segment of a facility, not less than—
(1) Where applicable, the loss of the
entire capacity of all in-line and break
out tank(s) needed for the continuous
operation of the pipelines used for the
purposes of handling or transporting
oil, in bulk, to or from a vessel regardless of the presence of secondary containment; plus
(2) The discharge from all piping carrying oil between the marine transfer
manifold and the non-transportationrelated portion of the facility. The discharge from each pipe is calculated as
follows: The maximum time to discover the release from the pipe in
hours, plus the maximum time to shut
down flow from the pipe in hours
(based on historic discharge data or the
best estimate in the absence of historic
discharge data for the facility) multiplied by the maximum flow rate expressed in barrels per hour (based on
the maximum relief valve setting or
maximum system pressure when relief
valves are not provided) plus the total
line drainage volume expressed in barrels for the pipe between the marine
manifold and the non-transportationrelated portion of the facility; and
(c) For a mobile facility it means the
loss of the entire contents of the container in which the oil is stored or
transported.
§ 154.1030 General response plan contents.
(a) The plan must be written in
English.
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§ 154.1035
(b) A response plan must be divided
into the sections listed in this paragraph and formatted in the order specified herein unless noted otherwise. It
must also have some easily found
marker identifying each section listed
below. The following are the sections
and subsections of a facility response
plan:
(1) Introduction and plan contents.
(2) Emergency response action plan:
(i) Notification procedures.
(ii) Facility’s spill mitigation procedures.
(iii) Facility’s response activities.
(iv) Fish and wildlife and sensitive
environments.
(v) Disposal plan.
(3) Training and Exercises:
(i) Training procedures.
(ii) Exercise procedures.
(4) Plan review and update procedures.
(5) Appendices.
(i) Facility-specific information.
(ii) List of contacts.
(iii) Equipment lists and records.
(iv) Communications plan.
(v) Site-specific safety and health
plan.
(vi) List of acronyms and definitions.
(vii) A geographic-specific appendix
for each zone in which a mobile facility
operates.
(c) The required contents for each
section and subsection of the plan are
contained in §§ 154.1035, 154.1040, and
154.1041, as appropriate.
(d) The sections and subsections of
response plans submitted to the COTP
must contain at a minimum all the information
required
in
§§ 154.1035,
154.1040, and 154.1041, as appropriate. It
may contain other appropriate sections, subsections, or information that
are required by other Federal, State,
and local agencies.
(e) For initial and subsequent submission, a plan that does not follow the
format specified in paragraph (b) of
this section must be supplemented
with a detailed cross-reference section
to identify the location of the applicable sections required by this subpart.
(f) The information contained in a response plan must be consistent with
the National Oil and Hazardous Substances Pollution Contingency Plan
(NCP) (40 CFR part 300) and the Area
Contingency Plan(s) (ACP) covering
the area in which the facility operates.
Facility owners or operators shall ensure that their response plans are in
accordance with the ACP in effect 6
months prior to initial plan submission
or the annual plan review required
under § 154.1065(a). Facility owners or
operators are not required to, but may
at their option, conform to an ACP
which is less than 6 months old at the
time of plan submission.
§ 154.1035 Specific requirements for facilities that could reasonably be expected to cause significant and substantial harm to the environment.
(a) Introduction and plan content. This
section of the plan must include facility and plan information as follows:
(1) The facility’s name, street address, city, county, state, ZIP code, facility telephone number, and telefacsimile number, if so equipped. Include mailing address if different from
street address.
(2) The facility’s location described
in a manner that could aid both a reviewer and a responder in locating the
specific facility covered by the plan,
such as, river mile or location from a
known landmark that would appear on
a map or chart.
(3) The name, address, and procedures
for contacting the facility’s owner or
operator on a 24-hour basis.
(4) A table of contents.
(5) During the period that the submitted plan does not have to conform
to the format contained in this subpart, a cross index, if appropriate.
(6) A record of change(s) to record information on plan updates.
(b) Emergency Response Action Plan.
This section of the plan must be organized in the subsections described in
this paragraph:
(1) Notification procedures. (i) This
subsection must contain a prioritized
list identifying the person(s), including
name, telephone number, and their role
in the plan, to be notified of a discharge or substantial threat of a discharge of oil. The telephone number
need not be provided if it is listed separately in the list of contacts required
in the plan. This Notification Procedures listing must include—
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§ 154.1035
33 CFR Ch. I (7–1–10 Edition)
(A) Facility response personnel, the
spill management team, oil spill removal organizations, and the qualified
individual(s) and the designated alternate(s); and
(B) Federal, State, or local agencies,
as required.
(ii) This subsection must include a
form, such as that depicted in Figure 1,
which contains information to be provided in the initial and follow-up notifications to Federal, State, and local
agencies. The form shall include notification of the National Response Center
as required in part 153 of this chapter.
Copies of the form also must be placed
at the location(s) from which notification may be made. The initial notification form must include space for the
information contained in Figure 1. The
form must contain a prominent statement that initial notification must not
be delayed pending collection of all information.
FIGURE 1—INFORMATION ON DISCHARGE *
[Involved Parties]
(A) Reporting party
(B) Suspected responsible party
Name
Phones () –
Company
Position
Address
Address
Name
Phones () –
Company
Organization Type:
Private citizen
Private enterprise
Public utility
Local government
State government
Federal government
City
State
Zip
City
State
Zip
* It is not necessary to wait for all information before calling NRC. National Response Center—1–800–424–8802 or direct telephone: 202–267–2675.
Were materials Discharged (Y/N)?
Calling for Responsible Party (Y/N)
Incident Description
Source and/or Cause of Incident
Date Cause
-
Time:
Incident Address/Location Nearest City
Distance from City
Storage Tank Container Type—Above ground (Y/N) Below ground (Y/N) Unknown
Facility Capacity
Tank Capacity
Latitude Degrees
Longitude Degrees
Mile Post or River Mile
Materials
Discharge Unit of Quantity Measure Discharged Material Quantity in Water
Response Action
Actions Taken to Correct or Mitigate Incident
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Number of Injuries Number of Fatalities
Were there Evacuations (Y/N/U)? Number Evacuated
Was there any Damage (Y/N/U)? Damage in Dollars
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Additional Information
Any information about the Incident not recorded elsewhere in the report
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(2) Facility’s spill mitigation procedures.
(i) This subsection must describe the
volume(s) and oil groups that would be
involved in the—
(A) Average most probable discharge
from the MTR facility;
(B) Maximum most probable discharge from the MTR facility;
(C) Worst case discharge from the
MTR facility; and
(D) Where applicable, the worst case
discharge from the non-transportationrelated facility. This must be the same
volume provided in the response plan
for the non-transportation-related facility.
(ii) This subsection must contain
prioritized procedures for facility personnel to mitigate or prevent any discharge or substantial threat of a discharge of oil resulting from operational activities associated with internal or external facility transfers including specific procedures to shut
down affected operations. Facility personnel responsible for performing specified procedures to mitigate or prevent
any discharge or potential discharge
shall be identified by job title. A copy
of these procedures shall be maintained
at the facility operations center. These
procedures must address actions to be
taken by facility personnel in the
event of a discharge, potential discharge, or emergency involving the following equipment and scenarios:
(A) Failure of manifold, mechanical
loading arm, other transfer equipment,
or hoses, as appropriate;
(B) Tank overfill;
(C) Tank failure;
(D) Piping rupture;
(E) Piping leak, both under pressure
and not under pressure, if applicable;
(F) Explosion or fire; and
(G) Equipment failure (e.g. pumping
system failure, relief valve failure, or
other general equipment relevant to
operational activities associated with
internal or external facility transfers.)
(iii) This subsection must contain a
listing of equipment and the responsibilities of facility personnel to mitigate an average most probable discharge.
(3) Facility’s response activities. (i)
This subsection must contain a description of the facility personnel’s responsibilities to initiate a response and
supervise response resources pending
the arrival of the qualified individual.
(ii) This subsection must contain a
description of the responsibilities and
authority of the qualified individual
and alternate as required in § 154.1026.
(iii) This subsection must describe
the organizational structure that will
be used to manage the response actions. This structure must include the
following functional areas.
(A) Command and control;
(B) Public information;
(C) Safety;
(D) Liaison with government agencies;
(E) Spill Operations;
(F) Planning;
(G) Logistics support; and
(H) Finance.
(iv) This subsection of the plan must
identify the oil spill removal organizations and the spill management team
that will be capable of providing the
following resources:
(A) Equipment and supplies to meet
the requirements of §§ 154.1045, 154.1047,
or subparts H or I of this part, as appropriate.
(B) Trained personnel necessary to
continue operation of the equipment
and staff the oil spill removal organization and spill management team for
the first 7 days of the response.
(v) This section must include job descriptions for each spill management
team member within the organizational structure described in paragraph
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§ 154.1035
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(b)(3)(iii) of this section. These job descriptions must include the responsibilities and duties of each spill management team member in a response action.
(vi) For facilities that handle, store,
or transport group II through group IV
petroleum oils, and that operate in waters where dispersant use is pre-authorized, this subsection of the plan must
also separately list the resource providers and specific resources, including
appropriately trained dispersant-application personnel, necessary to provide
the dispersant capabilities required in
this subpart. All resource providers and
resources must be available by contract or other approved means as described in § 154.1028(a). The dispersant
resources to be listed within this section must include the following:
(A) Identification of each primary
dispersant staging site to be used by
each dispersant-application platform
to meet the requirements of this subpart.
(B) Identification of the platform
type, resource-providing organization,
location, and dispersant payload for
each dispersant-application platform
identified. Location data must identify
the distance between the platform’s
home base and the identified primary
dispersant staging site for this section.
(C) For each unit of dispersant stockpile required to support the effective
daily application capacity (EDAC) of
each dispersant-application platform
necessary to sustain each intended response tier of operation, identify the
dispersant product resource provider,
location, and volume. Location data
must include the stockpile’s distance
to the primary staging sites where the
stockpile would be loaded onto the corresponding platforms.
(D) If an oil spill removal organization has been evaluated by the Coast
Guard, and its capability is equal to or
exceeds the response capability needed
by the owner or operator, the section
may identify only the oil spill removal
organization, and not the information
required in paragraphs (b)(3)(vi)(A)
through (b)(3)(vi)(C) of this section.
(vii) This subsection of the plan must
also separately list the resource providers and specific resources necessary
to provide aerial oil tracking capabili-
ties required in this subpart. The oil
tracking resources to be listed within
this section must include the following:
(A) The identification of a resource
provider; and
(B) Type and location of aerial surveillance aircraft that are ensured
available, through contract or other
approved means, to meet the oil tracking requirements of § 154.1045(j).
(viii) For mobile facilities that operate in more than one COTP zone, the
plan must identify the oil spill removal
organization and the spill management
team in the applicable geographic-specific appendix. The oil spill removal organization(s) and the spill management
team discussed in paragraph (b)(3)(iv)
of this section must be included for
each COTP zone in which the facility
will handle, store, or transport oil in
bulk.
(ix) For mobile facilities that operate
in more than one COTP zone, the plan
must identify the oil spill removal organization and the spill management
team in the applicable geographic-specific appendix. The oil spill removal organization(s) and the spill management
team
discussed
in
paragraph
(b)(3)(iv)(A) of this section must be included for each COTP zone in which the
facility will handle, store, or transport
oil in bulk.
(4) Fish and wildlife and sensitive environments. (i) This section of the plan
must identify areas of economic importance and environmental sensitivity,
as identified in the ACP, which are potentially impacted by a worst case discharge. ACPs are required under section 311(j)(4) of the FWPCA to identify
fish and wildlife and sensitive environments. The applicable ACP shall be
used to designate fish and wildlife and
sensitive environments in the plan.
Changes to the ACP regarding fish and
wildlife and sensitive environments
shall be included in the annual update
of the response plan, when available.
(ii) For a worst case discharge from
the facility, this section of the plan
must—
(A) List all fish and wildlife and sensitive environments identified in the
ACP which are potentially impacted by
a discharge of persistent oils, non-persistent oils, or non-petroleum oils.
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(B) Describe all the response actions
that the facility anticipates taking to
protect these fish and wildlife and sensitive environments.
(C) Contain a map or chart showing
the location of those fish and wildlife
and sensitive environments which are
potentially impacted. The map or chart
shall also depict each response action
that the facility anticipates taking to
protect these areas. A legend of activities must be included on the map page.
(iii) For a worst case discharge, this
section must identify appropriate
equipment and required personnel,
available by contract or other approved
means as described in § 154.1028, to protect fish and wildlife and sensitive environments which fall within the distances calculated using the methods
outlined in this paragraph as follows:
(A) Identify the appropriate equipment and required personnel to protect
all fish and wildlife and sensitive environments in the ACP for the distances,
as calculated in paragraph (b)(4)(iii)(B)
of this section, that the persistent oils,
non-persistent oils, or non-petroleum
oils are likely to travel in the noted geographic area(s) and number of days
listed in table 2 of appendix C of this
part;
(B) Calculate the distances required
by paragraph (b)(4)(iii)(A) of this section by selecting one of the methods
described in this paragraph;
(1) Distances may be calculated as
follows:
(i) For persistent oils and non-petroleum oils discharged into non-tidal waters, the distance from the facility
reached in 48 hours at maximum current.
(ii) For persistent and non-petroleum
oils discharged into tidal waters, 15
miles from the facility down current
during ebb tide and to the point of
maximum tidal influence or 15 miles,
whichever is less, during flood tide.
(iii) For non-persistent oils discharged into non-tidal waters, the distance from the facility reached in 24
hours at maximum current.
(iv) For non-persistent oils discharged into tidal waters, 5 miles from
the facility down current during ebb
tide and to the point of maximum tidal
influence or 5 miles, whichever is less,
during flood tide.
(2) A spill trajectory or model may be
substituted for the distances calculated
under paragraph (b)(4)(iii)(B)(l) of this
section. The spill trajectory or model
must be acceptable to the COTP.
(3) The procedures contained in the
Environmental Protection’s Agency’s
regulations on oil pollution prevention
for non-transportation-related onshore
facilities at 40 CFR part 112, appendix
C, Attachment C-III may be substituted for the distances listed in nontidal and tidal waters; and
(C) Based on historical information
or a spill trajectory or model, the
COTP may require the additional fish
and wildlife and sensitive environments also be protected.
(5) Disposal Plan. This subsection
must describe any actions to be taken
or procedures to be used to ensure that
all recovered oil and oil contaminated
debris produced as a result of any discharge are disposed according to Federal, state, or local requirements.
(c) Training and exercises. This section
must be divided into the following two
subsections:
(1) Training procedures. This subsection must describe the training procedures and programs of the facility
owner or operator to meet the requirements in § 154.1050.
(2) Exercise procedures. This subsection must describe the exercise program to be carried out by the facility
owner or operator to meet the requirements in § 154.1055.
(d) Plan review and update procedures.
This section must address the procedures to be followed by the facility
owner or operator to meet the requirements of § 154.1065 and the procedures
to be followed for any post-discharge
review of the plan to evaluate and validate its effectiveness.
(e) Appendices. This section of the response plan must include the appendices described in this paragraph.
(1) Facility-specific information. This
appendix must contain a description of
the facility’s principal characteristics.
(i) There must be a physical description of the facility including a plan of
the facility showing the mooring areas,
transfer locations, control stations, locations of safety equipment, and the
location and capacities of all piping
and storage tanks.
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§ 154.1035
33 CFR Ch. I (7–1–10 Edition)
(ii) The appendix must identify the
sizes, types, and number of vessels that
the facility can transfer oil to or from
simultaneously.
(iii) The appendix must identify the
first valve(s) on facility piping separating the transportation-related portion of the facility from the non-transportation-related portion of the facility, if any. For piping leading to a
manifold located on a dock serving
tank vessels, this valve is the first
valve inside the secondary containment required by 40 CFR part 112.
(iv) The appendix must contain information on the oil(s) and hazardous material handled, stored, or transported
at the facility in bulk. A material safety data sheet meeting the requirements of 29 CFR 1910.1200, 33 CFR
154.310(a)(5) or an equivalent will meet
this requirement. This information can
be maintained separately providing it
is readily available and the appendix
identifies its location. This information must include—
(A) The generic or chemical name;
(B) A description of the appearance
and odor;
(C) The physical and chemical characteristics;
(D) The hazards involved in handling
the oil(s) and hazardous materials.
This shall include hazards likely to be
encountered if the oil(s) and hazardous
materials come in contact as a result
of a discharge; and
(E) A list of firefighting procedures
and extinguishing agents effective with
fires involving the oil(s) and hazardous
materials.
(v) The appendix may contain any
other information which the facility
owner or operator determines to be
pertinent to an oil spill response.
(2) List of contacts. This appendix
must include information on 24-hour
contact of key individuals and organizations. If more appropriate, this information may be specified in a geographic-specific appendix. The list
must include—
(i) The primary and alternate qualified individual(s) for the facility;
(ii) The contact(s) identified under
paragraph (b)(3)(iv) of this section for
activation of the response resources;
and
(iii) Appropriate Federal, State, and
local officials.
(3) Equipment list and records. This appendix must include the information
specified in this paragraph.
(i) The appendix must contain a list
of equipment and facility personnel required to respond to an average most
probable discharge, as defined in
§ 154.1020. The appendix must also list
the location of the equipment.
(ii) The appendix must contain a detailed listing of all the major equipment identified in the plan as belonging to an oil spill removal organization(s) that is available, by contract or
other approved means as described in
§ 154.1028(a), to respond to a maximum
most probable or worst case discharge,
as defined in § 154.1020. The detailed
listing of all major equipment may be
located in a separate document referenced by the plan. Either the appendix or the separate document referenced in the plan must provide the
location of the major response equipment.
(iii) It is not necessary to list response equipment from oil spill removal organization(s) when the organization has been classified by the Coast
Guard and their capacity has been determined to equal or exceed the response capability needed by the facility. For oil spill removal organization(s) classified by the Coast Guard,
the classification must be noted in this
section of the plan. When it is necessary for the appendix to contain a
listing of response equipment, it shall
include all of the following items that
are identified in the response plan:
Skimmers; booms; dispersant application, in-situ burning, bioremediation
equipment and supplies, and other
equipment used to apply other chemical agents on the NCP Product Schedule (if applicable); communications,
firefighting, and beach cleaning equipment; boats and motors; disposal and
storage equipment; and heavy equipment. The list must include for each
piece of equipment—
(A) The type, make, model, and year
of manufacture listed on the nameplate
of the equipment;
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(B) For oil recovery devices, the effective daily recovery rate, as determined using section 6 of appendix C of
this part;
(C) For containment boom, the overall boom height (draft and freeboard)
and type of end connectors;
(D) The spill scenario in which the
equipment will be used for or which it
is contracted;
(E) The total daily capacity for storage and disposal of recovered oil;
(F) For communication equipment,
the type and amount of equipment intended for use during response activities. Where applicable, the primary and
secondary radio frequencies must be
specified.
(G) Location of the equipment; and
(H) The date of the last inspection by
the oil spill removal organization(s).
(4) Communications plan. This appendix must describe the primary and alternate method of communication during discharges, including communications at the facility and at remote locations within the areas covered by the
response plan. The appendix may refer
to additional communications packages provided by the oil spill removal
organization. This may reference another existing plan or document.
(5) Site-specific safety and health plan.
This appendix must describe the safety
and health plan to be implemented for
any response location(s). It must provide as much detailed information as is
practicable in advance of an actual discharge. This appendix may reference
another existing plan requiring under
29 CFR 1910.120.
(6) List of acronyms and definitions.
This appendix must list all acronyms
used in the response plan including any
terms or acronyms used by Federal,
State, or local governments and any
operational terms commonly used at
the facility. This appendix must include all definitions that are critical to
understanding the response plan.
[CGD 91–036, 61 FR 7917, Feb. 29, 1996, as
amended by USCG–2000–7223, 65 FR 40058,
June 29, 2000; USCG–2001–9286, 66 FR 33641,
June 25, 2001; USCG–2008–0179, 73 FR 35014,
June 19, 2008; USCG–2001–8661, 74 FR 45023,
Aug. 31, 2009]
§ 154.1040 Specific requirements for facilities that could reasonably be expected to cause substantial harm to
the environment.
(a) The owner or operator of a facility that, under § 154.1015, could reasonably be expected to cause substantial
harm to the environment, shall submit
a response plan that meets the requirements of § 154.1035, except as modified
by this section.
(b) The facility’s response activities
section of the response plan need not
list the facility or corporate organizational structure that will be used to
manage the response, as required by
§ 154.1035(b)(3)(iii).
(c) The owner or operator of a facility must ensure the availability of response resources required to be identified in § 154.1035(b)(3)(iv) by contract or
other approved means described in
§ 154.1028.
(d) A facility owner or operator must
have at least 200 feet of containment
boom and the means of deploying and
anchoring the boom available at the
spill site within 1 hour of the detection
of a spill to respond to the average
most probable discharge in lieu of the
quantity of containment boom specified in § 154.1045(c)(1). Based on site-specific or facility-specific information,
the COTP may specify that additional
quantities of containment boom are
available within one hour. In addition,
there must be adequate sorbent material for initial response to an average
most probable discharge. If the facility
is a fixed facility, the containment
boom and sorbent material must be located at the facility. If the facility is a
mobile facility, the containment boom
and sorbent must be available locally
and be at the site of the discharge
within 1 hour of its discovery.
§ 154.1041 Specific response information to be maintained on mobile
MTR facilities.
(a) Each mobile MTR facility must
carry the following information as contained in the response plan when performing transfer operations:
(1) A description of response activities for a discharge which may occur
during transfer operations. This may
be a narrative description or a list of
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procedures to be followed in the event
of a discharge.
(2) Identity of response resources to
respond to a discharge from the mobile
MTR facility.
(3) List of the appropriate persons
and agencies (including the telephone
numbers) to be contacted in regard to a
discharge and its handling, including
the National Response Center.
(b) The owner or operator of the mobile facility must also retain the information in this paragraph at the principal place of business.
§ 154.1045 Response plan development
and evaluation criteria for facilities
that handle, store, or transport
Group I through Group IV petroleum oils.
(a) The owner or operator of a facility that handles, stores, or transports
Group I through Group IV petroleum
oils shall use the criteria in this section to evaluate response resources
identified in the response plan for the
specified operating environment.
(1) The criteria in Table 1 of appendix
C of this part are to be used solely for
identification of appropriate equipment in a response plan. These criteria
reflect conditions used for planning
purposes to select mechanical response
equipment and are not conditions that
would limit response actions or affect
normal facility operations.
(2) The response resources must be
evaluated considering limitations for
the COTP zones in which the facility
operates, including but not limited to—
(i) Ice conditions;
(ii) Debris;
(iii) Temperature ranges;
(iv) Weather-related visibility; and
(v) Other appropriate environmental
conditions as determined by the COTP.
(3) The COTP may reclassify a specific body of water or location within
the COTP zone. Any reclassifications
will be identified by the COTP in the
applicable ACP. Reclassifications may
be to—
(i) A more stringent operating environment if the prevailing wave conditions exceed the significant wave
height criteria during more than 35
percent of the year; or
(ii) A less stringent operating environment if the prevailing wave conditions do not exceed the significant
wave height criteria for the less stringent operating environment during
more than 35 percent of the year.
(b) Response equipment must—
(1) Meet or exceed the operating criteria listed in Table 1 of appendix C of
this part;
(2) Function in the applicable operating environment; and
(3) Be appropriate for the petroleum
oil carried.
(c) The response plan for a facility
that handles, stores, or transports
Group I through Group IV petroleum
oils must identify response resources
that are available, by contract or other
approved means as described in
§ 154.1028(a)(1)(4), to respond to the facility’s average most probable discharge. The response resources must
include, at a minimum—
(1) 1,000 feet of containment boom or
two times the length of the largest vessel that regularly conducts petroleum
oil transfers to or from the facility,
whichever is greater, and the means of
deploying and anchoring the boom
available at the spill site within 1 hour
of the detection of a spill; and
(2) Oil recovery devices and recovered
oil storage capacity capable of being at
the spill site within 2 hours of the discovery of a petroleum oil discharge
from a facility.
(d) The response plan for a facility
that handles, stores, or transports
Group I through Group IV petroleum
oils must identify response resources
that are available, by contract or other
approved means as described in
§ 154.1028(a)(1)(4), to respond to a discharge up to the facility’s maximum
most probable discharge volume.
(1) The response resources must include sufficient containment boom, oil
recovery devices, and storage capacity
for any recovery of up to the maximum
most probable discharge planning volume, as contained in appendix C.
(2) The response resources must be
appropriate for each group of petroleum oil identified in § 154.1020 that is
handled, stored, or transported by the
facility.
(3) These response resources must be
positioned such that they can arrive at
the scene of a discharge within the following specified times:
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(i) The equipment identified in paragraphs (c)(1) and (c)(2) of this section or
in § 154.1040(d) must arrive within the
times specified in those paragraphs or
that section, as appropriate.
(ii) In higher volume port areas and
the Great Lakes, response resources
must be capable of arriving on scene
within 6 hours of the discovery of a petroleum oil discharge from a facility.
(iii) In all other locations, response
resources must be capable of arriving
on scene within 12 hours of the discovery of a petroleum oil discharge
from a facility.
(4) The COTP may determine that
mobilizing response resources to an
area beyond the response times indicated in this paragraph invalidates the
response plan. In this event, the COTP
may impose additional operational restrictions (e.g., limitations on the
number of transfers at a facility), or,
at the COTP’s discretion, the facility
may operate with temporarily modified
response plan development and evaluation criteria (e.g., modified response
times, alternate response resources,
etc.).
(e) The response plan for a facility
that handles, stores, or transports
Group I through Group IV petroleum
oils must identify the response resources that are available, by contract
or other approved means as described
in § 154.1028(a)(1)(4), to respond to the
worst case discharge volume of petroleum oil to the maximum extent practicable.
(1) The location of these response resources must be suitable to meet the
response times identified in paragraph
(f) of this section for the applicable geographic area(s) of operation and response tier.
(2) The response resources must be
appropriate for—
(i) The volume of the facility’s worst
case discharge;
(ii) Group(s) of petroleum oil as identified in § 154.1020 that are handled,
stored, or transported by the facility;
and
(iii) The geographic area(s) in which
the facility operates.
(3) The response resources must include sufficient boom, oil recovery devices, and storage capacity to recover
the worst case discharge planning volumes.
(4) The guidelines in appendix C of
this part must be used for calculating
the quantity of response resources required to respond at each tier to the
worst case discharge to the maximum
extent practicable.
(5) When determining response resources necessary to meet the requirements of this section, a portion of
those resources must be capable of use
in close-to-shore response activities in
shallow water. The following percentages of the response equipment identified for the applicable geographic area
must be capable of operating in waters
of 6 feet or less depth.
(i) Offshore—10 percent.
(ii) Nearshore/inland/Great Lakes/rivers and canals—20 percent.
(6) The COTP may determine that
mobilizing response resources to an
area beyond the response times indicated in this paragraph invalidates the
response plan. In this event, the COTP
may impose additional operational restrictions (e.g., limitations on the
number of transfers at a facility), or,
at the COTP’s discretion, the facility
may be permitted to operate with temporarily modified response plan development and evaluation criteria (e.g.,
modified response times, alternate response resources, etc.).
(f) Response equipment identified in
a response plan for a facility that handles, stores, or transports Group I
through Group IV petroleum oils must
be capable of arriving on scene within
the times specified in this paragraph
for the applicable response tier in a
higher volume port area, Great Lakes,
and in other areas. Response times for
these tiers from the time of discovery
of a discharge are—
Tier 1
(hrs.)
Higher volume port area (except
for a TAPAA facility located in
Prince William Sound, see
§ 154.1135) ............................
Great Lakes ...............................
All other river and canal, inland,
nearshore, and offshore
areas ......................................
Tier 2
(hrs.)
6
12
30
36
54
60
12
36
60
(g) For the purposes of arranging for
response resources for a facility that
handles, stores, or transports Group I
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(hrs.)
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§ 154.1045
33 CFR Ch. I (7–1–10 Edition)
through Group IV petroleum oils, by
contract or other approved means as
described in § 154.1028(a)(1)–(4), response
equipment identified for Tier 1 plan
credit must be capable of being mobilized and en route to the scene of a discharge within 2 hours of notification.
The notification procedures identified
in the plan must provide for notification and authorization of mobilization
of identified Tier 1 response resources—
(1) Either directly or through the
qualified individual; and
(2) Within 30 minutes of a discovery
of a discharge or substantial threat of
discharge.
(h) Response resources identified for
Tier 2 and Tier 3 plan credit must be
capable of arriving on scene within the
time specified for the applicable tier.
(i) The owner or operator of a facility
that handles, stores, or transports
groups II through IV petroleum oils
within the inland, nearshore, or offshore areas where pre-authorization for
dispersant use exists must identify in
their response plan, and ensure the
availability of, through contract or
other approved means, response resources capable of conducting dispersant operations within those areas.
(1) Dispersant response resources
must be capable of commencing dispersant-application operations at the
site of a discharge within 7 hours of the
decision by the Federal On-Scene Coordinator to use dispersants.
(2) Dispersant response resources
must include all of the following:
(i) Sufficient volumes of dispersants
for application as required by paragraph (i)(3) of this section. Any
dispersants identified in a response
plan must be of a type listed on the National Oil and Hazardous Substances
Pollution Contingency Plan Product
Schedule (which is contained in 40 CFR
part 300, and available online from the
U.S. Government Printing Office).
(ii) Dispersant-application platforms
capable of delivering and applying the
dispersant on a discharge in the
amounts as required by paragraph (i)(3)
of this section. At least 50 percent of
each EDAC tier requirement must be
achieved through the use of fixed-wing,
aircraft-based application platforms.
For dispersant-application platforms
not detailed within the DMP2, adequacy of performance criteria must be
documented by presentation of independent evaluation materials (e.g.,
field tests and reports of actual use)
that record the performance of the
platform.
(iii) Dispersant-application systems
that are consistent in design with, and
are capable of applying dispersants
within, the performance criteria in
ASTM F1413–07 (incorporated by reference, see § 154.106). For dispersant-application systems not fully covered by
ASTM F1413–07, such as fire monitortype applicators, adequacy of performance criteria must be documented by
presentation of independent evaluation
materials (e.g., laboratory tests, field
tests, and reports of actual use) that
record the design of performance specifications.
(iv) Dispersant-application personnel
trained in and capable of applying
dispersants according to the recommended procedures contained within ASTM F1737–07 (incorporated by reference, see § 154.106).
(3) Dispersant stockpiles, application
platforms, and other supporting resources must be available in a quantity
and type sufficient to treat a facility’s
worst-case discharge (as determined by
using the criteria in appendix C, section 8) or in quantities sufficient to
meet the requirements in Table
154.1045(i) of this section, whichever is
the lesser amount.
TABLE 154.1045(I)—TIERS FOR EFFECTIVE DAILY APPLICATION CAPABILITY
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Response time for
completed
application
(hours)
Tier 1 .................................................................
Tier 2 .................................................................
Tier 3 .................................................................
Dispersant
application
dispersant: oil treated in
gallons
(Gulf Coast)
Dispersant application
dispersant: oil treated in
gallons
all other U.S.
8,250:165,000
23,375:467,000
23,375:467,000
4,125:82,500
23,375:467,000
23,375:467,000
12
36
60
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Coast Guard, DHS
§ 154.1045
TABLE 154.1045(I)—TIERS FOR EFFECTIVE DAILY APPLICATION CAPABILITY—Continued
Response time for
completed
application
(hours)
Total ....................................................
Dispersant application
dispersant: oil treated in
gallons
all other U.S.
55,000:1,100,000
50,875:1,017,500
60
NOTE TO TABLE 154.1045(I): Gulf Coast Tier
1 is higher due to greater potential spill size
and frequency in that area, and it is assumed
that dispersant stockpiles would be centralized in the Gulf area. Alternative application
ratios may be considered based upon submission to Coast Guard Headquarters, Office of
Incident Management and Preparedness (CG–
533, 202–372–2234, 2100 2nd Street, SW., room
2100, Washington, DC 20593) of peer-reviewed
scientific evidence of improved capability.
erowe on DSK5CLS3C1PROD with CFR
Dispersant
application
dispersant: oil treated in
gallons
(Gulf Coast)
(j) The owner or operator of a facility
handling Groups I through IV petroleum oil as a primary cargo must identify in the response plan, and ensure
the availability through contract or
other approved means, of response resources necessary to provide aerial oil
tracking to support oil spill assessment
and cleanup activities. Facilities operating exclusively on inland rivers are
not required to comply with this paragraph. Aerial oil tracking resources
must:
(1) Be capable of arriving at the site
of a discharge in advance of the arrival
of response resources identified in the
plan for tiers 1, 2, and 3 Worst-Case
Discharge response times, and for a distance up to 50 nautical miles from
shore (excluding inland rivers);
(2) Be capable of supporting oil spill
removal operations continuously for
three 10-hour operational periods during the initial 72 hours of the discharge;
(3) Include appropriately located aircraft and personnel capable of meeting
the response time requirement for oil
tracking from paragraph (j)(1) of this
section; and
(4) Include sufficient numbers of aircraft, pilots, and trained observation
personnel to support oil spill removal
operations, commencing upon initial
assessment, and capable of coordinating on-scene cleanup operations, including dispersant and mechanical recovery operations. Observation personnel must be trained in:
(i) The protocols of oil-spill reporting
and assessment, including estimation
of slick size, thickness, and quantity;
and
(ii) The use of assessment techniques
in ASTM F1779–08 (incorporated by reference, see § 154.106), and familiar with
the use of other guides, such as NOAA’s
‘‘Open Water Oil Identification Job Aid
for Aerial Observation,’’ and NOAA’s
‘‘Characteristic
Coastal
Habitats’’
guide (available on the Internet at
http://response.restoration.noaa.gov/use
the following links in the order presented:
Home|Emergency
Response|Responding to Oil Spills).
(k) A response plan for a facility that
handles, stores, or transports Group I
through Group IV petroleum oils must
identify response resources with firefighting capability. The owner or operator of a facility that does not have
adequate firefighting resources located
at the facility or that can not rely on
sufficient local firefighting resources
must identify and ensure, by contract
or other approved means as described
in § 154.1028(a)(1)–(4), the availability of
adequate firefighting resources. The response plan must also identify an individual located at the facility to work
with the fire department for petroleum
oil fires. This individual shall also
verify that sufficient well-trained firefighting resources are available within
a reasonable time to respond to a worst
case discharge. The individual may be
the qualified individual as defined in
§ 154.1020 and identified in the response
plan or another appropriate individual
located at the facility.
(l) The response plan for a facility
that handles, stores, or transports
Groups I through IV petroleum oils
must identify equipment and required
personnel available, by contract or
other approved means as described in
§ 154.1028(a) (1)–(4), to protect fish and
wildlife and sensitive environments.
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§ 154.1045
33 CFR Ch. I (7–1–10 Edition)
(1) Except as set out in paragraph
(k)(2) of this section, the identified response resources must include the
quantities of boom sufficient to protect
fish and wildlife and sensitive environments as required by § 154.1035(b)(4).
(2) The resources and response methods identified in a facility response
plan must be consistent with the required resources and response methods
to be used in fish and wildlife and sensitive environments, contained in the
appropriate ACP. Facility owners or
operators shall ensure that their response plans are in accordance with the
ACP in effect 6 months prior to initial
plan submission or the annual plan review required under § 154.1065(a). Facility owners or operators are not required to, but may at their option, conform to an ACP which is less than 6
months old at the time of plan submission.
(m) The response plan for a facility
that handles, stores, or transports
Groups I through IV petroleum oils
must identify an oil spill removal organization(s) with response resources
that are available, by contract or other
approved means as described in
§ 154.1028(a) (1)–(4), to effect a shoreline
cleanup operation commensurate with
the quantity of emulsified petroleum
oil to be planned for in shoreline cleanup operations.
(1) Except as required in paragraph
(l)(2) of this section, the shoreline
cleanup response resources required
must be determined as described in appendix C of this part.
(2) The resources and response methods identified in a facility response
plan must be consistent with the required shoreline cleanup resources and
methods contained in the appropriate
ACP. Facility owners or operators
shall ensure that their response plans
are in accordance with the ACP in effect 6 months prior to initial plan submission or the annual plan review required under § 154.1065(a). Facility owners or operators are not required to,
but may at their option, conform to an
ACP which is less than 6 months old at
the time of plan submission.
(n) Appendix C of this part describes
the procedures to determine the maximum extent practicable quantity of
response resources that must be identi-
fied and available, by contract or other
approved means as described in
§ 154.1028(a) (1)–(4), for the maximum
most probable discharge volume, and
for each worst case discharge response
tier.
(1) Included in appendix C of this part
is a cap that recognizes the practical
and technical limits of response capabilities that an individual facility
owner or operator can be expected to
contract for in advance.
(2) Table 5 in appendix C of this part
lists the caps that apply in February
18, 1993, and February 18, 1998. Depending on the quantity and type of petroleum oil handled by the facility and
the facility’s geographic area of operations, the resource capability caps in
this table may be reached. The owner
or operator of a facility whose estimated recovery capacity exceeds the
applicable contracting caps in Table 5
shall identify sources of additional
equipment equal to twice the cap listed
in Tiers 1, 2, and 3 or the amount necessary to reach the calculated planning
volume, whichever is lower. The identified resources must be capable of arriving on scene not later than the Tier 1,
2, and 3 response times in this section.
No contract is required. While general
listings of available response equipment may be used to identify additional sources, a response plan must
identify the specific sources, locations,
and quantities of equipment that a facility owner or operator has considered
in his or her planning. When listing
Coast Guard classified oil spill removal
organization(s) which have sufficient
removal capacity to recover the volume above the response capability cap
for the specific facility, as specified in
Table 5 in appendix C of this part, it is
not necessary to list specific quantities
of equipment.
(o) The Coast Guard will continue to
evaluate the environmental benefits,
cost efficiency and practicality of increasing mechanical recovery capability requirements. This continuing
evaluation is part of the Coast Guard’s
long term commitment to achieving
and maintaining an optimum mix of oil
spill response capability across the full
spectrum of response modes. As best
available technology demonstrates a
need to evaluate or change mechanical
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Coast Guard, DHS
§ 154.1047
recovery capacities, a review of cap increases and other requirements contained within this subpart may be performed. Any changes in the requirements of this section will occur
through a public notice and comment
process. During this review, the Coast
Guard will determine if established
caps remain practicable and if increased caps will provide any benefit to
oil spill recovery operations. The review will include, at least, an evaluation of:
(1) Best available technologies for
containment and recovery;
(2) Oil spill tracking technology;
(3) High rate response techniques;
(4) Other applicable response technologies; and
(5) Increases in the availability of
private response resources.
erowe on DSK5CLS3C1PROD with CFR
[CGD 91–036, 61 FR 7917, Feb. 29, 1996, as
amended by USCG–2001–8661, 74 FR 45024,
Aug. 31, 2009]
§ 154.1047 Response plan development
and evaluation criteria for facilities
that handle, store, or transport
Group V petroleum oils.
(a) An owner or operator of a facility
that handles, stores, or transports
Group V petroleum oils must provide
information in his or her response plan
that identifies—
(1) Procedures and strategies for responding to a worst case discharge of
Group V petroleum oils to the maximum extent practicable; and
(2) Sources of the equipment and supplies necessary to locate, recover, and
mitigate such a discharge.
(b) An owner or operator of a facility
that handles, stores, or transports
Group V petroleum oil must ensure
that any equipment identified in a response plan is capable of operating in
the conditions expected in the geographic area(s) in which the facility
operates using the criteria in Table 1 of
appendix C of this part. When evaluating the operability of equipment, the
facility owner or operator must consider limitations that are identified in
the ACPs for the COTP zones in which
the facility operates, including—
(1) Ice conditions;
(2) Debris;
(3) Temperature ranges; and
(4) Weather-related visibility.
(c) The owner or operator of a facility that handles, stores, or transports
Group V petroleum oil must identify
the response resources that are available by contract or other approved
means as described in § 154.1028. The
equipment identified in a response plan
must include—
(1) Sonar, sampling equipment, or
other methods for locating the petroleum oil on the bottom or suspended in
the water column;
(2) Containment boom, sorbent boom,
silt curtains, or other methods for containing the petroleum oil that may remain floating on the surface or to reduce spreading on the bottom;
(3) Dredges, pumps, or other equipment necessary to recover petroleum
oil from the bottom and shoreline;
(4) Equipment necessary to assess the
impact of such discharges; and
(5) Other appropriate equipment necessary to respond to a discharge involving the type of petroleum oil handled,
stored, or transported.
(d) Response resources identified in a
response plan for a facility that handles, stores, or transports Group V petroleum oils under paragraph (c) of this
section must be capable of being at the
spill site within 24 hours of discovery
of a discharge.
(e) A response plan for a facility that
handles, stores, or transports Group V
petroleum oils must identify response
resources with firefighting capability.
The owner or operator of a facility that
does not have adequate firefighting resources located at the facility or that
can not rely on sufficient local firefighting resources must identity and
ensure, by contract or other approved
means as described in § 154.1028, the
availability of adequate firefighting resources. The response plan must also
identify an individual located at the facility to work with the fire department
for petroleum oil fires. This individual
shall also verify that sufficient welltrained firefighting resources are available within a reasonable response time
to a worst case scenario. The individual may be the qualified individual
as defined in § 154.1020 and identified in
the response plan or another appropriate individual located at the facility.
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§ 154.1050
§ 154.1050
33 CFR Ch. I (7–1–10 Edition)
Training.
(a) A response plan submitted to
meet the requirements of §§ 154.1035 or
154.1040, as appropriate, must identify
the training to be provided to each individual with responsibilities under the
plan. A facility owner or operator must
identify the method to be used for
training any volunteers or casual laborers used during a response to comply with the requirements of 29 CFR
1910.120.
(b) A facility owner or operator shall
ensure the maintenance of records sufficient to document training of facility
personnel; and shall make them available for inspection upon request by the
U.S. Coast Guard. Records for facility
personnel must be maintained at the
facility for 3 years.
(c) Where applicable, a facility owner
or operator shall ensure that an oil
spill removal organization identified in
a response plan to meet the requirements of this subpart maintains
records sufficient to document training
for the organization’s personnel and
shall make them available for inspection upon request by the facility’s
management personnel, the qualified
individual, and U.S. Coast Guard.
Records must be maintained for 3 years
following completion of training.
(d) The facility owner or operator remains responsible for ensuring that all
private response personnel are trained
to meet the Occupational Safety and
Health Administration (OSHA) standards for emergency response operations
in 29 CFR 1910.120.
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§ 154.1055
Exercises.
(a) A response plan submitted by an
owner or operator of an MTR facility
must include an exercise program containing both announced and unannounced exercises. The following are
the minimum exercise requirements
for facilities covered by this subpart:
(1) Qualified individual notification
exercises (quarterly).
(2) Spill management team tabletop
exercises (annually). In a 3-year period,
at least one of these exercises must include a worst case discharge scenario.
(3) Equipment deployment exercises:
(i) Semiannually for facility owned
and operated equipment.
(ii) Annually for oil spill removal organization equipment.
(4) Emergency procedures exercises
(optional).
(5) Annually, at least one of the exercises listed in § 154.1055(a)(2) through (4)
must be unannounced. Unannounced
means the personnel participating in
the exercise must not be advised in advance, of the exact date, time and scenario of the exercise.
(6) The facility owner or operator
shall design the exercise program so
that all components of the response
plan are exercised at least once every 3
years. All of the components do not
have to be exercised at one time; they
may be exercised over the 3-year period
through the required exercises or
through an Area exercise.
(b) A facility owner or operator shall
participate in unannounced exercises,
as directed by the COTP. The objectives of the unannounced exercises will
be to test notifications and equipment
deployment for response to the average
most probable discharge. After participating in an unannounced exercise directed by a COTP, the owner or operator will not be required to participate
in another COTP initiated unannounced exercise for at least 3 years
from the date of the exercise.
(c) A facility owner or operator shall
participate in Area exercises as directed by the applicable On-Scene Coordinator. The Area exercises will involve equipment deployment to respond to the spill scenario developed by
the Exercise Design Team, of which the
facility owner or operator will be a
member. After participating in an Area
exercise, a facility owner or operator
will not be required to participate in
another Area exercise for at least 6
years.
(d) The facility owner or operator
shall ensure that adequate records of
all required exercises are maintained
at the facility for 3 years. Records
shall be made available to the Coast
Guard upon request.
(e) The response plan submitted to
meet the requirements of this subpart
must specify the planned exercise program. The plan must detail the exercise program, including the types of exercises, frequency, scope, objectives
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Coast Guard, DHS
§ 154.1060
and the scheme for exercising the entire response plan every 3 years.
(f) Compliance with the National
Preparedness for Response Exercise
Program (PREP) Guidelines will satisfy the facility response plan exercise
requirements. These guidelines are
available from the TASC DEPT Warehouse, 33141Q 75th Avenue, Landover,
MD 20875 (fax: 301–386–5394, stock number USCG–X0241). Compliance with an
alternative program that meets the requirements of paragraph (a) of this section and has been approved under
§ 154.1060 will also satisfy the facility
response plan exercise requirements.
NOTE TO PARAGRAPH (f): The PREP guidelines
are
available
online
at
http://
dmses.dot.gov/docimages/pdf1a/198001lweb.pdf.
erowe on DSK5CLS3C1PROD with CFR
[CGD 91–036, 61 FR 7917, Feb. 29, 1996, as
amended by USCGD–2003–15404, 68 FR 37741,
June 25, 2003]
§ 154.1057 Inspection and maintenance
of response resources.
(a) A facility owner or operator required to submit a response plan under
this part must ensure that—
(1) Containment booms, skimmers,
vessels, and other major equipment
listed or referenced in the plan are periodically inspected and maintained in
good operating condition, in accordance
with
manufacturer’s
recommendations, and best commercial
practices; and
(2) All inspection and maintenance is
documented and that these records are
maintained for 3 years.
(b) For equipment which must be inspected and maintained under this section the Coast Guard may—
(1) Verify that the equipment inventories exist as represented;
(2) Verify the existences of records
required under this section;
(3) Verify that the records of inspection and maintenance reflect the actual condition of any equipment listed
or referenced; and
(4) Inspect and require operational
tests of equipment.
(c) This section does not apply to
containment booms, skimmers, vessels,
and other major equipment listed or
referenced in the plan and ensured
available from an oil spill removal organization through the written consent
required under § 154.1028(a)(5).
§ 154.1060 Submission
procedures.
and
(a) The owner or operator of a facility to which this subpart applies shall
submit one copy of a facility response
plan meeting the requirements of this
subpart to the COTP for initial review
and, if appropriate, approval.
(b) The owner or operator of a facility to which this subpart applies shall
include a statement certifying that the
plan meets the applicable requirements
of subparts F, G, H, and I of this part,
as appropriate.
(c) For an MTR facility that is located in the inland response zone where
the EPA Regional Administrator is the
predesignated Federal On-Scene Coordinator, the COTP may consult with
the EPA Federal On-Scene Coordinator
prior to any final approval.
(d) For an MTR facility identified in
§ 154.1015(c) of this subpart that is also
required to prepare a response plan
under 40 CFR part 112, if the COTP determines that the plan meets all applicable requirements and the EPA Regional Administrator raises no objection to the response plan contents, the
COTP will notify the facility owner or
operator in writing that the plan is approved.
(e) The plan will be valid for a period
of up to 5 years. The facility owner or
operator must resubmit an updated
plan every 5 years as follows:
(1) For facilities identified in only
§ 154.1015(b) of this subpart, the 5-year
period will commence on the date the
plan is submitted to the COTP.
(2) For facilities identified in
§ 154.1015(c) of this subpart, the 5-year
period will commence on the date the
COTP approves the plan.
(3) All resubmitted response plans
shall be accompanied by a cover letter
containing a detailed listing of all revisions to the response plan.
(f) For an MTR facility identified in
§ 154.1015(c)(2) the COTP will notify the
facility owner or operator in writing
that the plan is approved.
(g) If a COTP determines that a plan
does not meet the requirements of this
subpart either upon initial submission
or upon 5-year resubmission, the COTP
will return the plan to the facility
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§ 154.1065
33 CFR Ch. I (7–1–10 Edition)
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owner or operator along with an explanation of the response plan’s deficiencies. The owner or operator must
correct any deficiencies in accordance
with § 154.1070 and return the plan to
the COTP within the time specified by
the COTP in the letter describing the
deficiencies.
(h) The facility owner or operator
and the qualified individual and the alternative qualified individual shall
each maintain a copy of the most current response plan submitted to the
COTP. One copy must be maintained at
the facility in a position where the
plan is readily available to persons in
charge of conducting transfer operations.
§ 154.1065 Plan review and revision
procedures.
(a) A facility owner or operator must
review his or her response plan(s) annually. This review shall incorporate any
revisions to the plan, including listings
of fish and wildlife and sensitive environments identified in the ACP in effect 6 months prior to plan review.
(1) For an MTR facility identified in
§ 154.1015(c) of this subpart as a ‘‘significant and substantial harm facility,’’ this review must occur within 1
month of the anniversary date of COTP
approval of the plan. For an MTR facility identified in § 154.1015(b) of this subpart, as a ‘‘substantial harm facility’’
this review must occur within 1 month
of the anniversary date of submission
of the plan to the COTP.
(2) The facility owner or operator
shall submit any revision(s) to the response plan to the COTP and all other
holders of the response plan for information or approval, as appropriate.
(i) Along with the revisions, the facility owner or operator shall submit a
cover letter containing a detailed listing of all revisions to the response
plan.
(ii) If no revisions are required, the
facility owner or operator shall indicate the completion of the annual review on the record of changes page.
(iii) The COTP will review the revision(s) submitted by the owner or operator and will give written notice to the
owner or operator of any COTP objection(s) to the proposed revisions within
30 days of the date the revision(s) were
submitted to the COTP. The revisions
shall become effective not later than 30
days from their submission to the
COTP unless the COTP indicates otherwise in writing as provided in this
paragraph. If the COTP indicates that
the revision(s) need to be modified before implementation, the owner or operator will modify the revision(s) within the time period set by the COTP.
(3) Any required revisions must be
entered in the plan and noted on the
record of changes page.
(b) The facility owner or operator
shall submit revisions to a previously
submitted or approved plan to the
COTP and all other holders of the response plan for information or approval
within 30 days, whenever there is—
(1) A change in the facility’s configuration that significantly affects the information included in the response
plan;
(2) A change in the type of oil (petroleum oil group) handled, stored, or
transported that affects the required
response resources;
(3) A change in the name(s) or capabilities of the oil spill removal organization required by § 154.1045;
(4) A change in the facility’s emergency response procedures;
(5) A change in the facility’s operating area that includes ports or geographic area(s) not covered by the previously approved plan. A facility may
not operate in an area not covered in a
plan previously submitted or approved,
as appropriate, unless the revised plan
is approved or interim operating approval is received under § 154.1025; or
(6) Any other changes that significantly affect the implementation of
the plan.
(c) Except as required in paragraph
(b) of this section, revisions to personnel and telephone number lists included in the response plan do not require COTP approval. The COTP and
all other holders of the response plan
shall be advised of these revisions and
provided a copy of the revisions as they
occur.
(d) The COTP may require a facility
owner or operator to revise a response
plan at any time as a result of a compliance inspection if the COTP determines that the response plan does not
meet the requirements of this subpart
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Coast Guard, DHS
§ 154.1110
or as a result of inadequacies noted in
the response plan during an actual pollution incident at the facility.
(e) If required by §§ 154.1035(b)(3) or
154.1045, a new or existing facility
owner or operator must submit the required dispersant and aerial oil tracking resource revisions to a previously
submitted or approved plan, made pursuant to §§ 154.1035(b)(3) or 154.1045, to
the COTP and all other holders of the
response plan for information or approval no later than February 22, 2011.
[CGD 91–036, 61 FR 7917, Feb. 29, 1996, as
amended by USCG–2001–8661, 74 FR 45025,
Aug. 31, 2009]
erowe on DSK5CLS3C1PROD with CFR
§ 154.1070 Deficiencies.
(a) The cognizant COTP will notify
the facility owner or operator in writing of any deficiencies noted during review of a response plan, drills observed
by the Coast Guard, or inspection of
equipment or records maintained in
connection with this subpart.
(b) Deficiencies shall be corrected
within the time period specified in the
written notice provided by the COTP.
The facility owner or operator who disagrees with a deficiency issued by the
COTP may appeal the deficiency to the
cognizant COTP within 7 days or the
time specified by the COTP to correct
the deficiency, whichever is less. This
time commences from the date of receipt of the COTP notice. The owner or
operator may request a stay from the
COTP decision pending appeal in accordance with § 154.1075.
(c) If the facility owner or operator
fails to correct any deficiencies or submit a written appeal, the COTP may
invoke the provisions of § 154.1025 prohibiting the facility from storing, handling, or transporting oil.
§ 154.1075 Appeal process.
(a) Any owner or operator of a facility who desires to appeal the classification that a facility could reasonably be
expected to cause substantial harm or
significant and substantial harm to the
environment, shall submit a written
request to the cognizant COTP requesting review and reclassification by the
COTP. The facility owner or operator
shall identify those factors to be considered by the COTP. The factors to be
considered by the COTP regarding re-
classification of a facility include, but
are not limited to, those listed in
§ 154.1016(b). After considering all relevant material presented by the facility owner or operator and any additional material available to the COTP,
the COTP will notify the facility owner
or operator of the decision on the reclassification of the facility.
(b) Any facility owner or operator directly affected by an initial determination or action of the COTP may submit
a written request to the cognizant
COTP requesting review and reconsideration of the COTP’s decision or action. The facility owner or operator
shall identify those factors to be considered by the COTP in making his or
her decision on reconsideration.
(c) Within 10 days of the COTP’s decision under paragraph (b) of this section, the facility owner or operator
may appeal the decision of the COTP to
the District Commander. This appeal
shall be made in writing via the cognizant COTP to the District Commander of the district in which the office of the COTP is located.
(d) Within 30 days of the District
Commander’s decision, the facility
owner or operator may formally appeal
the decision of the District Commander. This appeal shall be submitted
in writing to Commandant (CG–535) via
the District Commander.
(e) When considering an appeal, the
COTP, District Commander, or Commandant may stay the effect of the decision or action being appealed pending
the determination of the appeal.
[CGD 91–036, 61 FR 7930, Feb. 29, 1996, as
amended by CGD 96–026, 61 FR 33666, June 28,
1996; USCG–2010–0351, 75 FR 36284, June 25,
2010]
Subpart G—Additional Response
Plan Requirements for a TransAlaska Pipeline Authorization
Act (TAPAA) Facility Operating in Prince William Sound,
Alaska
SOURCE: CGD 91–036, 61 FR 7930, Feb. 29,
1996, unless otherwise noted.
§ 154.1110 Purpose and applicability.
(a) This subpart establishes oil spill
response planning requirements for a
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§ 154.1115
33 CFR Ch. I (7–1–10 Edition)
facility permitted under the Tans-Alaska
Pipeline
Authorization
Act
(TAPAA), in addition to the requirements of subpart F of this part. The requirements of this subpart are intended
for use in developing response plans
and identifying response resources during the planning process. They are not
performance standards.
(b) The information required by this
subpart must be included in the Prince
William Sound facility-specific appendix to the facility response plan required by subpart F of this part.
erowe on DSK5CLS3C1PROD with CFR
§ 154.1115 Definitions.
In addition to the definitions in this
section, the definitions in §§ 154.105 and
154.1020 apply to this subpart. As used
in this subpart—
Crude oil means any liquid hydrocarbon mixture occurring naturally in
the earth, whether or not treated to
render it suitable for transportation,
and includes crude oil from which certain distillate fractions may have been
removed, and crude oil to which certain distillate fractions may have been
added.
Non-crude oil means any oil other
than crude oil.
Prince William Sound means all State
and Federal waters within Prince William Sound, Alaska, including the approach to Hinchinbrook Entrance out
to and encompassing Seal Rocks.
§ 154.1120 Operating restrictions and
interim operating authorization.
(a) The owner or operator of a
TAPAA facility may not operate in
Prince William Sound, Alaska, unless
the requirements of this subpart as
well as § 154.1025 have been met. The
owner or operator of a TAPAA facility
shall certify to the COTP that he or
she has provided, through an oil spill
removal organization required by
§ 154.1125, the necessary response resources to remove, to the maximum extend practicable, a worst case discharge or a discharge of 200,000 barrels
of oil, whichever is grater, in Prince
William Sound.
(b) Coast Guard approval of a TAPAA
facility response plan is effective only
so long as the appropriate Regional
Citizens Advisory Council(s) is funded
pursuant to the requirements of sec-
tion 5002(k) of the Oil Pollution Act of
1990 (Pub. L. 101–380; 104 Stat. 484, 550).
§ 154.1125 Additional response plan requirements.
(a) The owner or operator of a
TAPAA facility shall include the following information in the Prince William Sound appendix to the response
plan required by subpart F of this part:
(1) Oil spill removal organization. Identification of an oil spill removal organization that shall—
(i) Perform response activities;
(ii) Provide oil spill removal and containment training, including training
in the operation of prepositioned equipment for personnel, including local
residents and fishermen, from the following locations in Prince William
Sound:
(A) Valdez;
(B) Tatitlek;
(C) Cordova;
(D) Whittier;
(E) Chenega; and
(F) Fish hatcheries located at Port
San Juan, Main Bay, Esther Island,
Cannery Creek, and Solomon Gulch.
(iii) Provide a plan for training, in
addition to the personnel listed in
paragraph (a)(1)(ii) of this section, sufficient numbers of trained personnel to
remove, to the maximum extent practicable, a worst case discharge; and
(iv) Address the responsibilities required in § 154.1035(b)(3)(iii).
(2) Exercises. Identification of exercise procedures that must—
(i) Provide for two exercises of the oil
spill removal organization each year
that
test
the
ability
of
the
prepositioned equipment and trained
personnel required under this subpart
to perform effectively;
(ii) Consist of both announced and
unannounced drills; and
(iii) Include design(s) for exercises
that test either the entire appendix or
individual components(s).
(3) Testing, inspection, and certification. Identification of a testing, inspecting, and certification program for
the prepositioned response equipment
required in § 154.1130 that must provide
for—
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erowe on DSK5CLS3C1PROD with CFR
Coast Guard, DHS
§ 154.1140
(i) Annual testing and equipment inspection in accordance with the manufacturer’s recommended procedures, to
include—
(A) Start-up and running under load
all electrical motors, pumps, power
packs, air compressors, internal combustion engines, and oil recovery devices; and
(B) Removal for inspection of no less
than one-third of required boom from
storage annually, such that all boom
will have been removed and inspected
within a period of 3 years; and
(ii) Records of equipment tests and
inspection.
(iii) Use of an independent entity to
certify that the equipment is on-site
and in good operating condition and
that required tests and inspection have
been preformed. The independent entity must have appropriate training and
expertise to provide this certification.
(4) Prepositioned response equipment.
Identification and location of the
prepositioned response equipment required in § 154.1130 including the make,
model, and effective daily recovery
rate of each oil recovery resource.
(b) The owner or operator of a
TAPAA facility shall submit to the
COTP a schedule for the training and
drills required by the geographic-specific appendix for Prince William
Sound for the following calendar year.
(c) All records required by this section must be available for inspection
by the COTP.
being on scene within 18 hours of notification of discharge.
(d) On-water storage capacity of
300,000 barrels for recovered oily material capable of being on scene within 12
hours of notification of a discharge.
(e) On-water recovery devices and
storage equipment located in communities at strategic locations.
(f) Equipment as identified below, for
the
locations
identified
in
§ 154.1125(a)(1)(ii) sufficient for the protection of the environment in these locations:
(1) Boom appropriate for the specific
locations.
(2) Sufficient boats to deploy boom
and sorbents.
(3) Sorbent materials.
(4) Personnel protective clothing and
equipment.
(5) Survival equipment.
(6) First aid supplies.
(7) Buckets, shovels, and various
other tools.
(8) Decontamination equipment.
(9) Shoreline cleanup equipment.
(10) Mooring equipment.
(11) Anchored buoys at appropriate
locations to facilitate the positioning
of defensive boom.
(12) Other appropriate removal equipment for the protection of the environment as identified by the COTP.
§ 154.1130 Requirements
for
prepositioned response equipment.
The owner or operator of a TAPAA
facility shall provide the following
prepositioned response equipment, located within Prince William Sound, in
addition to that required by §§ 154.1035,
154.1045, or 154.1050:
(a) On-water recovery equipment
with a minimum effective daily recovery rate of 30,000 barrels capable of
being a scene within 2 hours of notification of a discharge.
(b) On-water storage capacity of
100,000 barrels for recovered oily material capable of being on scene within 2
hours of notification of a discharge.
(c) On-water recovery equipment
with a minimum effective daily recovery rate of 40,000 barrels capable of
The following response times must be
used in determining the on scene arrival time in Prince William Sound for
the response resources required by
§ 154.1045:
§ 154.1135 Response plan development
and evaluation criteria.
Tier 1
(hrs.)
Prince William Sound Area .......
Tier 2
(hrs.)
12
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36
§ 154.1140 TAPAA facility contracting
with a vessel.
The owner or operator of a TAPAA
facility may contract with a vessel
owner or operator to meet some of all
of the requirements of subpart G of
part 155 of this chapter. The extent to
which these requirements are met by
the contractual arrangement will be
determined by the COTP.
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(hrs.)
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§ 154.1210
33 CFR Ch. I (7–1–10 Edition)
Subpart H—Response Plans for
Animal Fats and Vegetable
Oils Facilities
SOURCE: CGD 91–036, 61 FR 7931, Feb. 29,
1996, unless otherwise noted.
§ 154.1210
Purpose and applicability.
(a) The requirements of this subpart
are intended for use in developing response plans and identifying response
resources during the planning process.
They are not performance standards.
(b) This subpart establishes oil spill
response planning requirements for an
owner or operator of a facility that
handles, stores, or transports animal
fats or vegetable oils including—
(1) A fixed MTR facility capable of
transferring oil in bulk, to or from a
vessel with a capacity of 250 barrels or
more; and
(2) A mobile MTR facility used or intended to be used to transfer oil to or
from a vessel with a capacity of 250
barrels or more.
[USCG–1999–5149, 65 FR 40825, June 30, 2000]
§ 154.1216
Facility classification.
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(a) The Coast Guard classifies facilities that handle, store, or transport
animal fats or vegetable oils as ‘‘substantial harm’’ facilities because they
may cause substantial harm to the environment by discharging oil.
(b) The COTP may change the classification of a facility that handles,
stores, or transports animal fats or
vegetable oils. The COTP may consider
the following factors, and any other
relevant factors, before changing the
classification of a facility:
(1) The type and quantity of oils handled.
(2) The spill history of the facility.
(3) The age of the facility.
(4) The public and commercial water
supply intakes near the facility.
(5) The navigable waters near the facility. Navigable waters is defined in 33
CFR part 2.36.
(6) The fish, wildlife, and sensitive
environments near the facility.
[USCG–1999–5149, 65 FR 40825, June 30, 2000, as
amended by USCG–2008–0179, 73 FR 35014,
June 19, 2008]
§ 154.1220 Response plan submission
requirements.
(a) The owner or operator of an MTR
facility identified in § 154.1216 as a substantial harm facility, shall prepare
and submit to the cognizant COTP a
response plan that complies with this
subpart and all sections of subpart F of
this part, as appropriate, except
§§ 154.1015, 154.1016, 154.1017, 154.1028,
154.1045 and 154.1047.
(b) The owner or operator of an MTR
facility classified by the COTP under
§ 154.1216(b) as a significant and substantial harm facility, shall prepare
and submit for review and approval of
the cognizant COTP a response plan
that complies with this subpart and all
sections of subpart F of this part, as
appropriate, except §§ 154.1015, 154.1016,
154.1017, 154.1028, 154.1045 and 154.1047.
(c) In addition to the requirements in
paragraph (a) of this section, the response plan for a mobile MTR facility
must meet the requirements of
§ 154.1041 subpart F.
[USCG–1999–5149, 65 FR 40825, June 30, 2000]
§ 154.1225 Specific response plan development and evaluation criteria
and other requirements for fixed facilities that handle, store, or transport animal fats or vegetable oils.
(a) The owner or operator of a fixed
facility that handles, stores, or transports animal fats or vegetable oils
must include information in the response plan that identifies—
(1) The procedures and strategies for
responding to a worst case discharge
and to an average most probable discharge of an animal fat or vegetable oil
to the maximum extent practicable;
and
(2) Sources of the equipment and supplies necessary to locate, recover, and
mitigate such a discharge.
(b) The owner or operator of a fixed
facility must ensure the equipment
listed in the response plan will operate
in the geographic area(s) where the facility operates. To determine if the
equipment will operate, the owner or
operator must—
(1) Use the criteria in Table 1 and
Section 2 of appendix C of this part;
and
(2) Consider the limitations in the
area contingency plan for the COTP
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Coast Guard, DHS
§ 154.1225
zone where the facility is located, including
(i) Ice conditions;
(ii) Debris;
(iii) Temperature ranges; and
(iv) Weather-related visibility.
(c) The owner or operator of a facility that handles, stores, or transports
animal fats or vegetable oils must
name the personnel and list the equipment, including those that are specified in § 154.1240, that are available by
contract or by a method described in
§ 154.1228(a). The owner or operator is
not required, but may at their option,
refer to the tables in Environmental
Protection Agency regulations, 40 CFR
112, Appendix E, Section 10.0, Tables 6
and 7, to determine necessary response
resources.
(d) The owner or operator of a facility that handles, stores, or transports
animal fats or vegetable oils must ensure that the response resources in
paragraph (c) of this section are able to
effectively respond to an incident within the amount of time indicated in the
following table, unless otherwise specified in § 154.1240:
Tier 1
(hrs.)
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Higher volume port
area.
Great Lakes ...............
All other river and
canal, inland, nearshore, and offshore
areas.
Tier 2
Tier 3
6
N/A
N/A.
12
12
N/A
N/A
N/A.
N/A.
(e) The owner or operator of a facility that handles, stores, or transports
animal fats or vegetable oils must—
(1) List in the plan the personnel and
equipment that the owner or operator
will use to fight fires.
(2) If there is not enough equipment
or personnel located at the facility, arrange by contract or a method described in § 154.1228(a), or through a cooperative agreement with public firefighting resources, to have the necessary personnel and equipment available to fight fires.
(3) Identify an individual located at
the facility who will work with the fire
department on fires, involving an animal fat or vegetable oil. The individual—
(i) Verifies that there are enough
trained personnel and operating equip-
ment within a reasonable distance to
the incident to fight fires.
(ii) Can be the qualified individual
defined in § 154.1020 or an appropriate
individual located at the facility.
(f) For a fixed facility, except for facilities that are part of a non-transportation-related fixed onshore facility
with a storage capacity of less than
42,000 gallons, the owner or operator
must also ensure and identify, through
contract or a method described in
§ 154.1228, response resources for an average most probable discharge, including—
(1) At least 1,000 feet of containment
boom or two times the length of the
longest vessel that regularly conducts
operations at the facility, whichever is
greater, and the means of deploying
and anchoring the boom within 1 hour
of the discovery of an incident. Based
on site-specific or facility-specific information, the COTP may require the
facility owner or operator to make
available additional quantities of containment boom within 1 hour of an incident;
(2) Adequate sorbent material located
at the facility;
(3) Oil recovery devices and recovered
oil storage capacity capable of being at
the incident’s site within 2 hours of the
discovery of an incident; and
(4) Other appropriate equipment necessary to respond to an incident involving the type of oil handled.
(g) For a mobile facility or a fixed facility that is part of a non-transportation-related onshore facility with a
storage capacity of less than 42,000 gallons, the owner or operator must meet
the requirements of § 154.1041, and ensure and identify, through contract or
a method described in § 154.1228, response resources for an average most
probable discharge, including—
(1) At least 200 feet of containment
boom and the means of deploying and
anchoring the boom within 1 hour of
the discovery of an incident. Based on
site-specific or facility-specific information, the COTP may require the facility owner or operator to make available additional quantities of containment boom within 1 hour of the discovery of an incident;
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§ 154.1228
33 CFR Ch. I (7–1–10 Edition)
(2) Adequate sorbent material capable of being at the site of an incident
within 1 hour of its discovery;
(3) Oil recovery devices and recovered
oil storage capacity capable of being at
incident’s site within 2 hours of the
discovery of an incident; and
(4) Other equipment necessary to respond to an incident involving the type
of oil handled.
(h) The response plan for a facility
that is located in any environment
with year-round preapproval for use of
dispersants and that handles, stores, or
transports animal fats and vegetables
oils may request a credit for up to 25
percent of the worst case planning volume set forth by subpart F of this part.
To receive this credit, the facility
owner or operator must identify in the
plan and ensure, by contract or other
approved means as described in
§ 154.1228(a), the availability of specified resources to apply the dispersants
and to monitor their effectiveness. The
extent of the credit for dispersants will
be based on the volumes of the
dispersants available to sustain operations at the manufacturers’ recommended dosage rates. Other spill
mitigation techniques, including mechanical dispersal, may be identified in
the response plan provided they are in
accordance with the NCP and the applicable ACP. Resources identified for
plan credit should be capable of being
on scene within 12 hours of a discovery
of a discharge. Identification of these
resources does not imply that they will
be authorized for use. Actual authorization for use during a spill response
will be governed by the provisions of
the NCP and the applicable ACP.
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[CGD 91–036, 61 FR 7931, Feb. 29, 1996, as
amended by USCG–1999–5149, 65 FR 40826,
June 30, 2000]
§ 154.1228 Methods of ensuring the
availability of response resources
by contract or other approved
means.
(a) When required in this subpart, the
availability of response resources must
be ensured by the following methods:
(1) The identification of an oil spill
removal organization with specified
equipment and personnel available
within stipulated response times in
specified geographic areas. The organi-
zation must provide written consent to
being identified in the plan;
(2) A document which—
(i) Identifies the personnel, equipment, and services capable of being
provided by the oil spill removal organization within stipulated response
times in the specified geographic areas;
(ii) Sets out the parties’ acknowledgment that the oil spill removal organization intends to commit the resources
in the event of a response;
(iii) Permits the Coast Guard to
verify the availability of the identified
response resources through tests, inspections, and drills;
(iv) Is referenced in the response
plan;
(3) Active membership in a local or
regional oil spill removal organization
that has identified specified personnel
and equipment required under this subpart that are available to response to a
discharge within stipulated response
times in the specified geographic areas;
(4) Certification by the facility owner
or operator that specified personnel
and equipment required under this subpart are owned, operated, or under the
direct control of the facility owner or
operator, and are available within stipulated response times in the specified
geographic areas; or
(5) A written contractual agreement
with an oil spill removal organization.
The agreement must identify and ensure the availability of specified personnel and equipment required under
this subpart within stipulated response
times in the specified geographic areas.
(b) The contracts and documents required in paragraph (a) of this section
must be retained at the facility and
must be produced for review upon request by the COTP.
§ 154.1240 Specific requirements for
animal fats and vegetable oils facilities that could reasonably be expected to cause substantial harm to
the environment.
(a) The owner or operator of a facility, classified under § 154.1216 as a facility that could reasonably be expected
to cause substantial harm to the environment, must submit a response plan
that meets the requirements of
§ 154.1035, except as modified by this
section.
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Coast Guard, DHS
§ 154.1325
(b) The plan does not need to list the
facility or corporate organizational
structure that the owner or operator
will use to manage the response, as required by § 154.1035(b)(3)(iii).
(c) The owner or operator must ensure and identify, by contract or a
method described in § 154.1228, that the
response resources required under
§ 154.1035(b)(3)(iv) are available for a
worst case discharge.
[USCG–1999–5149, 65 FR 40827, June 30, 2000]
Subpart I—Response Plans for
Other Non-Petroleum Oil Facilities
SOURCE: CGD 91–036, 61 FR 7932, Feb. 29,
1996, unless otherwise noted.
§ 154.1310
Purpose and applicability.
This subpart establishes oil spill response planning requirements for an
owner or operator of a facility that
handles, stores, or transports other
non-petroleum oils. The requirements
of this subpart are intended for use in
developing response plans and identifying response resources during the
planning process. They are not performance standards.
§ 154.1320 Response plan submission
requirements.
An owner or operator of a facility
that handles, stores, or transports
other non-petroleum oils shall submit
a response plan in accordance with the
requirements of this subpart, and with
all sections of subpart F of this part,
except §§ 154.1045 and 154.1047, which
apply to petroleum oils.
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§ 154.1325 Response plan development
and evaluation criteria for facilities
that handle, store, or transport
other non-petroleum oils.
(a) An owner or operator of a facility
that handles, stores, or transports
other non-petroleum oils must provide
information in his or her plan that
identifies—
(1) Procedures and strategies for responding to a worst case discharge of
other non-petroleum oils to the maximum extent practicable; and
(2) Sources of the equipment and supplies necessary to locate, recover, and
mitigate such a discharge.
(b) An owner or operator of a facility
that handles, stores, or transports
other non-petroleum oils must ensure
that any equipment identified in a response plan is capable of operating in
the conditions expected in the geographic area(s) in which the facility
operates using the criteria in Table 1 of
appendix C of this part. When evaluating the operability of equipment, the
facility owner or operator must consider limitations that are identified in
the ACPs for the COTP zone in which
the facility is located, including—
(1) Ice conditions;
(2) Debris;
(3) Temperature ranges; and
(4) Weather-related visibility.
(c) The owner or operator of a facility that handles, stores, or transports
other non-petroleum oils must identify
the response resources that are available by contract or other approved
means as described in § 154.1028(a). The
equipment identified in a response plan
must include—
(1) Containment boom, sorbent boom,
or other methods for containing oil
floating on the surface or to protect
shorelines from impact;
(2) Oil recovery devices appropriate
for the type of other non-petroleum
oils handled; and
(3) Other appropriate equipment necessary to respond to a discharge involving the type of oil handled.
(d) Response resources identified in a
response plan under paragraph (c) of
this section must be capable of commencing an effective on-scene response
within the times specified in this paragraph for the applicable operating area:
Higher volume port area .......................
Great Lakes ..........................................
All other river and canal, inland, nearshore, and offshore areas .................
Tier
1
(hrs.)
Tier
2
Tier
3
6
12
N/A
N/A
N/A
N/A
12
N/A
N/A
(e) A response plan for a facility that
handles, stores, or transports other
non-petroleum oils must identify response resources with firefighting capability. The owner or operator of a facility that does not have adequate firefighting resources located at the facility or that cannot rely on sufficient
local firefighting resources must identify and ensure, by contract or other
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approved means as described in
§ 154.1028(a), the availability of adequate firefighting resources. The response plan must also identify an individual located at the facility to work
with the fire department on other nonpetroleum oil fires. This individual
shall also verify that sufficient welltrained firefighting resources are available within a reasonable response time
to a worst case scenario. The individual may be the qualified individual
as defined in § 154.1020 and identified in
the response plan or another appropriate individual located at the facility.
(f) The response plan for a facility
that is located in any environment
with year-round preapproval for use of
dispersants and that handles, stores, or
transports other non-petroleum oils
may request a credit for up to 25 percent of the worst case planning volume
set forth by subpart F of this part. To
receive this credit, the facility owner
or operator must identify in the plan
and ensure, by contract or other approved
means
as
described
in
§ 154.1028(a), the availability of specified resources to apply the dispersants
and to monitor their effectiveness. The
extent of the credit will be based on
the volumes of the dispersant available
to sustain operations at the manufacturers’ recommended dosage rates.
Identification of these resources does
not imply that they will be authorized
for use. Actual authorization for use
during a spill response will be governed
by the provisions of the NCP and the
applicable ACP.
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APPENDIX A TO PART 154—GUIDELINES
FOR DETONATION FLAME ARRESTERS
This appendix contains the draft ASTM
standard for detonation flame arresters. Devices meeting this standard will be accepted
by the Commandant (CG–522).
1. Scope
1.1 This standard provides the minimum
requirements for design, construction, performance and testing of detonation flame arresters.
2. Intent
2.1 This standard is intended for detonation flame arresters protecting systems containing vapors of flammable or combustible
liquids where vapor temperatures do not exceed 60 °C. For all tests, the test media defined in 14.1.1 can be used except where detonation flame arresters protect systems han-
dling vapors with a maximum experimental
safe gap (MESG) below 0.9 millimeters. Detonation flame arresters protecting such systems must be tested with appropriate media
(the same vapor or a media having a MESG
no greater than the vapor). Various gases
and their respective MESG are listed in attachment 1.
2.2 The tests in this standard are intended
to qualify detonation flame arresters for all
in-line applications independent of piping
configuration provided the operating pressure is equal to or less than the maximum
operating pressure limit specified in the
manufacturer’s certification and the diameter of the piping system in which the detonation arrester is to be installed is equal to or
less than the piping diameter used in the
testing.
NOTE: Detonation flame arresters meeting
this standard as Type I devices, which are
certified to be effective below 0 °C and which
can sustain three stable detonations without
being damaged or permanently deformed,
also comply with the minimum requirements
of the International Maritime Organization,
Maritime Safety Committee Circular No. 373
(MSC/Circ. 373/Rev.1).
3. Applicable Documents
3.1 ASTM Standards 1
A395 Ferritic Ductile Iron Pressure-Retaining Castings For Use At Elevated Temperatures.
F722 Welded Joints for Shipboard Piping Systems
F1155 Standard Practice for Selection and
Application of Piping System Materials
3.2 ANSI Standards 2
B16.5 Pipe Flanges and Flanged Fittings.
3.3 Other Documents
3.3.1 ASME Boiler and Pressure Vessel
Code 2
Section VIII, Division 1, Pressure Vessels
Section IX, Welding and Brazing Qualifications.
3.3.2 International Maritime Organization, Maritime Safety Committee 3
MSC/Circ. 373/Rev. 1—Revised Standards for
the Design, Testing and Locating of Devices to Prevent the Passage of Flame into
Cargo Tanks in Tankers.
3.3.3 International Electrotechnical Commission 4
Publication 79–1—Electrical Apparatus for
Explosive Gas Atmospheres.
4. Terminology
4.1 D P/Po—The dimensionless ratio, for
any deflagration and detonation test of 14.3,
of the maximum pressure increase (the maximum pressure minus the initial pressure),
as measured in the piping system on the side
1 Footnotes appear at the end of this article.
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of the arrester where ignition begins by the
device described in paragraph 14.3.3, to the
initial absolute pressure in the piping system. The initial pressure should be greater
than or equal to the maximum operating
pressure specified in paragraph 11.1.7.
4.2 Deflagration—A combustion wave that
propagates subsonically (as measured at the
pressure and temperature of the flame front)
by the transfer of heat and active chemical
species to the unburned gas ahead of the
flame front.
4.3 Detonation—A reaction in a combustion wave propagating at sonic or supersonic
(as measured at the pressure and temperature of the flame front) velocity. A detonation is stable when it has a velocity equal to
the speed of sound in the burnt gas or may be
unstable (overdriven) with a higher velocity
and pressure.
4.4 Detonation flame arrester—A device
which prevents the transmission of a detonation and a deflagration.
4.5 Flame speed—The speed at which a
flame propagates along a pipe or other system.
4.6 Flame Passage—The transmission of a
flame through a device.
4.7 Gasoline Vapors—A non-leaded petroleum distillate consisting essentially of aliphatic hydrocarbon compounds with a boiling range approximating 65 °C/75 °C.
5. Classification
5.1 The two types of detonation flame arresters covered in this specification are classified as follows:
5.1.1 Type I—Detonation flame arresters
acceptable for applications where stationary
flames may rest on the device.
5.1.2 Type II—Detonation flame arresters
acceptable for applications where stationary
flames are unlikely to rest on the device, and
further methods are provided to prevent
flame passage when a stationary flame occurs. One example of ‘‘further methods’’ is a
temperature monitor and an automatic shutoff valve.
6. Ordering Information
6.1 Orders for detonation flame arresters
under this specification shall include the following information as applicable:
6.1.1 Type (I or II).
6.1.2 Nominal pipe size.
6 1.3 Each gas or vapor in the system and
the corresponding MESG.
6.1.4 Inspection and tests other than specified by this standard.
6.1.5 Anticipated ambient air temperature
range.
6.1.6 Purchaser’s inspection requirements
(see section 10.1).
6.1.7 Description of installation.
6.1.8 Materials of construction (see section 7).
6.1.9 Maximum flow rate and the maximum design pressure drop for that maximum flow rate.
6.1.10 Maximum operating pressure.
7. Materials
7.1 The detonation flame arrester housing, and other parts or bolting used for pressure retention, shall be constructed of materials listed in ASTM F 1155 (incorporated by
reference, see § 154.106), or section VIII, Division 1 of the ASME Boiler and Pressure Vessel Code. Cast and malleable iron shall not
be used; however, ductile cast iron in accordance with ASTM A395 may be used.
7.1.1 Arresters, elements, gaskets, and
seals must be made of materials resistant to
attack by seawater and the liquids and vapors contained in the system being protected
(see section 6.1.3).
7.2 Nonmetallic materials, other than
gaskets and seals, shall not be used in the
construction of pressure retaining components of the detonation flame arrester.
7.2.1 Nonmetallic gaskets and seals shall
be non-combustible and suitable for the service intended.
7.3 Bolting materials, other than that of
section 7.1, shall be at least equal to those
listed in Table 1 of ANSI B16.5.
7.4 The possibility of galvanic corrosion
shall be considered in the selection of materials.
7.5 All other parts shall be constructed of
materials suitable for the service intended.
8. Other Requirements
8.1 Detonation flame arrester housings
shall be gas tight to prevent the escape of
vapors.
8.2 Detonation flame arrester elements
shall fit in the housing in a manner that will
insure tightness of metal-to-metal contacts
in such a way that flame cannot pass between the element and the housing.
8.2.1 The net free area through detonation
flame arrester elements shall be at least 1.5
times the cross-sectional area of the arrester
inlet.
8.3 Housings, elements, and seal gasket
materials shall be capable of withstanding
the maximum and minimum pressures and
temperatures to which the device may be exposed under both normal and the specified
fire test conditions in section 14, and shall be
capable of withstanding the hydrostatic
pressure test of section 9.2.3.
8.4 Threaded or flanged pipe connections
shall comply with the applicable B16 standards in ASTM F 1155 (incorporated by reference, see § 154.106). Welded joints shall
comply with ASTM F 722 (incorporated by
reference, see § 154.106).
8.5 All flat joints of the housing shall be
machined true and shall provide for a joint
having adequate metal-to-metal contact.
8.6 Where welded construction is used for
pressure retaining components, welded joint
design details, welding and non-destructive
testing shall be in accordance with Section
VIII, Division 1, of the ASME Code and
ASTM F 722 (incorporated by reference, see
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§ 154.106). Welders and weld procedures shall
be qualified in accordance with section IX of
the ASME Code.
8.7 The design of detonation flame arresters shall allow for ease of inspection and removal of internal elements for replacement,
cleaning or repair without removal of the entire device from the system.
8.8 Detonation flame arresters shall allow
for efficient drainage of condensate without
impairing their efficiency to prevent the passage of flame. The housing may be fitted
with one or more drain plugs for this purpose. The design of a drain plug should be
such so that by cursory visual inspection it
is obvious whether the drain has been left
open.
8.9 All fastenings shall be protected
against loosening.
8.10 Detonation flame arresters shall be
designed and constructed to minimize the effect of fouling under normal operating conditions.
8.11 Detonation flame arresters shall be
capable of operating over the full range of
ambient air temperatures anticipated.
8.12 Detonation flame arresters shall be of
first class workmanship and free from imperfections which may affect their intended
purpose.
8.13 Detonation flame arresters shall be
tested in accordance with section 9.
9. Tests
9.1 Tests shall be conducted by an independent laboratory capable of performing
the tests. The manufacturer, in choosing a
laboratory, accepts that it is a qualified
independent laboratory by determining that
it has (or has access to) the apparatus, facilities, personnel, and calibrated instruments
that are necessary to test detonation flame
arresters in accordance with this standard.
9.1.1 A test report shall be prepared by the
laboratory which shall include:
9.1.1.1 Detailed drawings of the detonation flame arrester and its components (including a parts list identifying the materials
of construction).
9.1.1.2 Types of tests conducted and results obtained. This shall include the maximum temperature reached and the length of
testing time in section 14.2 in the case of
Type II detonation flame arresters.
9.1.1.3 Description of approved attachments (reference 9.2.6).
9.1.1.4 Types of gases or vapors for which
the detonation flame arrester is approved.
9.1.1.5 Drawings of the test rig.
9.1.1.6 Record of all markings found on
the tested detonation flame arrester.
9.1.1.7 A report number.
9.2 One of each model Type I and Type II
detonation flame arrester shall be tested.
Where approval of more than one size of a
detonation flame arrester model is desired,
only the largest and smallest sizes need be
tested provided it is demonstrated by cal-
culation and/or other testing that intermediate size devices have equal or greater
strength to withstand the force of a detonation and have equivalent detonation arresting characteristics. A change of design, material, or construction which may affect the
corrosion resistance, or ability to resist endurance burning, deflagrations or detonations shall be considered a change of model
for the purpose of this paragraph.
9.2.1 The detonation flame arrester shall
have the same dimensions, configuration,
and most unfavorable clearances expected in
production units.
9.2.2 A corrosion test shall be conducted.
In this test, a complete detonation flame arrester, including a section of pipe similar to
that to which it will be fitted, shall be exposed to a 20% sodium chloride solution
spray at a temperature of 25 °C for a period
of 240 hours, and allowed to dry for 48 hours.
Following this exposure, all movable parts
shall operate properly and there shall be no
corrosion deposits which cannot be washed
off.
9.2.3 The detonation flame arrester shall
be subjected to a hydrostatic pressure test of
at least 350 psig for ten minutes without rupturing, leaking, or showing permanent distortion.
9.2.4 Flow characteristics as declared by
the manufacturer, shall be demonstrated by
appropriate tests.
9.2.5 Detonation flame arresters shall be
tested for endurance burn and deflagration/
detonation in accordance with the test procedures in section 14. Type I detonation
flame arresters shall show no flame passage
when subjected to both tests. Type II detonation flame arresters shall show no evidence
of flame passage during the detonation/deflagration tests in section 14.3. Type II detonation flame arresters shall be tested for endurance burn in accordance with section 14.2.
From the endurance burn test of a Type II
detonation flame arresters, the maximum
temperature reached and the test duration
shall be recorded and provided as part of the
laboratory test report.
9.2.6 Where a detonation flame arrester is
provided with cowls, weather hoods and deflectors, etc., it shall be tested in each configuration in which it is provided.
9.2.7 Detonation flame arresters which are
provided with a heating arrangement designed to maintain the surface temperature
of the device above 85 °C shall pass the required tests at the maximum heated operating temperature.
9.2.8 Each finished detonation arrester
shall be pneumatically tested at 10 psig to
ensure there are no defects or leakage.
10. Inspection
10.1 The manufacturer shall afford the
purchaser’s inspector all reasonable access
necessary to assure that the device is being
furnished in accordance with this standard.
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All examinations and inspections shall be
made at the place of manufacture, unless
otherwise agreed upon.
10.2 Each finished detonation arrester
shall be visually and dimensionally checked
to ensure that the device corresponds to this
standard, is certified in accordance with section 11 and is marked in accordance with section 12. Special attention shall be given to
the checking of welds and the proper fit-ups
of joints (see sections 8.5 and 8.6).
11. Certification
11.1 Manufacturer’s certification that a
detonation flame arrester meets this standard shall be provided in an instruction manual. The manual shall include as applicable:
11.1.1 Installation instructions and a description of all configurations tested (reference paragraph 9.2.6). Installation instructions to include the device’s limitations.
11.1.2 Operating instructions.
11.1.3 Maintenance requirements.
11.1.3.1 Instructions on how to determine
when arrester cleaning is required and the
method of cleaning.
11.1.4 Copy of test report (see section
9.1.1).
11.1.5 Flow test data, maximum temperature and time tested (Type II).
11.1.6 The ambient air temperature range
over which the device will effectively prevent the passage of flame.
NOTE: Other factors such as condensation
and freezing of vapors should be evaluated at
the time of equipment specification.
11.1.7 The maximum operating pressure
for which the device is suitable.
12. Marking
12.1 Each detonation flame arrester shall
be permanently marked indicating:
12.1.1 Manufacturer’s name or trademark.
12.1.2 Style, type, model or other manufacturer’s designation for the detonation
flame arrester.
12.1.3 Size of the inlet and outlet.
12.1.4 Type of device (Type I or II).
12.1.5 Direction of flow through the detonation flame arrester.
12.1.6 Test laboratory and report number.
12.1.7 Lowest MESG of gases that the detonation flame arrester is suitable for.
12.1.8 ASTM designation of this standard.
12.1.9 Ambient air operating temperature
range.
12.1.10 Maximum operating pressure.
13. Quality Assurance
13.1 Detonation flame arresters shall be
designed, manufactured and tested in a manner that ensures they meet the characteristics of the unit tested in accordance with
this standard.
13.2 The detonation flame arrester manufacturer shall maintain the quality of the arresters that are designed, tested and marked
in accordance with this standard. At no time
shall a detonation flame arrester be sold
with this standard designation that does not
meet the requirements herein.
14. Test Procedures for Detonation Arresters
14.1 Media/Air Mixtures
14.1.1 For vapors from flammable or combustible liquids with a MESG greater than or
equal to 0.9 mm, technical grade hexane or
gasoline vapors shall be used for all tests in
this section except technical grade propane
may be used for the deflagration/detonation
tests in section 14.3. For vapors with a MESG
less than 0.9 mm, the specific vapor (or alternatively, a media with a MESG less than or
equal to the MESG of the vapor) must be
used as the test medium in all Section 14
tests.
14.1.2 Hexane, propane, gasoline and other
test vapors shall be mixed with air to form
the most easily ignitable mixture. 5
14.2 Endurance Burn Test Procedure
14.2.1 An endurance burning test shall be
carried out as follows:
14.2.1.1 The test rig shall consist of an apparatus producing an explosive mixture, a
small tank with a diaphragm, a prototype of
the detonation flame arrester and a firing
source in close proximity to the test device
(see Figure 1). The detonation flame arrester
shall be installed so that the mixture emission is vertically upwards, or installed in the
position for which it is designed and which
will cause the most severe heating of the device under the prescribed endurance burn
conditions. In this position the mixture shall
be ignited.
14.2.1.2 Endurance burn test shall start by
using the most easily ignitable test vapor/air
mixture with the aid of a pilot flame or a
spark igniter at the outlet. The flammable
mixture may be reignited as necessary in the
course of the endurance burn.
14.2.1.3 Temperature measurement will be
performed on the surface of the arrester element half way between the center and its
edge.
14.2.1.4 By varying the proportions of the
flammable mixture and the flow rate, the
detonation flame arrester shall be heated by
a stable flame on the surface of the arrester
until the highest obtainable temperature is
reached on the ignited side or until the temperature on the side which was not ignited
(protected side) rises 100 °C.
14.2.1.5 The flammable mixture proportions will then be varied again until the conditions which result in the highest temperature on the protected side are achieved. This
temperature shall be maintained for a period
of ten minutes, after which the flow shall be
stopped and the conditions observed. The
highest attainable temperature is considered
to have been reached when any subsequent
rise of temperature does not exceed 0.5 °C per
minute over a ten minute period.
14.2.1.6 If difficulty arises in establishing
the highest attainable temperature on the
protected side, the following criteria shall
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apply. When the increase in temperature on
the protected side occurs so slowly that its
temperature does not rise 100 °C, the conditions which produced the highest temperature on the ignited side of the arrester will
be maintained for two hours. For the condition in which the temperature on the protected side continues to rise at a rate in excess of 0.5 °C per minute for a 10 minute period, endurance burning shall be continued,
using the most severe conditions of flammable mixtures and flow rate, for a period of
two hours. In either of these cases, at the
end of the two hour period, the flow shall be
stopped and the conditions observed. The
two hour interval shall be measured commencing with the setting of the conditions
which produced the most severe conditions
of mixture and flow rate. For Type I detonation flame arresters, flame passage shall not
occur during this test. For Type II detonation flame arresters, the maximum temperature obtained, and the time elapsed from the
time when the most severe conditions are set
to when flame passage occurs, shall be recorded. However, for Type II detonation
flame arresters the test may be terminated
15 minutes after setting the most severe conditions on the protected side.
14.3 Deflagration/Detonation Test Procedure
14.3.1 A detonation flame arrester shall be
installed at one end of a pipe of the same diameter as the inlet of the detonation flame
arrester (see Figure 2). The length and configuration of the test pipe shall develop a
stable detonation 6 at the device and shall be
capable, by change in its length or configuration, of developing deflagrations and unstable (overdriven) detonations as measured on
the side of the pipe where ignition occurs
(run-up side). For deflagration testing, two
test piping arrangements shall be used on
the outlet side of the detonation flame arrester (the side which is not ignited). In both
of the following end arrangements, the outlet side pipe diameter shall be equal to that
on the run-up side. In one arrangement, the
outlet side pipe shall be at least 10 pipe diameters long with a plastic bag over the free
end. (Alternate end of pipe closures are also
acceptable provided they easily give way
during the course of the test, and the closure
allows the required gas concentration to be
maintained throughout the test piping arrangement.) In the other arrangement the
outlet side pipe shall be fitted with a restriction located 0.6 meters from the outlet side
arrester flange. The size of the restriction
for each nominal size detonation flame arrester shall be as follows:
Nominal pipe diameter
(inches)
Restriction diameter (inches)
3
4
6
8
⁄
⁄
1
11⁄2
12
12
Nominal pipe diameter
(inches)
Restriction diameter (inches)
10
12
18
24
11⁄2
2
2
2
The entire pipe shall be filled with the most
easily ignitable vapor/air mixture to a test
pressure corresponding to or greater than
the upper limit of the device’s maximum operating pressure (see 11.1.7). In order to obtain this test pressure, a device such as a
bursting disc may be fitted on the open end
of the device in place of the plastic bag. The
concentration of the mixture should be
verified by appropriate testing of the gas
composition. The vapor/air mixture shall
then be ignited.
14.3.2 Flame speeds shall be measured by
optical devices capable of providing accuracy
of ±5%. These devices shall be situated no
more than a distance equal to 3% of the
length of the run-up pipe apart with one device no more than 8 inches from the end of
the test pipe to which the detonation flame
arrester is attached. In addition, each outlet
arrangement described in paragraph 14.3.1
shall be fitted with an optical device located
no more than 8 inches from the detonation
flame arrester outlet. 7
14.3.3 Explosion pressures within the pipe
shall be measured by a high frequency transducer situated in the test pipe no more than
8 inches from the run-up side of the housing
of the detonation flame arrester.
14.3.4 Using the first end arrangement (10
pipe diameter outlet) described in paragraph
14.3.1, a series of tests shall be conducted to
determine the test pipe length and configuration that results in the maximum unstable
(overdriven) detonation having the maximum measured flame speed at the detonation flame arrester. (These tests may also be
carried out using a single length of pipe with
igniters spaced at varying distances from the
arrester.) The flame speeds, explosion pressures and test pipe configurations shall be
recorded for each of these tests. The piping
configuration that resulted in the highest recorded unstable (overdriven) detonation
flame speed shall be used, and the device
shall be subjected to at least four additional
unstable (overdriven) detonations. In the
course of testing, the device shall also demonstrate its ability to withstand five stable
detonations, five deflagrations (as determined by flame speed) where D P/Po was less
than 1 and five deflagrations (as determined
by flame speed) where D P/Po was greater
than 1 but less than 10. Initiation of
deflagrations shall be at several locations to
generate a range for D P/Po. Deflagration
tests using the restricted outlet arrangement described in paragraph 14.3.1 shall then
be conducted. In these tests the device shall
demonstrate its ability to stop five
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deflagrations (as determined by flame speed)
generated by the same configurations which
resulted in D P/Po being less than 1 during
the deflagration tests which were conducted
without the restricted end arrangements,
and five deflagrations (as determined by
flame speed) generated by the same configurations which resulted in D P/Po being greater than 1 but less than 10 during the deflagration tests which were conducted without
the restricted end arrangements. No evidence of flame passage shall occur during
these tests. The flame speeds and explosion
pressures for each of these tests shall be recorded.
14.3.5 A device that successfully passes
the tests of 14.3.4 shall be considered to be directional (suitable for arresting a detonation
advancing only from the direction as tested)
except;
14.3.5.1 A device may be tested according
to 14.3.4 for detonations approaching from either direction, or
14.3.5.2 The design of the device is symmetrical where each end may be considered
to be identical when approached by a detonation from either direction.
1 Available from the American Society for
Testing and Materials (ASTM), 100 Barr Harbor Dr., West Conshohocken, PA 19428–2959.
2 Available from the American Society of
Mechanical Engineers International, Three
Park Avenue, New York, NY 10016–5990.
3 Available from the International Maritime Organization, 4 Albert Embankment,
London SE1 7SR, England.
4 Available from the International Electrotechnical Commission, 1 rue de Varembe, Geneva, Switzerland.
5 See IEC Publication 79–1.
6 Some data are available for the estimation of flame speeds in horizontal pipes
without detonation flame arresters. Some
data indicate that the presence of small obstacles, fittings or bends in the test pipe can
accelerate the flame speeds appreciably.
7 Other pressure and/or flame speed measuring techniques may be used if effective.
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Pt. 154, App. B
33 CFR Ch. I (7–1–10 Edition)
ATTACHMENT 1
Inflammable gas or vapour
Experimental maximum safe gap
mm
Methane ...........................................
Blast furnace gas ............................
Propane ...........................................
Butane .............................................
Pentane ...........................................
Hexane ............................................
Heptane ...........................................
Iso-octane ........................................
Decane ............................................
Benzene ..........................................
Xylene ..............................................
Cyclohexane ....................................
Acetone ...........................................
Ethylene ...........................................
Methyl-ethyl-ketone .........................
Carbon monoxide ............................
Methyl-acetate .................................
Ethyl-acetate ....................................
Propyl-acetate .................................
Butyl-acetate ....................................
Amyl-acetate ....................................
Methyl alcohol .................................
Ethyl alcohol ....................................
Iso-butyl-alcohol ..............................
Butyl-alcohol (Normal) .....................
Amyl-alcohol ....................................
Ethyl-ether .......................................
Coal gas (H2 57%) ..........................
Acetylene .........................................
Carbon disulphide ...........................
Hydrogen .........................................
Blue water gas (H2 53% CO 47%)
Ethyl nitrate .....................................
Ammonia .........................................
Ethylene oxide .................................
Ethyl nitrite .......................................
1.170
1.193
0.965
1.066
1.016
0.965
0.965
1.040
1.016
0.99
1.066
0.94
1.016
0.71
1.016
0.915
0.990
1.04
1.04
1.016
0.99
0.915
1.016
0.965
0.94
0.99
0.864
0.482
≤0.025
0.203
0.102
0.203
≤0.025
1 3.33
0.65
0.922
in.
0.046
0.047
0.038
0.042
0.040
0.038
0.038
0.041
0.040
0.039
0.042
0.037
0.040
0.028
0.040
0.036
0.039
0.041
0.041
0.040
0.039
0.036
0.040
0.038
0.037
0.039
0.034
0.019
≤0.001
0.008
0.004
0.008
≤0.001
1 0.133
0.026
0.038
1 Approximately.
[CGD 88–102, 55 FR 25435, June 21, 1990; 55 FR
39270, Sept. 26, 1990, as amended by CGD 96–
026, 61 FR 33666, June 28, 1996; USCG–1999–
5832, 64 FR 34715, June 29, 1999; USCG–2000–
7223, 65 FR 40058, June 29, 2000; USCG–2010–
0351, 75 FR 36284, June 25, 2010]
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APPENDIX B TO PART 154—STANDARD
SPECIFICATION FOR TANK VENT
FLAME ARRESTERS
1. Scope
1.1 This standard provides the minimum
requirements for design, construction, performance and testing of tank vent flame arresters.
2. Intent
2.1 This standard is intended for flame arresters protecting systems containing vapors
of flammable or combustible liquids with a
flashpoint that does not exceed 60 °C. The
test media defined in 14.1.1 can be used except where arresters protect systems handling vapors with a maximum experimental
safe gap (MESG) below 0.9 millimeters.
Flame arresters protecting such systems
must be tested with appropriate media (the
same vapor or a media having a MESG no
greater than the vapor). Various gases and
their respective MESG are listed in Attachment 1.
NOTE: Flame arresters meeting this standard also comply with the minimum requirements of the International Maritime Organization, Maritime Safety Committee Circular
No. 373 (MSC/Circ. 373/Rev. 1).
3. Applicable Documents
3.1 ASTM Standards 1 F722 Welded Joints
for Shipboard Piping Systems; F1155 Standard Practice for Selection and Application of
Piping System Materials
3.2 ANSI Standards 2 B16.5 Pipe Flanges
and Flanged Fittings.
3.3 Other Documents
3.3.1 ASME Boiler and Pressure Vessel
Code 2 section VIII, Division 1, Pressure Vessels; section IX, Welding and Brazing Qualifications.
3.3.2 International Maritime Organization, Maritime Safety Committee 3 MSC/Circ.
373/Rev. 1—Revised Standards for the Design,
Testing and Locating of Devices to Prevent
the Passage of Flame into Cargo Tanks in
Tankers.
3.3.3 International Electrotechnical Commission 4 Publication 79.1—Electrical Apparatus for Explosive Gas Atmospheres.
4. Terminology
4.1 Flame arrester—A device to prevent
the passage of flame in accordance with a
specified performance standard. Its flame arresting element is based on the principle of
quenching.
4.2 Flame speed—The speed at which a
flame propagates along a pipe or other system.
4.3 Flame Passage—The transmission of a
flame through a flame arrester.
4.4 Gasoline Vapors—A non-leaded petroleum distillate consisting essentially of aliphatic hydrocarbon compounds with a boiling range approximating 65 °C/75 °C.
5. Classification
5.1 The two types of flame arresters covered in this specification are classified as follows:
5.1.1 Type I—Flame arresters acceptable
for end-of-line applications.
5.1.2 Type II—Flame arresters acceptable
for in-line applications.
6. Ordering Information
6.1 Orders for flame arresters under this
specification shall include the following information as applicable:
6.1.1 Type (I or II).
6.1.2 Nominal pipe size.
6.1.3 Each gas or vapor in the tank being
protected by the flame arrester, and the corresponding MESG.
1 Footnotes appear at the end of this article.
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6.1.4 Inspection and tests other than specified by this standard.
6.1.5 Anticipated ambient air temperature
range.
6.1.6 Purchaser’s inspection requirements
(see section 10.1).
6.1.7 Description of installation (distance
and configuration of pipe between the arrester, and the atmosphere or potential ignition source) (see section 9.2.4.2).
6.1.8 Materials of construction (see section 7).
6.1.9 Maximum flow rate and the design
pressure drop for that maximum flow rate.
7. Materials
7.1 The flame arrester housing, and other
parts or bolting used for pressure retention,
shall be constructed of materials listed in
ASTM F 1155 (incorporated by reference, see
§ 154.106), or section VIII, Division 1 of the
ASME Boiler and Pressure Vessel Code.
7.1.1 Arresters, elements, gaskets, and
seals must be of materials resistant to attack by seawater and the liquids and vapors
contained in the tank being protected (see
section 6.1.3).
7.2 Nonmetallic materials, other than
gaskets and seals, shall not be used in the
construction of pressure retaining components of the flame arrester.
7.2.1 Nonmetallic gaskets and seals shall
be non-combustible and suitable for the service intended.
7.3 Bolting materials, other than that of
Section 7.1, shall be at least equal to those
listed in Table 1 of ANSI B16.5.
7.4 The possibility of galvanic corrosion
shall be considered in the selection of materials.
7.5 All other parts shall be constructed of
materials suitable for the service intended.
8. Other Requirements
8.1 Flame arrester housings shall be gas
tight to prevent the escape of vapors.
8.2 Flame arrester elements shall fit in
the housing in a manner that will insure
tightness of metal-to-metal contacts in such
a way that flame cannot pass between the
element and the housing.
8.2.1 The net free area through flame arrester elements shall be at least 1.5 times the
cross-sectional area of the arrester inlet.
8.3 Housings and elements shall be of substantial construction and designed for the
mechanical and other loads intended during
service. In addition, they shall be capable of
withstanding the maximum and minimum
pressures and temperatures to which the device may be exposed under both normal and
the specified fire test conditions in section
14.
8.4 Threaded or flanged pipe connections
shall comply with the applicable B16 standards in ASTM F 1155 (incorporated by reference, see § 154.106). Welded joints shall
comply with ASTM F 722 (incorporated by
reference, see § 154.106).
8.5 All flat joints of the housing shall be
machined true and shall provide for a joint
having adequate metal-to-metal contact.
8.6 Where welded construction is used for
pressure retaining components, welded joint
design details, welding and non-destructive
testing shall be in accordance with section
VIII, Division 1, of the ASME Code and
ASTM F 722 (incorporated by reference, see
§ 154.106). Welders and weld procedures shall
be qualified in accordance with section IX of
the ASME Code.
8.7 The design of flame arresters shall
allow for ease of inspection and removal of
internal elements for replacement, cleaning
or repair without removal of the entire device from the system.
8.8 Flame arresters shall allow for efficient drainage of condensate without impairing their efficiency to prevent the passage of
flame.
8.9 All fastenings shall be protected
against loosening.
8.10 Flame arresters shall be designed and
constructed to minimize the effect of fouling
under normal operating conditions.
8.11 Flame arresters shall be capable of
operating over the full range of ambient air
temperatures anticipated.
8.12 End-of-line flame arresters shall be so
constructed as to direct the efflux vertically
upward.
8.13 Flame arresters shall be of first class
workmanship and free from imperfections
which may affect their intended purpose.
8.14 Tank vent flame arresters shall show
no flame passage when subjected to the tests
in 9.2.4.
9. Prototype Tests
9.1 Tests shall be conducted by an independent laboratory capable of performing
the tests. The manufacturer, in choosing a
laboratory, accepts that it is a qualified
independent laboratory by determining that
it has (or has access to) the apparatus, facilities, personnel, and calibrated instruments
that are necessary to test flame arresters in
accordance with this standard.
9.1.1 A test report shall be prepared by the
laboratory which shall include:
9.1.1.1 Detailed drawings of the flame arrester and its components (including a parts
list identifying the materials of construction).
9.1.1.2 Types of tests conducted and results obtained.
9.1.1.3 Specific advice on approved attachments (see section 9.2.4.1).
9.1.1.4 Types of gases or vapors for which
the flame arrester is approved (see section
6.1.3).
9.1.1.5 Drawings of the test rig.
9.1.1.6 Record of all markings found on
the tested flame arrester.
9.1.1.7 A report number.
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33 CFR Ch. I (7–1–10 Edition)
9.2 One of each model Type I and Type II
flame arrester shall be tested. Where approval of more than one size of a flame arrester model is desired, the largest and
smallest sizes shall be tested. A change of design, material, or construction which may
affect the corrosion resistance, endurance
burn, or flashback capabilities of the flame
arrester shall be considered a change of
model for the purpose of this paragraph.
9.2.1 The flame arrester shall have the
same dimensions, configuration, and the
most unfavorable clearances expected in production units.
9.2.2 A corrosion test shall be conducted.
In this test, a complete arrester, including a
section of pipe similar to that to which it
will be fitted, shall be exposed to a 20% sodium chloride solution spray at a temperature of 25 degrees C for a period of 240 hours,
and allowed to dry for 48 hours. Following
this exposure, all movable parts shall operate properly and there shall be no corrosion
deposits which cannot be washed off.
9.2.3 Performance characteristics as declared by the manufacturer, such as flow
rates under both positive and negative pressure, operating sensitivity, flow resistance,
and velocity, shall be demonstrated by appropriate tests.
9.2.4 Tank vent flame arresters shall be
tested for endurance burn and flashback in
accordance with the test procedures in section 14. The following constraints apply:
9.2.4.1 Where a Type I flame arrester is
provided with cowls, weather hoods and deflectors, etc., it shall be tested in each configuration in which it is provided.
9.2.4.2 Type II arresters shall be specifically tested with the inclusion of all pipes,
tees, bends, cowls, weather hoods, etc., which
may be fitted between the arrester and the
atmosphere.
9.2.5 Devices which are provided with a
heating arrangement shall pass the required
tests at the heated temperature.
9.2.6 After all tests are completed, the device shall be disassembled and examined, and
no part of the device shall be damaged or
show permanent deformation.
10. Inspection
10.1 The manufacturer shall afford the
purchaser’s inspector all reasonable facilities necessary to assure that the material is
being furnished in accordance with this
standard. All examinations and inspections
shall be made at the place of manufacture,
unless otherwise agreed upon.
10.2 Each finished flame arrester shall be
visually and dimensionally checked to ensure that the device corresponds to this
standard, is certified in accordance with section 11 and is marked in accordance with section 12. Special attention shall be given to
checking the proper fit-up of joints (see sections 8.5 and 8.6)
11. Certification
11.1 Manufacturer’s certification that a
flame arrester has been constructed in accordance with this standard shall be provided in an instruction manual. The manual
shall include as applicable:
11.1.1 Installation instructions and a description of all configurations tested (reference paragraph 9.2.4.1 and 9.2.4.2). Installation instructions to include manufacturer’s
recommended limitations based on all configurations tested.
11.1.2 Operating instructions.
11.1.3 Maintenance requirements.
11.1.3.1 Instructions on how to determine
when flame arrester cleaning is required and
the method of cleaning.
11.1.4 Copy of test report (see section
9.1.1).
11.1.5 Flow test data, including flow rates
under both positive and negative pressures,
operating sensitivity, flow resistance, and
velocity.
11.1.6 The ambient air temperature range
over which the device will effectively prevent the passage of flame. (NOTE: Other factors such as condensation and freezing of vapors should be evaluated at the time of
equipment specification.)
12. Marking
12.1 Each flame arrester shall be permanently marked indicating:
12.1.1 Manufacturer’s name or trademark.
12.1.2 Style, type, model or other manufacturer’s designation for the flame arrester.
12.1.3 Size of the inlet and outlet.
12.1.4 Type of device (Type I or II).
12.1.5 Direction of flow through the flame
arrester.
12.1.6 Test laboratory and report number.
12.1.7 Lowest MESG of gases for which the
flame arrester is suitable for.
12.1.8 Ambient air operating temperature
range.
12.1.9 ASTM designation of this standard.
13. Quality Assurance
13.1 Flame arresters shall be designed,
manufactured and tested in a manner that
ensures they meet the characteristics of the
unit tested in accordance with this standard.
13.2 The flame arrester manufacturer
shall maintain the quality of the flame arresters that are designed, tested and marked
in accordance with this standard. At no time
shall a flame arrester be sold with this
standard designation that does not meet the
requirements herein.
14. Test Procedures for Flame Arresters
14.1 Media/Air Mixtures
14.1.1 For vapors from flammable or combustible liquids with a MESG greater than or
equal to 0.9 mm, technical grade hexane or
gasoline vapors shall be used for all tests in
this section except technical grade propane
may be used for the flashback test in Section
14.2. For vapors with a MESG less than 0.9
mm, the specific vapor (or alternatively, a
media with a MESG less than or equal to the
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MESG of the vapor) must be used as the test
medium in all section 14 tests.
14.1.2 Hexane, propane, gasoline and
chemical vapors shall be mixed with air to
form the most easily ignitable mixture. 5
14.2 Flashback Test
14.2.1 A flashback test shall be carried out
as follows:
14.2.1.1 The test rig shall consist of an apparatus producing an explosive mixture, a
small tank with a diaphragm, a prototype of
the flame arrester, a plastic bag 6 and a firing
source in three positions (see Figure 1). 7
14.2.1.2 The tank, flame arrester assembly
and the plastic bag enveloping the prototype
flame arrester shall be filled so that this volume contains the most easily ignitable
vapor/air mixture. 8 The concentration of the
mixture should be verified by appropriate
testing of the gas composition in the plastic
bag. Three ignition sources shall be installed
along the axis of the bag, one close to the
flame arrester, another as far away as possible therefrom, and the third at the midpoint between these two. These three sources
shall be fired in succession, one during each
of the three tests. Flame passage shall not
occur during this test.
14.2.1.3 If flame passage occurs, the tank
diaphragm will burst and this will be audible
and visible to the operator by the emission
of a flame. Flame, heat and pressure sensors
may be used as an alternative to a bursting
diaphragm.
14.3 Endurance Burn Test
14.3.1 An endurance burning test shall be
carried out as follows:
14.3.1.1 The test rig as referred to in 14.2
may be used, without the plastic bag. The
flame arrester shall be so installed that the
mixture emission is vertical. In this position
the mixture shall be ignited.
14.3.1.2 Endurance
burning
shall
be
achieved by using the most easily ignitable
test vapor/air mixture with the aid of a pilot
flame or a spark igniter at the outlet. By
varying the proportions of the flammable
mixture and the flow rate, the arrester shall
be heated until the highest obtainable tem-
perature on the cargo tank side of the arrester is reached. The highest attainable
temperature may be considered to have been
reached when the rate of rise of temperature
does not exceed 0.5 °C per minute over a ten
minute period. This temperature shall be
maintained for a period of ten minutes, after
which the flow shall be stopped and the conditions observed. If difficulty arises in establishing the highest attainable temperature,
the following criteria shall apply. When the
temperature appears to be approaching the
maximum temperature, using the most severe conditions of flammable mixtures and
flow rate, but increases at a rate in excess of
0.5 °C per minute over a ten minute period,
endurance burning shall be continued for a
period of two hours after which the flow
shall be stopped and the conditions observed.
Flame passage shall not occur during this
test.
1 American Society for Testing and Materials (ASTM), 100 Barr Harbor Dr., West
Conshohocken, PA 19428–2959.
2 Available from the American Society of
Mechanical Engineers International, Three
Park Avenue, New York, NY 10016–5990.
3 Available from the International Maritime Organization, 4 Albert Embankment,
London SEl 7SR, England.
4 Available from the International Electrotechnical Commission, 1 rue de Varembe, Geneva, Switzerland
5 See IEC Publication 79–1.
6 The dimensions of the plastic bag are dependent on those of the flame arrester. The
plastic bag may have a circumference of 2 m,
a length of 2.5 m and a wall thickness of .05
m.
7 In order to avoid remnants of the plastic
bag from falling back on to the flame arrester being tested after ignition of the fuel/
air mixture, it may be useful to mount a
coarse wire frame across the flame arrester
within the plastic bag. The frame should be
constructed so as not to interfere with the
test result.
8 See IEC Publication 79–1.
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Coast Guard, DHS
Pt. 154, App. C
ATTACHMENT 1
Inflammable gas or vapor
Methane ...........................................
Blast furnace gas ............................
Propane ...........................................
Butane .............................................
Pentane ...........................................
Hexane ............................................
Heptane ...........................................
Iso-octane ........................................
Decane ............................................
Benzene ..........................................
Xylene ..............................................
Cyclohexane ....................................
Acetone ...........................................
Ethylene ...........................................
Methyl-ethyl-ketone .........................
Carbon monoxide ............................
Methyl-acetate .................................
Ethyl-acetate ....................................
Propyl-acetate .................................
Butyl-acetate ....................................
Amyl-acetate ....................................
Methyl alcohol .................................
Ethyl alcohol ....................................
Iso-butyl-alcohol ..............................
Butyl-alcohol (Normal) .....................
Amyl-alcohol ....................................
Ethyl-ether .......................................
Coal gas (H2 57%) ..........................
Acetylene .........................................
Carbon disulphide ...........................
Hydrogen .........................................
Blue water gas (H2 53% CO 47%)
Ethyl nitrate .....................................
Ammonia .........................................
Ethylene oxide .................................
Ethyl nitrite .......................................
Experimental maximum safe gap
mm
in.
1.170
1.193
0.965
1.066
1.016
0.965
0.965
1.040
1.016
0.99
1.066
0.94
1.016
0.71
1.016
0.915
0.990
1.04
1.04
1.016
0.99
0.915
1.016
0.965
0.94
0.99
0.864
0.482
<0.025
0.203
0.102
0.203
<0.025
13.33
0.65
0.922
0.046
0.047
0.038
0.042
0.040
0.038
0.038
0.041
0.040
0.039
0.042
0.037
0.040
0.028
0.040
0.036
0.039
0.041
0.041
0.040
0.039
0.036
0.040
0.038
0.037
0.039
0.034
0.019
<0.001
0.008
0.004
0.008
<0.001
10.133
0.026
0.038
1Approximately.
[CGD 88–102, 55 FR 25441, June 21, 1990, as
amended by USCG–1999–5832, 64 FR 34715,
June 29, 1999; USCG–2000–7223, 65 FR 40058,
June 29, 2000]
APPENDIX C TO PART 154—GUIDELINES
FOR DETERMINING AND EVALUATING
REQUIRED RESPONSE RESOURCES FOR
FACILITY RESPONSE PLANS
1. Purpose
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1.1 The purpose of this appendix is to describe the procedures for identifying response resources to meet the requirements of
subpart F of this part. These guidelines will
be used by the facility owner or operator in
preparing the response plan and by the Captain of the Port (COTP) when reviewing
them. Response resources identified in subparts H and I of this part should be selected
using the guidelines in section 2 and Table 1
of this appendix.
2. Equipment Operability and Readiness
2.1 All equipment identified in a response
plan must be designed to operate in the con-
ditions expected in the facility’s geographic
area. These conditions vary widely based on
location and season. Therefore, it is difficult
to identify a single stockpile of response
equipment that will function effectively in
each geographic location.
2.2 Facilities handling, storing, or transporting oil in more than one operating environment as indicated in Table 1 of this appendix must identify equipment capable of
successfully functioning in each operating
environment.
2.3 When identifying equipment for response plan credit, a facility owner or operator must consider the inherent limitations
in the operability of equipment components
and response systems. The criteria in Table
1 of this appendix should be used for evaluating the operability in a given environment.
These criteria reflect the general conditions
in certain operating areas.
2.3.1 The Coast Guard may require documentation that the boom identified in a response plan meets the criteria in Table 1. Absent acceptable documentation, the Coast
Guard may require that the boom be tested
to demonstrate that it meets the criteria in
Table 1. Testing must be in accordance with
ASTM F 715 (incorporated by reference, see
§ 154.106), or other tests approved by the
Coast Guard.
2.4 Table 1 of this appendix lists criteria
for oil recovery devices and boom. All other
equipment necessary to sustain or support
response operations in the specified operating environment must be designed to function in the same conditions. For example,
boats which deploy or support skimmers or
boom must be capable of being safely operated in the significant wave heights listed
for the applicable operating environment.
2.5 A facility owner or operator must
refer to the applicable local contingency
plan or ACP, as appropriate, to determine if
ice, debris, and weather-related visibility are
significant factors in evaluating the operability of equipment. The local contingency
plan or ACP will also identify the average
temperature ranges expected in the facility’s
operating area. All equipment identified in a
response plan must be designed to operate
within those conditions or ranges.
2.6 The requirements of subparts F, G, H
and I of this part establish response resource
mobilization and response times. The distance of the facility from the storage location of the response resources must be used
to determine whether the resources can arrive on scene within the stated time. A facility owner or operator shall include the time
for notification, mobilization, and travel
time of response resources identified to meet
the maximum most probable discharge and
Tier 1 worst case discharge response time requirements. For subparts F and G, tier 2 and
3 response resources must be notified and
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33 CFR Ch. I (7–1–10 Edition)
mobilized as necessary to meet the requirements for arrival on scene in accordance
with §§ 154.1045 or 154.1047 of subpart F, or
§ 154.1135 of subpart G, as appropriate. An on
water speed of 5 knots and a land speed of 35
miles per hour is assumed unless the facility
owner or operator can demonstrate otherwise.
2.7 For subparts F and G, in identifying
equipment, the facility owner or operator
shall list the storage location, quantity, and
manufacturer’s make and model. For oil recovery devices, the effective daily recovery
capacity, as determined using section 6 of
this appendix must be included. For boom,
the overall boom height (draft plus
freeboard) should be included. A facility
owner or operator is responsible for ensuring
that identified boom has compatible connectors.
2.8 For subparts H and I, in identifying
equipment, the facility owner or operator
shall list the storage location, quantity, and
manufacturer’s make and model. For boom,
the overall boom height (draft plus
freeboard) should be included. A facility
owner or operator is responsible for ensuring
that identified boom has compatible connectors.
3. Determining Response Resources Required for
the Average Most Probable Discharge
3.1 A facility owner or operator shall
identify sufficient response resources available, through contract or other approved
means as described in § 154.1028(a), to respond
to the average most probable discharge. The
equipment must be designed to function in
the operating environment at the point of
expected use.
3.2 The response resources must include:
3.2.1 1,000 feet of containment boom or
two times the length of the largest vessel
that regularly conducts oil transfers to or
from the facility, whichever is greater, and a
means deploying it available at the spill site
within 1 hour of the discovery of a spill.
3.2.2 Oil recovery devices with an effective daily recovery capacity equal to the
amount of oil discharged in an average most
probable discharge or greater available at
the facility within 2 hours of the detection of
an oil discharge.
3.2.3 Oil storage capacity for recovered
oily material indicated in section 9.2 of this
appendix.
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4. Determining Response Resources Required for
the Maximum Most Probable Discharge
4.1 A facility owner or operator shall
identify sufficient response resources available, by contract or other approved means as
described in § 154.1028(a), to respond to discharges up to the maximum most probable
discharge volume for that facility. This will
require response resources capable of con-
taining and collecting up to 1,200 barrels of
oil or 10 percent of the worst case discharge,
whichever is less. All equipment identified
must be designed to operate in the applicable
operating environment specified in Table 1 of
this appendix.
4.2 Oil recovery devices identified to meet
the applicable maximum most probable discharge volume planning criteria must be located such that they arrive on scene within
6 hours in higher volume port areas (as defined in 154.1020) and the Great Lakes and
within 12 hours in all other areas.
4.3 Because rapid control, containment,
and removal of oil is critical to reduce spill
impact, the effective daily recovery capacity
for oil recovery devices must equal 50 percent of the planning volume applicable for
the facility as determined in section 4.1 of
this appendix. The effective daily recovery
capacity for oil recovery devices identified in
the plan must be determined using the criteria in section 6 of this appendix.
4.4 In addition to oil recovery capacity,
the plan must identify sufficient quantities
of containment boom available, by contract
or other approved means as described in
§ 154.1028(a), to arrive within the required response times for oil collection and containment and for protection of fish and wildlife
and sensitive environments. While the regulation does not set required quantities of
boom for oil collection and containment, the
response plan must identify and ensure, by
contract or other approved means as described in § 154.1028(a), the availability of the
boom identified in the plan for this purpose.
4.5 The plan must indicate the availability of temporary storage capacity to
meet the guidelines of section 9.2 of this appendix. If available storage capacity is insufficient to meet this level, then the effective
daily recovery capacity must be derated to
the limits of the available storage capacity.
4.6 The following is an example of a maximum most probable discharge volume planning calculation for equipment identification in a higher volume port area: The facility’s worst case discharge volume is 20,000
barrels. Ten percent of this is 2,000 barrels.
Since this is greater than 1,200 barrels, 1,200
barrels is used as the planning volume. The
effective daily recovery capacity must be 50
percent of this, or 600 barrels per day. The
ability of oil recovery devices to meet this
capacity will be calculated using the procedures in section 6 of this appendix. Temporary storage capacity available on scene
must equal twice the daily recovery rate as
indicated in section 9 of this appendix, or
1,200 barrels per day. This is the information
the facility owner or operator will use to
identify and ensure the availability of,
through contract or other approved means as
described in § 154.1028(a), the required response resources. The facility owner will also
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need to identify how much boom is available
for use.
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5. Determining Response Resources Required for
the Worst Case Discharge to the Maximum Extent Practicable
5.1 A facility owner or operator shall
identify and ensure availability of, by contract or other approved means, as described
in § 154.1028(a), sufficient response resources
to respond to the worst case discharge of oil
to the maximum extent practicable. Section
7 of this appendix describes the method to
determine the required response resources.
5.2 Oil spill response resources identified
in the response plan and available through
contract or other approved means, as described in § 154.1028(a), to meet the applicable
worst case discharge planning volume must
be located such that they can arrive at the
scene of a discharge within the times specified for the applicable response tiers listed in
§ 154.1045.
5.3 The effective daily recovery capacity
for oil recovery devices identified in a response plan must be determined using the
criteria in section 6 of this appendix. A facility owner or operator shall identify the storage locations of all response resources that
must be used to fulfill the requirements for
each tier. The owner or operator of a facility
whose required daily recovery capacity exceeds the applicable response capability caps
in Table 5 of this appendix shall identify
sources of additional equipment, their locations, and the arrangements made to obtain
this equipment during a response. The owner
or operator of a facility whose calculated
planning volume exceeds the applicable contracting caps in Table 5 shall identify
sources of additional equipment equal to
twice the cap listed in Tiers 1, 2, and 3 or the
amount necessary to reach the calculated
planning volume, whichever is lower. The resources identified above the cap must be capable of arriving on scene not later than the
Tiers 1, 2, and 3 response times in § 154.1045.
No contract is required. While general listings of available response equipment may be
used to identify additional sources, a response plan must identify the specific
sources, locations, and quantities of equipment that a facility owner or operator has
considered in his or her planning. When listing Coast Guard classified oil spill removal
organization(s) which have sufficient removal capacity to recover the volume above
the response capability cap for the specific
facility, as specified in Table 5 of this appendix, it is not necessary to list specific quantities of equipment.
5.4 A facility owner or operator shall
identify the availability of temporary storage capacity to meet the requirements of
section 9.2 of this appendix. If available storage capacity is insufficient to meet this requirement, then the effective daily recovery
capacity must be derated to the limits of the
availabile storage capacity.
5.5 When selecting response resources necessary to meet the response plan requirements, the facility owner or operator must
ensure that a portion of those resources are
capable of being used in close-to-shore response activities in shallow water. The following percentages of the on-water response
equipment identified for the applicable geographic area must be capable of operating in
waters of 6 feet or less depth:
(i) Offshore—10 percent
(ii) Nearshore/inland/Great Lakes/rivers
and canals—20 percent.
5.6 In addition to oil spill recovery devices, a facility owner or operator shall identify sufficient quantities of boom that are
available, by contract or other approved
means as described in § 154.1028(a), to arrive
on scene within the required response times
for oil containment and collection. The specific quantity of boom required for collection
and containment will depend on the specific
recovery equipment and strategies employed. A facility owner or operator shall
also identify sufficient quantities of oil containment boom to protect fish and wildlife
and sensitive environments for the number
of days and geographic areas specified in
Table 2. Sections 154.1035(b)(4)(iii) and
154.1040(a), as appropriate, shall be used to
determine the amount of containment boom
required, through contract or other approved
means as described in § 154.1028(a), to protect
fish and wildlife and sensitive environments.
5.7 A facility owner or operator must also
identify, through contract or other approved
means as described in § 154.1028(a), the availability of an oil spill removal organization
capable of responding to a shoreline cleanup
operation involving the calculated volume of
oil and emulsified oil that might impact the
affected shoreline. The volume of oil that
must be planned for is calculated through
the application of factors contained in Tables 2 and 3. The volume calculated from
these tables is intended to assist the facility
owner or operator in identifying a contractor
with sufficient resources and expertise. This
planning volume is not used explicitly to determine a required amount of equipment and
personnel.
6. Determining Effective Daily Recovery
Capacity for Oil Recovery Devices
6.1 Oil recovery devices identified by a facility owner or operator must be identified
by manufacturer, model, and effective daily
recovery capacity. These rates must be used
to determine whether there is sufficient capacity to meet the applicable planning
critieria for the average most probable discharge, maximum most probable discharge,
and worst case discharge to the maximum
extent practicable.
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33 CFR Ch. I (7–1–10 Edition)
6.2 For the purpose of determining the effective daily recovery capacity of oil recovery devices, the formula listed in section
6.2.1 of this appendix will be used. This method considers potential limitations due to
available daylight, weather, sea state, and
percentage of emulsified oil in the recovered
material. The Coast Guard may assign a
lower efficiency factor to equipment listed in
a response plan if it determines that such a
reduction is warranted.
6.2.1 The following formula must be used
to calculate the effective daily recovery capacity:
R=T×24 hours×E
R=Effective daily recovery capacity
T=Throughout rate in barrels per hour
(nameplate capacity)
E=20 percent Efficiency factor (or lower factor as determined by Coast Guard)
6.2.2 For those devices in which the pump
limits the throughput of liquid, throughput
rate will be calculated using the pump capacity.
6.2.3 For belt or mop type devices, the
throughput rate will be calculated using the
speed of the belt or mop through the device,
assumed thickness of oil adhering to or collected by the device, and surface area of the
belt or mop. For purposes of this calculation,
the assumed thickness of oil will be 1/4 inch.
6.2.4 Facility owners or operators including oil recovery devices whose throughput is
not measurable using a pump capacity or
belt/mop speed may provide information to
support an alternative method of calculation. This information must be submitted
following the procedures in paragraph 6.3.2 of
this appendix.
6.3 As an alternative to 6.2, a facility
owner or operator may submit adequate evidence that a different effective daily recovery capacity should be applied for a specific
oil recovery device. Adequate evidence is actual verified performance data in spill conditions or tests using ASTM F 631 (incorporated by reference, see § 154.106), or an
equivalent test approved by the Coast Guard.
6.3.1 The following formula must be used
to calculate the effective daily recovery capacity under this alternative:
R=D×U
R=Effective daily recovery capacity
D=Average Oil Recovery Rate in barrels per
hour (Item 26 in ASTM F 808; Item 13.2.16
in ASTM F 631; or actual performance
data)
U=Hours per day that a facility owner or operator can document capability to operate
equipment under spill conditions. Ten
hours per day must be used unless a facility owner or operator can demonstrate
that the recovery operation can be sustained for longer periods.
6.3.2 A facility owner or operator proposing a different effective daily recovery
rate for use in a response plan shall provide
data for the oil recovery devices listed. The
following is an example of these calculations:
A weir skimmer identified in a response
plan has a manufacturer’s rated throughput
at the pump of 267 gallons per minute (gpm).
267 gpm=381 barrels per hour
R=381×24×.2=1829 barrels per day
After testing using ASTM procedures, the
skimmer’s oil recovery rate is determined to
be 220 gpm. The facility owner of operator
identifies sufficient response resources available to support operations 12 hours per day.
220 gpm=314 barrels per hour
R=314×12=3768 barrels per day
The facility owner or operator will be able
to use the higher rate if sufficient temporary
oil storage capacity is available. Determinations of alternative efficiency factors under
paragraph 6.2 or alternative effective daily
recovery capacities under paragraph 6.3 of
this appendix will be made by Commandant,
(CG–535), 2100 2nd St., SW., Stop 7363, Washington, DC 20593–7363. Response contractors
or equipment manufacturers may submit required information on behalf of multiple facility owners or operators directly in lieu of
including the request with the response plan
submission.
7. Calculating the Worst Case Discharge
Planning Volumes
7.1 The facility owner or operator shall
plan for a response to a facility’s worst case
discharge. The planning for on-water recovery must take into account a loss of some oil
to the environment due to evaporative and
natural dissipation, potential increases in
volume due to emulsification, and the potential for deposit of some oil on the shoreline.
7.2 The following procedures must be used
to calculate the planning volume used by a
facility owner or operator for determining
required on water recovery capacity:
7.2.1 The following must be determined:
The worst case discharge volume of oil in the
facility; the appropriate group(s) for the type
of oil handled, stored, or transported at the
facility (non-persistent (Group I) or persistent (Groups II, III, or IV)); and the facility’s specific operating area. Facilities which
handle, store, or transport oil from different
petroleum oil groups must calculate each
group separately. This information is to be
used with Table 2 of this appendix to determine the percentages of the total volume to
be used for removal capacity planning. This
table divides the volume into three categories: Oil lost to the environment; oil deposited on the shoreline; and oil available for
on-water recovery.
7.2.2 The on-water oil recovery volume
must be adjusted using the appropriate
emulsification factor found in Table 3 of this
appendix. Facilities which handle, store, or
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transport oil from different petroleum
groups must assume that the oil group resulting in the largest on-water recovery volume will be stored in the tank or tanks identified as constituting the worst case discharge.
7.2.3 The adjusted volume is multiplied by
the on-water oil recovery resource mobilization favor found in Table 4 of this appendix
from the appropriate operating area and response tier to determine the total on-water
oil recovery capacity in barrels per day that
must be identified or contracted for to arrive
on-scene with the applicable time for each
response tier. Three tiers are specified. For
higher volume port areas, the contracted
tiers of resources must be located such that
they can arrive on scene within 6, 30, and 54
hours of the discovery of an oil discharge.
For all other river, inland, nearshore, offshore areas, and the Great Lakes, these tiers
are 12, 36, and 60 hours.
7.2.4 The resulting on-water recovery capacity in barrels per day for each tier must
be used to identify response resources necessary to sustain operations in the applicable operating area. The equipment must be
capable of sustaining operations for the time
period specified in Table 2 of this appendix.
The facility owner or operator must identify
and ensure the availability, through contract or other approved means as described
in § 154.1028(a), of sufficient oil spill recovery
devices to provide the effective daily recovery oil recovery capacity required. If the required capacity exceeds the applicable cap
specified in Table 5 of this appendix, then a
facility owner or operator shall ensure, by
contract or other approved means as described in § 154.1028(a), only for the quantity
of resources required to meet the cap, but
shall identify sources of additional resources
as indicated in § 154.1045(m). The owner or operator of a facility whose planning volume
exceeds the cap for 1993 must make arrangements to identify and ensure the availability, through contract or other approved
means as described in § 154.1028(a), of the additional capacity in 1998 or 2003, as appropriate. For a facility that handles, stores, or
transports multiple groups of oil, the required effective daily recovery capacity for
each group is calculated before applying the
cap.
7.3 The following procedures must be used
to calculate the planning volume for identifying shoreline cleanup capacity:
7.3.1 The following must be determined:
The worst case discharge volume of oil for
the facility; the appropriate group(s) for the
type of oil handled, stored, or transported at
the facility (non-persistent (Group I) or persistent (Groups II, III, or IV)); and the operating area(s) in which the facility operates.
For a facility storing oil from different
groups, each group must be calculated separately. Using this information, Table 2 of
this appendix must be used to determine the
percentages of the total planning volume to
be used for shoreline cleanup resource planning.
7.3.2 The shoreline cleanup planning volume must be adjusted to reflect an emulsification factor using the same procedure as
described in section 7.2.2.
7.3.3 The resulting volume will be used to
identify an oil spill removal organization
with the appropriate shoreline cleanup capability.
7.3.4 The following is an example of the
procedure described above: A facility receives oil from barges via a dock located on
a bay and transported by piping to storage
tanks. The facility handles Number 6 oil
(specific gravity .96) and stores the oil in
tanks where it is held prior to being burned
in an electric generating plant. The MTR
segment of the facility has six 18-inch diameter pipelines running one mile from the
dock-side manifold to several storage tanks
which are located in the non-transportationrelated portion of the facility. Although the
facility piping has a normal working pressure of 100 pounds per square inch, the piping
has a maximum allowable working pressure
(MAWP) of 150 pounds per square inch. At
MAWP, the pumping system can move 10,000
barrels (bbls) of Number 6 oil every hour
through each pipeline. The facility has a roving watchman who is required to drive the
length of the piping every 2 hours when the
facility is receiving oil from a barge. The facility operator estimates that it will take
approximately 10 minutes to secure pumping
operations when a discharge is discovered.
Using the definition of worst case discharge
provided in § 154.1029(b)(ii), the following calculation is provided:
bbls.
2 hrs + 0.17 hour × 10,000 bbls per hour .........
Piping volume = 37,322 ft 3 ÷ 5.6 ft 3/bbl .........
21,700
+6,664
Discharge volume per pipe ...........................
Number of pipelines .....................................
28,364
×6
Worst case discharge from MTR facility .....
170,184
To calculate the planning volumes for onshore recovery:
Worst case discharge: 170,184 bbls. Group IV
oil
Emulsification factor (from Table 3): 1.4
Operating Area impacted: Inland
Planned percent oil onshore recovery (from
Table 2): Inland 70%
Planning volumes for onshore recovery: Inland 170,184 ×.7 × 1.4 = 166,780 bbls.
Conclusion: The facility owner or operator
must contract with a response resource capable of managing a 166,780 barrel shoreline
cleanup.
To calculate the planning volumes for onwater recovery:
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33 CFR Ch. I (7–1–10 Edition)
Worst case discharge: 170,184 bbls. Group IV
oil
Emulsification factor (from Table 3): 1.4
Operating Area impacted: Inland
Planned percent oil on-water recovery (from
Table 2): Inland 50%
Planning volumes for on-water recovery: Inland 170,184×.5×1.4 = 119,128 bbls.
To determine the required resources for
on-water recovery for each tier, use the mobilization factors from Table 4:
Tier 1
Tier 2
Tier 3
Inland = 119,128 bbls. ...............
× .15
× .25
× .40
Barrels per day (pbd) ................
17,869
29,782
47,652
Conclusion: Since the requirements for all
tiers for inland exceed the caps, the facility
owner will only need to contract for 10,000
bpd for Tier 1, 20,000 bpd for Tier 2, and 40,000
bpd for Tier 3. Sources for the bpd on-water
recovery resources above the caps for all
three Tiers need only be identified in the response plan.
Twenty percent of the capability for Inland, for all tiers, must be capable of operating in water with a depth of 6 feet or less.
The facility owner or operator will also be
required to identify or ensure, by contract or
other approved means as described in
§ 154.1028(a), sufficient response resources required under §§ 154.1035(b)(4) and 154.1045(k) to
protect fish and wildlife and sensitive environments identified in the response plan for
the worst case discharge from the facility.
The COTP has the discretion to accept
that a facility can operate only a limited
number of the total pipelines at a dock at a
time. In those circumstances, the worst case
discharge must include the drainage volume
from the piping normally not in use in addition to the drainage volume and volume of
oil discharged during discovery and shut
down of the oil discharge from the operating
piping.
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8. Determining the Capability of High-Rate
Response Methods
8.1. Calculate cumulative dispersant application capacity as follows:
8.1.1 A facility owner or operator must
plan either for a dispersant capacity to respond to a facility’s worst case discharge
(WCD) of oil, or for the amount of the dispersant resource cap as required by
§ 154.1045(i)(3) of this chapter, whichever is
the lesser amount. When planning for the cumulative application capacity required, the
calculations must account for the loss of
some oil to the environment due to natural
dissipation causes (primarily evaporation).
The following procedure must be used to determine the cumulative application requirements:
8.1.2 Determine the WCD volume of oil in
gallons and the appropriate oil group for the
type of petroleum oil (persistent Groups II,
III, and IV). For facilities with mixed petroleum oils, assume a total WCD volume using
the group that constitutes the largest portion of the oil being handled or the group
with the smallest natural dissipation factor;
8.1.3 Multiply the total WCD amount in
gallons by the natural dissipation factor for
the appropriate oil group as follows: Group II
factor is 0.50; Group III is 0.30; and Group IV
is 0.10. This represents the amount of oil that
can be expected to be lost to natural dissipation in a nearshore environment. Subtract
the oil amount lost to natural dissipation
from the total WCD amount to determine
the remaining oil available for treatment by
dispersant application; and
8.1.4 Multiply the oil available for dispersant treatment by the dispersant-to-oil
planning application ratio of 1 part dispersant to 20 parts oil (0.05). The resulting number represents the cumulative total dispersant-application capability that must be ensured available within the first 60 hours.
8.1.5(i) The following is an example of the
procedure described in paragraphs 8.1.1
through 8.1.4 above: A facility with a 1,000,000
gallon WCD of crude oil (specific gravity
0.87) is located in an area with pre-authorization for dispersant use in the nearshore environment on the U.S. East Coast:
WCD: 1,000,000 gallons, Group III oil.
Natural dissipation factor for Group III: 30
percent.
General formula to determine oil available
for dispersant treatment: (WCD)¥[(WCD) ×
(natural dissipation factor)] = available oil.
E.g., 1,000,000 gal¥(1,000,000 gal × .30) =
700,000 gallons of available oil.
Cumulative application capacity = Available oil × planning application ratio (1 gal
dispersant/20 gals oil = 0.05).
E.g., 700,000 gal oil × (0.05) = 35,000 gallons
cumulative dispersant-application capacity.
(ii) The requirements for cumulative dispersant-application capacity (35,000 gallons)
for this facility’s WCD is less than the overall dispersant capability for non-Gulf Coast
waters required by § 155.1045(i)(3) of this
chapter. Because paragraph 8.1.1 of this appendix requires owners and operators to ensure the availability of the lesser of a facility’s dispersant requirements for WCD or the
amount of the dispersant cap provided for in
§ 154.1045(i)(3), the facility in this example
would be required to ensure the availability
of 35,000 gallons of dispersant. More specifically, this facility would be required to meet
the
following
tier
requirements
in
§ 154.1045(i)(3), which total 35,000 gallons application:
Tier 1—4,125 gallons—Completed in 12
hours.
Tier 2—23,375 gallons—Completed in 36
hours.
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Tier 3—7,500 gallons—Completed in 60
hours.
8.2 Determine Effective Daily Application
Capacities (EDACs) for dispersant response
systems as follows:
8.2.1 EDAC planning estimates for compliance with the dispersant application requirements in § 154.1045(i)(3) are to be based on:
8.2.1.1 The spill occurring at the facility;
8.2.1.2 Specific
dispersant
application
platform operational characteristics identified in the Dispersant Mission Planner 2 or
as demonstrated by operational tests;
8.2.1.3 Locations of primary dispersant
staging sites; and
8.2.1.4 Locations and quantities of dispersant stockpiles.
8.2.2 EDAC calculations with supporting
documentation must be submitted to the
NSFCC for classification as a Dispersant Oil
Spill Removal Organization.
8.2.3(i) EDAC can also be calculated using
the Dispersant Mission Planner 2 (DMP2).
The DMP2 is a downloadable application
that calculates EDAC for different dispersant response systems. It is located on the
Internet
at:
http://
www.response.restoration.noaa.gov/spilltools.
(ii) The DMP2 contains operating information for the vast majority of dispersant application platforms, including aircraft, both
rotary and fixed wing, and vessels. The
DMP2 produces EDAC estimates by performing calculations based on performance
parameters of dispersant application platforms, locations of primary dispersant staging sites, home-based airport or port locations, and the facility location (for the spill
site).
8.2.4 For each Captain of the Port zone
where a dispersant response capability is required, the response plan must identify:
8.2.4.1 The type, number, and location of
each dispersant-application platform intended for use to meet dispersant delivery
requirements specified in § 154.1045(i)(3) of
this chapter;
8.2.4.2 The amount and location of available dispersant stockpiles to support each
platform; and,
8.2.4.3 A primary staging site for each
platform that will serve as its base of operations for the duration of the response.
8.3 In addition to the equipment and supplies required, a facility owner or operator
must identify a source of support to conduct
the monitoring and post-use effectiveness
evaluation required by applicable regional
plans and ACPs.
8.4 Identification of the resources for dispersant application does not imply that the
use of this technique will be authorized. Actual authorization for use during a spill response will be governed by the provisions of
the National Oil and Hazardous Substances
Contingency Plan (40 CFR part 300) and the
applicable Local or Area Contingency Plan.
9. Additional Equipment Necessary To Sustain
Response Operations
9.1 A facility owner or operator is responsible for ensuring that sufficient numbers of
trained personnel and boats, aerial spotting
aircraft, containment boom, sorbent materials, boom anchoring materials, and other
supplies are available to sustain response operations to completion. All such equipment
must be suitable for use with the primary
equipment identified in the response plan. A
facility owner or operator is not required to
list these response resources, but shall certify their availability.
9.2 A facility owner or operator shall
evaluate the availability of adequate temporary storage capacity to sustain the effective daily recovery capacities from equipment identified in the plan. Because of the
inefficiencies of oil spill recovery devices, response plans must identify daily storage capacity equivalent to twice the effective daily
recovery rate required on scene. This temporary storage capacity may be reduced if a
facility owner or operator can demonstrate
by waste stream analysis that the efficiencies of the oil recovery devices, ability
to decant waste, or the availability of alternative temporary storage or disposal locations will reduce the overall volume of oily
material storage requirement.
9.3 A facility owner or operator shall ensure that his or her planning includes the capability to arrange for disposal of recovered
oil products. Specific disposal procedures
will be addressed in the applicable ACP.
TABLE 1—RESPONSE RESOURCE OPERATING CRITERIA OIL RECOVERY DEVICES
Significant wave height 1
Operating environment
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Rivers and Canals ...................................................................................
Inland .......................................................................................................
Great Lakes .............................................................................................
Ocean ......................................................................................................
≤1
≤3
≤4
≤6
Sea State
Foot ....................................................
feet .....................................................
feet .....................................................
feet .....................................................
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1
2
2–3
3–4
Pt. 154, App. C
33 CFR Ch. I (7–1–10 Edition)
BOOM
Use
Boom property
Rivers and
canals
Inland
≤1
1
6–18
2:1
4,500
200
100
Significant Wave Height 1 ..............................................................
Sea State ......................................................................................
Boom height—in. (draft plus freeboard) .......................................
Reserve Buoyancy to Weight Ratio ..............................................
Total Tensile Strength—lbs. ..........................................................
Skirt Fabric Tensile Strength—lbs ................................................
Skirt Fabric Tear Strength—lbs ....................................................
Great Lakes
≤3
2
18–42
2:1
15–20,000
300
100
Ocean
≤4
2–3
18–42
2:1
15–20,000
300
100
≤6
3–4
≤42
3:1 to 4:1
≤20,000
500
125
1 Oil recovery devices and boom must be at least capable of operating in wave heights up to and including the values listed in
Table 1 for each operating environment.
TABLE 2—REMOVAL CAPACITY PLANNING TABLE
Spill location
Rivers and canals
Nearshore/inland Great Lakes
Sustainability of on-water oil
recovery
3 Days
4 Days
Oil group
% Natural dissipation
% Recovered
floating
oil
80
40
20
5
1
2
3
Non-persistent oils .........
Light crudes ...................
Medium crudes and
fuels .................................
4 Heavy crudes and fuels
% Oil on
shore
% Natural dissipation
% Recovered
floating
oil
10
15
10
45
80
50
15
20
65
75
30
10
TABLE 3—EMULSIFICATION FACTORS FOR
PETROLEUM OIL GROUPS
Non-Persistent Oil:
Group I .........................................................
Persistent Oil:
Group II ........................................................
Group III .......................................................
Group IV ......................................................
Offshore
6 Days
% Oil on
shore
% Natural dissipation
% Recovered
floating
oil
% Oil on
shore
20
50
10
30
95
75
5
25
/
5
50
50
50
70
60
50
40
40
20
30
TABLE 4—ON WATER OIL RECOVERY
RESOURCE MOBILIZATION FACTORS
Operating Area
1.0
1.8
2.0
1.4
Rivers & Canals ....................................
Inland/Nearshore/Great Lakes ..............
Offshore .................................................
Tier
1
Tier
2
Tier
3
.30
.15
.10
.40
.25
.165
.60
.40
.21
Note: These mobilization factors are for total response resources mobilized, not incremental response resources.
TABLE 5—RESPONSE CAPABILITY CAPS BY OPERATING AREA
Tier 1
February 18, 1993:
All except rivers and canals, Great
Lakes.
Great Lakes ..........................................
Rivers and canals ................................
February 18, 1998:
All except rivers and canals, Great
Lakes.
Great Lakes ..........................................
Rivers and canals ................................
February 18, 2003:
All except rivers & canals & Great
Lakes.
Great Lakes ..........................................
Rivers & canals ....................................
Tier 2
Tier 3
10K bbls/day ....................
20K bbls/day ....................
40K bbls/day/
5K bbls/day ......................
1,500 bbls/day .................
10K bbls/day ....................
3,000 bbls/day .................
20K bbls/day.
6,000 bbls/day.
12.5K bbls/day .................
25K bbls/day ....................
50K bbls/day.
6.25K bbls/day .................
1,875 bbls/day .................
12.3K bbls/day .................
3,750 bbls/day .................
25K bbls/day.
7,500 bbls/day.
12.5K bbls/day .................
25K bbls/day ....................
50K bbls/day.
6.25K bbls/day .................
1,875 bbls/day .................
12.3K bbls/day .................
3,750 bbls/day .................
25K bbls/day.
7,500 bbls/day.
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Note: The caps show cumulative overall effective daily recovery capacity, not incremental increases.
TBD = To be determined.
[CGD 91–036, 61 FR 7933, Feb. 29, 1996, as amended by CGD 96–026, 61 FR 33666, June 28, 1996;
USCG–1999–5151, 64 FR 67175, Dec. 1, 1999; USCG–2000–7223, 65 FR 40058, June 29, 2000; USCG–
2005–21531, 70 FR 36349, June 23, 2005; USCG–2001–8661, 74 FR 45025, Aug. 31, 2009; USCG–2010–
0351, 75 FR 36284, June 25, 2010]
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Coast Guard, DHS
Pt. 154, App. D
APPENDIX D TO PART 154—TRAINING
ELEMENTS FOR OIL SPILL RESPONSE
PLANS
1. General
1.1 The portion of the plan dealing with
training is one of the key elements of a response plan. This concept is clearly expressed by the fact that Congress, in writing
OPA 90, specifically included training as one
of the sections required in a vessel or facility
response plan. In reviewing submitted response plans, it has been noted that the
plans often do not provide sufficient information in the training section of the plan for
either the user or the reviewer of the plan. In
some cases, plans simply state that the crew
and others will be trained in their duties and
responsibilities, with no other information
being provided. In other plans, information
is simply given that required parties will receive the necessary worker safety training
(HAZWOPER).
1.2 The training section of the plan need
not be a detailed course syllabus, but it must
contain sufficient information to allow the
user and reviewer (or evaluator) to have an
understanding of those areas that are believed to be critical. Plans should identify
key skill areas and the training that is required to ensure that the individual identified will be capable of performing the duties
prescribed to them. It should also describe
how the training will be delivered to the various personnel. Further, this section of the
plan must work in harmony with those sections of the plan dealing with exercises, the
spill management team, and the qualified individual.
1.3 The material in this appendix D is not
all-inclusive and is provided for guidance
only.
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2. Elements To Be Addressed
2.1 To assist in the preparation of the
training section of a facility response plan,
some of the key elements that should be addressed are indicated in the following sections. Again, while it is not necessary that
the comprehensive training program for the
company be included in the response plan, it
is necessary for the plan to convey the elements that define the program as appropriate.
2.2 An effective spill response training
program should consider and address the following:
2.2.1 Notification requirements and procedures.
2.2.2 Communication system(s) used for
the notifications.
2.2.3 Procedures to mitigate or prevent
any discharge or a substantial threat of a
discharge of oil resulting from failure of
manifold, mechanical loading arm, or other
transfer equipment or hoses, as appropriate;
2.2.3.1 Tank overfill;
2.2.3.2 Tank rupture;
2.2.3.3 Piping rupture;
2.2.3.4 Piping leak, both under pressure
and not under pressure, if applicable;
2.2.3.5 Explosion or fire;
2.2.3.6 Equipment failure (e.g., pumping
system failure, relief valve failure, or other
general equipment relevant to operational
activities associated with internal or external facility transfers).
2.2.4 Procedures for transferring responsibility for direction of response activities
from facility personnel to the spill management team.
2.2.5 Familiarity with the operational capabilities of the contracted oil spill removal
organizations and the procedures to notify
the activate such organizations.
2.2.6 Familiarity with the contracting and
ordering procedures to acquire oil spill removal organization resources.
2.2.7 Familiarity with the ACP(s).
2.2.8 Familiarity with the organizational
structures that will be used to manage the
response actions.
2.2.9 Responsibilities and duties of the
spill management team members in accordance with designated job responsibilities.
2.2.10 Responsibilities and authority of
the qualified individual as described in the
facility response plan and company response
organization.
2.2.11 Responsibilities of designated individuals to initiate a response and supervise
response resources.
2.2.12 Actions to take, in accordance with
designated job responsibilities, in the event
of a transfer system leak, tank overflow, or
suspected cargo tank or hull leak.
2.2.13 Information on the cargoes handled
by the vessel or facility, including familiarity with—
2.2.13.1 Cargo material safety data sheets;
2.2.13.2 Chemical characteristic of the
cargo;
2.2.13.3 Special handling procedures for
the cargo;
2.2.13.4 Health and safety hazards associated with the cargo; and
2.2.13.5 Spill and firefighting procedures
for cargo.
2.2.14 Occupational Safety and Health Administration requirements for worker health
and safety (29 CFR 1910.120).
3. Further Considerations
In drafting the training section of the facility response plan, some further considerations are noted below (these points are
raised simply as a reminder):
3.1 The training program should focus on
training provided to facility personnel.
3.2 An organization is comprised of individuals, and a training program should be
structured to recognize this fact by ensuring
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Pt. 155
33 CFR Ch. I (7–1–10 Edition)
that training is tailored to the needs of the
individuals involved in the program.
3.3 An owner or operator may identify
equivalent work experience which fulfills
specific training requirements.
3.4 The training program should include
participation in periodic announced and unannounced exercises. This participation
should approximate the actual roles and responsibilities of individual specified in the
plan.
3.5 Training should be conducted periodically to reinforce the required knowledge
and to ensure an adequate degree of preparedness by individuals with responsibilities under the facility response plan.
3.6 Training may be delivered via a number of different means; including classroom
sessions, group discussions, video tapes, selfstudy workbooks, resident training courses,
on-the-job training, or other means as
deemed appropriate to ensure proper instruction.
3.7 New employees should complete the
training program prior to being assigned job
responsibilities which require participation
in emergency response situations.
4. Conclusion
The information in this appendix is only
intended to assist response plan preparers in
reviewing the content of and in modifying
the training section of their response plans.
It may be more comprehensive than is needed for some facilities and not comprehensive
enough for others. The Coast Guard expects
that plan preparers have determined the
training needs of their organizations created
by the development of the response plans and
the actions identified as necessary to increase the preparedness of the company and
its personnel to respond to actual or threatened discharges of oil from their facilities.
[CGD 91–036, 61 FR 7938, Feb. 29, 1996]
PART 155—OIL OR HAZARDOUS
MATERIAL POLLUTION PREVENTION REGULATIONS FOR VESSELS
Subpart A—General
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Sec.
155.100 Applicability.
155.110 Definitions.
155.120 Equivalents.
155.130 Exemptions.
155.140 Incorporation by reference.
155.T150 Temporary suspension of requirements to permit support of deepwater horizon spill response.
Subpart B—Vessel Equipment
155.200
Definitions.
155.205 Discharge removal equipment for
vessels 400 feet or greater in length.
155.210 Discharge removal equipment for
vessels less than 400 feet in length.
155.215 Discharge removal equipment for inland oil barges.
155.220 Discharge removal equipment for
vessels carrying oil as secondary cargo.
155.225 Internal cargo transfer capability.
155.230 Emergency control systems for tank
barges.
155.235 Emergency towing capability for oil
tankers.
155.240 Damage stability information for oil
tankers and offshore oil barges.
155.245 Damage stability information for inland oil barges.
155.310 Containment of oil and hazardous
material cargo discharges.
155.320 Fuel oil and bulk lubricating oil discharge containment.
155.330 Oily mixture (bilge slops)/fuel oil
tank ballast water discharges on U.S.
non-oceangoing ships.
155.350 Oily mixture (bilge slops)/fuel oil
tank ballast water discharges on oceangoing ships of less than 400 gross tons.
155.360 Oily mixture (bilge slops) discharges
on oceangoing ships of 400 gross tons and
above but less than 10,000 gross tons, excluding ships that carry ballast water in
their fuel oil tanks.
155.370 Oily mixture (bilge slops)/fuel oil
tank ballast water discharges on oceangoing ships of 10,000 gross tons and above
and oceangoing ships of 400 gross tons
and above that carry ballast water in
their fuel oil tanks.
155.380 Oily water separating equipment and
bilge alarm approval standards.
155.400 Platform machinery space drainage
on oceangoing fixed and floating drilling
rigs and other platforms.
155.410 Pumping, piping and discharge requirements for U.S. non-oceangoing ships
of 100 gross tons and above.
155.420 Pumping, piping and discharge requirements for oceangoing ships of 100
gross tons and above but less than 400
gross tons.
155.430 Standard discharge connections for
oceangoing ships of 400 gross tons and
above.
155.440 Segregation of fuel oil and ballast
water on new oceangoing ships of 4,000
gross tons and above, other than oil
tankers, and on new oceangoing oil tankers of 150 gross tons and above.
155.450 Placard.
155.470 Prohibited spaces.
155.480 Overfill devices.
155.490 [Reserved]
Subpart C—Transfer Personnel, Procedures,
Equipment, and Records
155.700
Designation of person in charge.
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| File Type | application/pdf |
| File Modified | 2014-08-28 |
| File Created | 2014-08-28 |