DNVGL-SI-0003: Verification for compliance with United States … · 2015. 11. 2. · Statutory interpretations DNVGL-SI-0003 – Edition July 2015 Page 3 Verification for compliance

STATUTORY INTERPRETATIONS
DNVGL-SI-0003 Edition July 2015
Verification for compliance with United States regulations on the outer continental shelf

DNV GL AS

The electronic pdf version of this document found through http://www.dnvgl.com is the officially binding version. The documents are available free of charge in PDF format.

The content of this service document is the subject of intellectual property rights reserved by DNV GL AS (“DNV GL”).The user accepts that it is prohibited by anyone else but DNV GL and/or its licensees to offer and/or perform classification,certification and/or verification services, including the issuance of certificates and/or declarations of conformity, whollyor partly, on the basis of and/or pursuant to this document whether free of charge or chargeable, without DNV GL’s priorwritten consent. DNV GL is not responsible for the consequences arising from any use of this document by others.

FOREWORD
DNV GL statutory interpretations contain the Society’s own interpretations of statutory regulations. Theseare valid when not instructed otherwise by the flag or coastal state administration, and when nointerpretations exist from IACS or regulatory bodies. The publication covers only selected relevant topicsand shall under no circumstances be taken as the Society's complete interpretations of such regulations.
© DNV GL AS July 2015

Any comments may be sent by e-mail to [email protected]

If any person suffers loss or damage which is proved to have been caused by any negligent act or omission of DNV GL, then DNV GL shall pay compensation tosuch person for his proved direct loss or damage. However, the compensation shall not exceed an amount equal to ten times the fee charged for the service inquestion, provided that the maximum compensation shall never exceed USD 2 million.In this provision “DNV GL” shall mean DNV GL AS, its direct and indirect owners as well as all its affiliates, subsidiaries, directors, officers, employees, agentsand any other acting on behalf of DNV GL.

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GeneralThis document supersedes DNVGL-SE-0003, April 2014.

Main changes July 2015, entering into force 1 January 2016• GeneralThe revision of this document is part of the DNV GL merger, updating the previous DNV GL service specification into a DNV GL statutory interpretation format including updated nomenclature and document reference numbering, e.g.:

— Main class identification “1A1” becomes “1A”.— DNV replaced by DNV GL.— DNV-OSS-102 to DNVGL-RU-OU-0102 etc.

A complete listing with updated reference numbers can be found on DNV GL's homepage on internet.

To complete your understanding, observe that the entire DNV GL update process will be implemented sequentially. Hence, for some of the references, still the legacy DNV documents apply and are explicitly indicated as such, e.g.: Standard for Certification 2.22 has become DNV Standard for Certification 2.22.

Statutory interpretations DNVGL-SI-0003 – Edition July 2015 Page 3Verification for compliance with United States regulations on the outer continental shelf

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CHANGES – CURRENT ................................................................................................. 3

CH. 1 PRINCIPLES AND PROCEDURES ................................. 6Sec.1 Introduction.................................................................................................. 6

1.1 Introduction ...........................................................................................61.2 General...................................................................................................6

1.2.1 Objective ......................................................................................61.2.2 Scope...........................................................................................61.2.3 Structure ......................................................................................6

1.3 Definitions..............................................................................................71.3.1 Verbal forms .................................................................................71.3.2 DNV GL definitions .........................................................................7

1.4 References .............................................................................................81.4.1 General .......................................................................................8

1.5 Abbreviations .......................................................................................10Sec.2 Regulatory basis and legal provisions ....................................................... 11

2.1 Regulatory basis principles ..................................................................112.1.1 Jurisdictions ................................................................................112.1.2 Outer continental shelf facilities .....................................................112.1.3 Code of federal regulations............................................................112.1.4 Alternate design and equipment standards ......................................122.1.5 Regulatory considerations for floating offshore installations and

floating production storage and offloading units ..............................122.1.6 Equivalent design and construction considerations............................12

2.2 Classification principles........................................................................132.2.1 General ......................................................................................132.2.2 Classification of floating offshore installations and floating production

storage and offloading units including floating storage and offloading units ..........................................................................................13

2.2.3 Class notations ............................................................................132.2.4 Main character of class .................................................................132.2.5 Basic design notations ..................................................................132.2.6 Service notations .........................................................................14

2.3 (US)-notation .......................................................................................142.3.1 General ......................................................................................142.3.2 Compliance matrix for outer continental shelf ..................................14

CH. 2 DESIGN AND CONSTRUCTION PROVISIONS............. 16Sec.1 Introduction................................................................................................ 16

1.1 General.................................................................................................161.1.1 General ......................................................................................16

Sec.2 Floating offshore installations..................................................................... 172.1 Introduction .........................................................................................17

2.1.1 Application..................................................................................172.1.2 Class notations ............................................................................17

2.2 Compliance matrix ...............................................................................172.2.1 Application..................................................................................17


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2.2.2 Compliance matrix for floating offshore installations with (US)
notation......................................................................................17

Sec.3 Floating storage units and floating production, storage and offloading units............................................................................................................ 213.1 Introduction .........................................................................................21

3.1.1 Application..................................................................................213.1.2 Class notations ............................................................................21

3.2 Compliance matrix ...............................................................................213.2.1 Application..................................................................................213.2.2 Compliance basis for floating storage and offloading unit and floating

production storage and offloading unit (US) ....................................21

Sec.4 Equivalencies and other design considerations (informative) .................... 244.1 General.................................................................................................244.2 Passive ballast system .........................................................................244.3 External impact load on hull .................................................................244.4 Fire protection boundaries ...................................................................244.5 Platform verification program by a certified verification agent ............24

4.5.1 General ......................................................................................244.5.2 Scope of assessment ....................................................................24

App. A United States Coast Guard policy letter ....................................................... 26


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CHAPTER 1 PRINCIPLES AND PROCEDURES
SECTION 1 INTRODUCTION

1 IntroductionDNV GL offshore classification provides assurance that a set of requirements laid down in the rules established by DNV GL are met during design and construction and maintained during operation of an offshore unit or installation. Classification has gained worldwide recognition as representing an adequate level of safety and quality.

Wherever possible DNV GL offers additional, integrated services to assist clients toward fulfilling coastal state legislation, giving credit for classification activities.

2 General

2.1 ObjectiveThis document outlines an alternative regulatory roadmap for owners and operators of floating offshore installation (FOI), floating storage units (FSO) and floating production, storage and offloading units (FPSO) wishing to engage in outer continental shelf (OCS) activities in the US Gulf of Mexico. The roadmap uses DNV GL classification rules and services as a building block, and identifies additional United States coast guard (USCG) design and equipment requirements for these units that are not otherwise covered by the rules. Compliance with the appropriate DNV GL classification notations and supplemental USCG requirements described herein, provide an equivalent level of safety to the USCG’s design and equipment requirements prescribed in the code of federal regulations.

2.2 Scope2.2.1 This document outlines a class based verification scheme for US compliance for offshore objects of the following types:

— floating offshore installations (FOI)

— floating storage units (FSO)

— floating production, storage, and offloading units (FPSO).

2.2.2 This document does not address regulatory requirements under the jurisdiction of the Bureau of Safety and Environmental Enforcement (BSEE).

Guidance note:MMS/USCG Memorandum of Agreement OCS-04, dated February 28, 2008, identifies the lead agency for systems and subsystems associated with floating OCS facilities.

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2.3 StructureThis document is divided into two main chapters and an appendix:

— Ch.1: General information about principles, procedures and legal provisions for meeting an equivalent level of safety to the USCG requirements for FOIs, FSOs and FPSOs meant to operate on the US OCS.

— Ch.2: Design and equipment requirements for meeting an equivalent level of safety to the USCG requirementsfor FOIs, FSOs and FPSOs operating in the US OCS. The chapter also includes an informative section on equivalencies and design considerations.

— App.A: United States Coast Guard policy letter.


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3 Definitions
3.1 Verbal forms

3.2 DNV GL definitions

Table 1 Verbal forms

Term Definitionshall verbal form used to indicate requirements strictly to be followed in order to conform to the document

should verbal form used to indicate that among several possibilities one is recommended as particularly suitable, without mentioning or excluding others, or that a certain course of action is preferred but not necessarily required

may verbal form used to indicate a course of action permissible within the limits of the document

Table 2 Definitions

Term Definitionapproval or approved denotes acceptance by DNV GL of documentation showing design solutions, arrangements

and/or equipment to comply with the rulesassessment an act of assessing, appraising or evaluating a condition of a product, process or systemcertificate a document confirming compliance with the Society’s rules or with other rules and

regulations for which the Society has been authorized to actcertification a service confirming compliance with applicable requirements on the date that the survey

was completedcertification of materials and components (CMC)

the activity of ensuring that materials, equipment and components considered critical for the installation have undergone a certification process for compliance with applicable code and standards

class class is assigned to and will be retained by units complying with applicable requirements of the Society’s rules

classification a service which comprises the development of independent technical standards for offshore units – class rules and standards, and verification of compliance with the rules and standards throughout the units’ life

classification certificate issued upon assignment or renewal of classIts validity is five years subject to successful completion of annual and intermediate surveys.

client the party having requested classification or having assumed ownership of a classed offshore unit or installationIn cases where owners have authorised another party to operate the unit or installation on their behalf, such party is regarded as the client.

contract the specific agreement between DNV GL and the customerIt defines the extent of services requested by the customer, and is concerned with:

— the classification of offshore units or installations, both new buildings and in operation — statutory work carried out on behalf of national maritime authorities — equipment and materials

floating offshore installation (FOI)

a buoyant OCS facility securely and substantially moored so that it cannot be moved without a special effort This term includes tension leg platforms and permanently moored semisubmersibles or shipshaped hulls, but does not include mobile offshore drilling units.

guidance note contain advice which is not mandatory for the assignment or retention of class, but with which the Society, in light of general experience, advises compliance.

offshore installation A collective term to cover any construction, buoyant or non-buoyant, designed and built for installation at a particular offshore location

owner in the context of these statutory interpretations, the owner is defined as the party responsible for the offshore unit or installation including its operation and safety

recognised classification society

A classification society which is a full or associate member of IACS


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4 References
4.1 General 4.1.1 These statutory interpretations includes references to other DNV GL documents and regulations, codes and standards which shall be used in conjunction with the requirements given herein, for classification of FOIs, FSOs and FPSOs in the US OCS and for partial compliance with the USCG requirements. Unless noted otherwise the latest issue of the references shall be used.

4.1.2 DNV GL documents referred to are given in Table 3.

4.1.3 Other standards and regulatory basis references for compliance as referred to herein are given in Table 4. Only parts referred to in the main text of this document or CG-ENG Policy Letter No. 01-13 are applicable.

Table 3 DNV GL References

Reference Title

DNVGL-RU-OU-0102 Rules for classification of floating production, storage and loading units

DNVGL-OS-A101 Safety principles and arrangements

DNVGL-OS-B101 Metallic materials

DNVGL-OS-C102 Structural design of offshore Ships

DNVGL-OS-C103 Structural design of column-stabilised units (LRFD method)

DNVGL-OS-C104 Structural design of self-elevating units (LRFD method)

DNVGL-OS-C105 Structural design of TLPs (LRFD method)

DNVGL-OS-C106 Structural design of deep draught floating units (LRFD method)

DNVGL-OS-C201 Structural design of offshore units (WSD method)

DNVGL-OS-C301 Stability and watertight integrity

DNVGL-OS-C401 Fabrication and testing of offshore structures

DNVGL-OS-D101 Marine and machinery systems and equipment

DNVGL-OS-D201 Electrical installations

DNVGL-OS-D202 Automation, safety, and telecommunication systems

DNVGL-OS-D301 Fire protection

DNVGL-OS-E201 Oil and gas processing systems

DNVGL-OS-E301 Position mooring

DNVGL-OS-E401 Helicopter decks

Table 4 Other references

Reference Title

American National Standards Institute (ANSI) UL 674

Standard for Electric Motors and Generators for Use in Division 1 Hazardous (Classified) Locations, Fifth Edition (dated May 31, 2011) (“ANSI/UL 674”)

ANSI/UL 823 Standard for Electric Heaters for Use in Hazardous (Classified) Locations, Ninth Edition including revisions through November 15, 2007 (dated October 20, 2006)

ANSI/UL 844 Standard for Luminaires for Use in Hazardous (Classified) Locations, Thirteenth Edition (dated June 29, 2012) (“ANSI/UL 844”)

ANSI/UL 913 Standard for Intrinsically Safe Apparatus and Associated Apparatus for Use in Class I, II, and III, Division 1, Hazardous Locations, Seventh Edition including revisions through June 3, 2010 (dated July 31, 2006)

ANSI/ISA 12.12.01-2012 (UL 1604)

Non-Incendive Electrical Equipment for Use in Class I and II, Division 2 and Class III, Division 1 and 2 Hazardous (Classified) Locations

ANSI/UL 1203 Standard for Explosion-Proof and Dust-Ignition-Proof Electrical Equipment for Use in Hazardous (Classified) Locations, Fourth Edition including revisions through October 28, 2009 (dated September 15, 2006)

ANSI/UL 2225 Standard for Cables and Cable-Fittings for Use in Hazardous (Classified) Locations, Third Edition February 25, 2011


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ISA 12.13.01-2002 (IEC 61779-1 through 5 Mod)

Performance Requirements for Combustible Gas Detectors

ISA 60079-29-2 (12.13.02)-2012

Gas detectors – Selection, installation, use and maintenance of detectors for flammable gases and oxygen

American Petroleum Institute (API) Recommended Practice (RP) 2FPS

Planning, Designing, and Constructing Floating Production Systems, 2011, 2nd Ed.

API RP 2T Planning, Designing, and Constructing Tension Leg Platforms,” 2010, 3rd Ed

API Standard 607 Fire Test for Quarter-turn Valves and Valves Equipped with Nonmetallic Seats”, 2010, 6th Ed

API RP 2SK Design and Analysis of Stationkeeping Systems for Floating Structures”, 2005

API RP 500 Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Division I and Division 2”, 2012

API RP 505 Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Zone 0, Zone 1 and Zone 2”, 1998

API RP 14C (R2007) Analysis, Design, Installation and Testing of Basic Surface Safety Systems on Offshore Production Platforms”

API RP 14G Recommended Practice for Fire Prevention and Control on Open Type Offshore Production Platforms”, 2007

API RP 14J (R2007) Recommended Practice for Design and Hazards Analysis for Offshore Production Facilities”

ANSI/API RP 14F Design, Installation, and Maintenance of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class 1, Division 1 and Division 2 Locations”, 2008

ASTM International Standard ASTM F1273 - 91(2007)

Specification for Tank Vent Flame Arresters

Canadian Standards Association (CAN/CSA), CAN/CSA-C22.2 No. 0-M91

General Requirements - Canadian Electrical Code, Part II, July 1991, Reaffirmed 2006

CAN/CSA-C22.2 No. 157-92 Intrinsically Safe and Non-Incendive Equipment for Use in Hazardous Locations, June 2003, Reaffirmed 2006

C22.2 No. 30-M1986 Explosion-Proof Enclosures for Use in Class I Hazardous Locations, November 1988, Reaffirmed 2007

C22.2 No. 213-M1987 Non-Incendive Electrical Equipment for Use in Class I, Division 2 Hazardous Locations, March 1987, Reaffirmed 2008

Factory Mutual (FM) 3600 Approval Standard for Electric Equipment for use in Hazardous (Classified) Locations General Requirements, November 1998

FM 3610 Approval Standard for Intrinsically Safe Apparatus and Associated Apparatus for Use in Class I, II, and III, Division 1, Hazardous (Classified) Locations, January 2010

FM 3611 Approval Standard for Non-Incendive Electrical Equipment for Use in Class I and II, Division 2, and Class III, Divisions 1 and 2, Hazardous (Classified) Locations, December 2004

FM 3615 Approval Standard for Explosionproof Electrical Equipment General Requirements, August 2006

FM 3620 Approval Standard for Purged and Pressurized Electrical Equipment for Hazardous (Classified) Locations, August 2000

IEC 61892-7 Mobile and fixed offshore units- Electrical installations- Part 7: Hazardous areas”, 2007

IEC 60092-502 Electrical installations in ships –Part 502: Tankers- Special Features”, 1999

IEC 60079-29-1 Explosive atmospheres – Part 29-1: Gas detectors – Performance requirements of detectors for flammable gases”, 2007

IEC 60079-29-2 Explosive atmospheres – Part 29-2: Gas detectors – Selection, installation, use and maintenance of detectors for flammable gases and oxygen”, 2007

IEC 60092-504 Electrical installations in ships – Part: 504 Special features – Control and instrumentation”, 2001

Table 4 Other references (Continued)

Reference Title


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Unless noted otherwise the latest issue of the references given in [4] shall be used.

5 AbbreviationsThe abbreviations given in Table 5 are used in this document.

International Maritime Organization Maritime Safety Committee Circular MSC/Circ.677

“Revised Standards for the Design, Testing and Locating of Devices to Prevent the Passage of Flame into Cargo Tankers”, 1994, as amended

IMO Resolution A.1023(26) “Code for the Construction and Equipment of MobileOffshore Drilling Units,” 2009 (2009 MODU Code)

IMO Resolution A.1021(26) Code on Alerts and Indicators”, 2009

ISO 19921:2005 Ships and marine technology – Fire resistance of metallic pipe components with resilient and elastomeric seals – Test methods

National Fire Protection Association (NFPA) 70

National Electrical Code, 2011

NFPA Standard 496 Standard for Purged and Pressurized Enclosures for Electrical Equipment”, 2013

Table 5 Abbreviations

Abbreviation Full Name

BSEE Bureau of Safety and Environmental Enforcement

CFR code of federal regulations

CVA certified verification agentDHS Department of Homeland Security

FOI floating offshore installation

FPSO floating production storage and offloading

FSO floating storage and offloading

GOM Gulf of Mexico

IMO International Maritime Organisation

MOU mobile offshore unit

MODU mobile offshore drilling unit

MRA mutual recognition agreement MSC maritime safety center

MTSA Maritime Transportation Security Act

OCS outer continental shelf

OCSLA outer continental shelf lands act

NVIC Navigation and Vessel Inspection Circular

USCG United States Coast Guard

Table 4 Other references (Continued)

Reference Title


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SECTION 2 REGULATORY BASIS AND LEGAL PROVISIONS
1 Regulatory basis principles

1.1 Jurisdictions1.1.1 The USCG, within the Department of Homeland Security (DHS), has broad authority under the outer continental shelf lands act (OCSLA) to regulate safety of life and property on OCS facilities and vessels engaged in OCS activities, and the safety of navigation. The USCG is also responsible for security regulations on OCS facilities, as specified under the Maritime Transportation Security Act (MTSA). Other regulatory agencies, such as the Bureau of Safety and Environmental Enforcement (BSEE) also share jurisdiction over OCS activities.

1.1.2 BSEE, within the Department of Interior, exercises safety and environmental enforcement functions related to OCS facilities, including but not limited to, developing regulations governing OCS operations, permitting, conducting inspections and investigations, enforcing regulatory requirements, assessing penalties, conducting research, and overseeing oil spill planning and preparedness. Although BSEE has applicable regulations for FOIs and FPSOs, these statutory interpretations deals with USCG requirements only.

Guidance note:BSEE have requirements for platform and structures which are covered under 30 CFR 250 Subpart I. The verification scheme for this is covered under a platform verification program through a certified verification agent (CVA). The CVA verification scheme is defined under § 250.915. It may be mentioned that DNV GL is an authorized CVA and have conducted this role for BSEE for recent projects in the GOM OCS. Some aspects of this scope has been discussed in Ch.2 Sec.4. The main areas of BSEE requirements that are not covered by this specification are primarily related to production, safety and operations for the plant/ topsides. See Ch.2 Sec.4 [5.1]


1.2 Outer continental shelf facilitiesUnder OCSLA, an OCS activity is any activity associated with exploration, development, production, transportation via pipeline, storage, or processing of mineral resources, including hydrocarbons (e.g. oil, gas, condensate, and natural gas liquids), salt, sulphur, sand and gravel. An OCS facility is any artificial island, installation, pipeline, or other device permanently or temporarily attached to the seabed, erected for the purpose of exploring for, developing, producing, transporting via pipeline, storing, or processing mineral resources from the OCS. This term does not include ships or vessels for transporting produced hydrocarbons. The following are types of OCS facilities:

— Fixed OCS facility: A bottom-founded OCS facility permanently affixed to the seabed or subsoil of the OCS, including platforms, guyed towers, articulated gravity platforms, and other structures. This definition also includes gravel and ice islands and caisson-retained islands engaged in OCS activities used for drilling, production, or both.

— Floating OCS facility: A buoyant OCS facility securely and substantially moored so that it cannot be moved without special effort. This term includes tension leg platforms, spars, semi-submersibles, and ship-shaped hulls.

— Mobile offshore drilling unit (MODU): Vessels capable of engaging in drilling operations for exploring or exploiting subsea oil, gas, or other mineral resource.

1.3 Code of federal regulationsCommercial vessel safety standards for US flagged vessels, MODUs, floating facilities, and fixed facilities are published in Chapter 1 of Titles 33 and 46, Code of Federal Regulations (CFR). The regulations provide detailed guidance for the design, construction and operation of these units. Table 1 lists some of the CFR subchapters under Titles 33 and 46 that are applicable to MODUs, undocumented floating facilities and fixed facilities on the OCS. Table 2 lists subchapter with general applicability across all units operating on the OCS.


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1.4 Alternate design and equipment standards1.4.1 The USCG has recognized that the design and technology of offshore facilities continue to advance at a rapid pace, and that existing US regulations do not address the current state of technology. Under 33 CFR 143.120, the USCG has the authority to accept alternative design and engineering standards if an equivalent level of safety is provided. Accordingly, the USCG published CG-ENG Policy Letter No. 01-13, which prescribes alternate design and equipment standards for floating offshore installations (FOI) and floating production, storage, and offloading offshore units (FPSO) located on the US OCS. In general, the policy letter requires the floating unit to be classed by a classification society that is accepted by the USCG, and establishes requirements to be met in addition to the classification society’s rules. A floating facility meeting the design and construction requirements of this policy letter is considered to meet a level of safety equivalent to that prescribed by 33 CFR 143.

1.4.2 The USCG reviews construction plans and conducts construction and periodic inspections of floating OCS facilities to ensure compliance with regulatory requirements. In 2007, the USCG agreed to accept plan review and inspection functions performed by DNV GL on floating OCS facilities. USCG has subsequently accepted DNV GL plan review and inspection functions on an FPSO and an FOI project in the GOM.

Guidance note:The latest revision of the USCG policy letter CG-ENG Policy Letter 01-13 has been included in Sec.5.2.


1.5 Regulatory considerations for floating offshore installations and floating production storage and offloading units Following CG-ENG Policy Letter 01-13, this document uses DNV GL rules and standards for classification of an FOI as the baseline for compliance. Additionally, the statutory interpretation includes only those supplemental requirements in CG-ENG Policy Letter 01-13 that are not otherwise covered by this baseline to streamline the certification process. The DNV GL offshore standards together with identified international standards and USCG regulations form the basis for meeting design, construction and equipment certification.

1.6 Equivalent design and construction considerationsUSCG acceptance of DNV GL plan review and inspections is predicated on the basis that such actions are in accordance with the relevant class notations and additional USCG requirements described in CG-ENG Policy Letter No. 01-13. Decisions concerning equivalencies, or resolutions of apparent conflicts in or among the applicable requirements, will be made by the US Coast Guard.

US Coast Guard recognizes that other proposals may exist that would provide an equivalent level of safety to that of existing regulations. In addition to CG-ENG Policy Letter No. 01-13, US Coast Guard will continue to consider requests for alternative design and equipment standards on a “case-by-case” basis. A brief description of a few examples are discussed in Ch.2 Sec.4.

Table 1 Regulatory subchapters applicable to specific units

CFR Title Subchapter Applicability

33 N OCS activities

46 D tank vessels

46 I-A mobile offshore drilling units

Table 2 Regulatory subchapters with applicability across all units

CFR Title Subchapter Applicability

33 O pollution

46 F marine engineering

46 J electrical engineering

46 Q equipment, construction and materials: specification and approval

46 S stability


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Guidance note:The examples of design issues that may be subject to case-by-case consideration are passive ballast systems and vessel collision loads based on typical supply vessel size on location. In all cases, proposed deviations from applicable requirements should be vetted with the US Coast Guard early in the approval process.

2 Classification principles

2.1 General2.1.1 Classification provides assurance that a set of requirements laid down in rules established by DNV GL are met during design and construction, and maintained during operation of an offshore unit or installation. Classification has gained world-wide recognition as representing an adequate level of safety and quality.

2.1.2 Classification implies an activity, in which an offshore unit or installation is surveyed during construction on the basis of design approval, tested before being taken into service, and surveyed regularly during its whole operational life. The aim is to verify that the required safety standard is built-in, observed and maintained.

2.2 Classification of floating offshore installations and floating production storage and offloading units including floating storage and offloading unitsThe classification rules and referred standards define acceptance criteria for design, construction, survey and testing of offshore units and installations, their marine, machinery, safety, and utility, systems / equipment, applicable to the new building and operational phase.

Guidance note:See DNV GL rules for classification: Offshore units DNVGL-RU-OU-0102 Floating production, storage and loading units for details on classification principles, scope, notations and procedures for classification.


2.3 Class notationsClassed units and installations will be given a class designation consisting of:

— construction symbol

— main character of class

— basic design notation

— service notation

— special equipment and systems notations (as applicable)

— special feature notations (as applicable).

2.4 Main character of class2.4.1 The notation 1A will be given to self propelled offshore units with hull and marine machinery and equipment found to be in compliance with the basic (common) requirements of the applicable DNV GL offshore standards referred to in the rules.

2.4.2 The notation OI will be given to non-self-propelled offshore installations intended for long term service at one offshore location with main structure, utility and safety systems found to be in compliance with the requirements of the applicable DNV GL offshore standards referred to in the rules.

2.5 Basic design notationsThe basic design notation indicates the type of structural design. The notations currently in use are given in Table 3.


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2.6 Service notationsUnits or installations constructed according to DNV GL rules for offshore classification, arranged for a particular service and found to be in accordance with the relevant requirements for such service, will be given a corresponding service notation. Relevant notations are given in Table 4.

3 (US)-notation

3.1 General3.1.1 FOIs, FSOs and FPSOs that are designed and constructed in accordance with the DNV GL class notations and additional requirements in Ch.2 Sec.2 and Ch.2 Sec.3 are considered to provide a level of safety equivalent to that provided by 33 CFR 143.120 (b), and may be assigned the class notation (US). The assignment of the (US)-notation signifies compliance with USCG requirement for the objects covered.

Guidance note:DNV GL’s results and conclusions related to services described in this statutory interpretation are based on DNV GL’s understanding and interpretation of the USCG requirements, as outlined in the policy letter and experience from executing an FOI and an FPSO project in the OCS GOM. Compliance with the (US)-notation does not represent any formal approval on behalf of USCG.


3.1.2 Verification basis applied for the (US)-notation will be stated in the “Appendix to Class Certificate”.

3.1.3 The following (US) notations are currently available:

— Production Unit (US) for FOIs— Storage Unit (US) for FSOs— Production and Storage Unit (US) for FPSOs.

Guidance note:For Mobile Offshore Drilling Units (MODU), see DNVGL-RU-OU-0101, Ch.2 Sec.6 specifying the DRILL (US) notation.


3.2 Compliance matrix for outer continental shelfChapter 2 of this Statutory Interpretation contains a matrix of supplemental USCG requirements that are applicable to a DNV GL classed FOI and FSO/FPSO. This matrix is based on the alternate design and engineering standards published in CG-ENG Policy Letter 01-13, and includes only those items that are not otherwise satisfied by meeting DNV GL classification requirements. Meeting DNV GL class scope and the

Table 3 Basic design notation

Class Notation Description

Column-stabilised a structure dependent on the buoyancy of widely spaced columns for floatation and stability in all modes of operation

Deep Draught A floating structure having a relatively deep draught to obtain high heave Eigen period avoiding resonance responses. The structure can have single or multi-vertical columns, with or without moonpools (e.g.SPARS & Dry Tree Semis)

Self-elevating A structure with hull of sufficient buoyancy for safe transport which is raised above sea surface on legs supported by the sea bed during operation

Ship-shaped Monohull ship and barge structures having displacement hulls with or without propulsion machinery

Tension Leg A buoyant structure connected to a fixed foundation by pretensioned tendons

Floating Offshore Structure not properly characterized by the above notations.

Table 4 Class notations related to service

Oil Production vessel purpose production of oil

Oil Storage vessel purpose storage of oil

Oil Loading vessel purpose loading or unloading of oil


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listed items in Ch.2 Sec.2 (for FOI) and Ch.2 Sec.3 (for FPSO and FSO) provides an equivalent level of safety to the USCG’s design and equipment standards for such units as described in the Code of Federal Regulations.

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CHAPTER 2 DESIGN AND CONSTRUCTION PROVISIONS
SECTION 1 INTRODUCTION

1 General

1.1 General1.1.1 Unless otherwise stated, the design and construction requirements given in this chapter are supplementary to the latest edition of relevant DNV GL class requirements.

1.1.2 Unless otherwise stated, class procedures, document requirements, extent of certification of materials and components, extent of surveys etc. shall be required as a minimum for the corresponding class notations. Generally the documentation requirements and extent of survey will be based on the additional regulatory basis as listed herein.


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SECTION 2 FLOATING OFFSHORE INSTALLATIONS
1 Introduction

1.1 ApplicationThe compliance matrix described in this section applies to Floating Offshore Installations (FOI) classed with DNV GL with minimum service notation OI Production Unit, POSMOOR.

1.2 Class notationsClassed installations complying with the relevant requirements of this section may, after completion of design reviews and surveys be assigned the additional class notation: Production Unit (US).

2 Compliance matrix

2.1 Application2.1.1 Reference to be made to Ch.1 Sec.1 [4], Table 3 for the applicable DNV GL rules and offshore standards to meet the assigned class requirements for FOIs on the OCS.

2.1.2 The objective of the compliance matrix listed below is to specify a list with supplemental USCG requirements that are not otherwise required or covered by DNV GL classification for the stated FOI notation. Accordingly, the compliance matrix is a subset of the USCG requirements listed in enclosure (1) to CG-ENG Policy Letter 01-13.

2.2 Compliance matrix for floating offshore installations with (US) notationThe following areas will be subject to additional design and equipment requirements as basis for assignment of the (US)-notation for FOI’s.

Table 1 Structures and stability

Area Short Description USCG Policy Letter, Encl. 1

structural standards FOI/FPSO (exc. TLP): API RP 2FPS, 2011, 2nd Ed.TLP: API RP 2T, 2010, 3rd Ed.Guidance Note:DNV GL Class requirements through DNVGL-OS-C101 to C503 Standards provides an accepted equivalent level of structural safety.

Item 4 and 5

cranes Cranes shall be certified, inspected, tested and designed in accordance with 46 CFR 107.258, 46 CFR 107.259, 46 CFR 107.260, and 46 CFR 108.601, or other standards determined by the Commandant (CG-ENG-3) to provide an equivalent level of safety.Guidance NoteDNV Standard for Certification 2.22 – Lifting Appliances provides an equivalent level of safety.

Item 12

stability The operating manual shall include sufficient stability information for operation. Item 19 stability, spar and deep draft caisson FOIs

Ref. Policy Letter, Enclosure 1, item 22. Requirements a to h.

Item 22

stability TLPs Ref. Policy Letter, Enclosure 1, item 23. Requirements a to g. Item 23 stability, general In applying the requirements of the 2009 IMO MODU Code:

— The term “Administration” means the Commandant (CG-ENG), USCG, except in paragraph 3.3.2, where it means the Commanding Officer, Marine Safety Center (MSC).

— The term “should” means “shall” and all “recommendations” are “requirements.”

— For purposes of paragraph 3.2.1, the free surface of liquids in tanks shall be determined according to the IMO 2008 Intact Stability Code.

— Paragraphs 3.2.4.2, 3.2.8, and 3.3.3 do not apply.

Item 24


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metocean study Metocean study in accordance with API Bulletin 2INT-MET required, unless the unit is capable of disconnecting from its mooring and riser systems.

Item 25

sliding watertight doors Sliding watertight doors shall comply with 46 CFR 174.100 (e) and (f). Item 26 catwalks, floors and openings

1) Perimeters shall have guardrails or wire mesh fences at least 42 in (1 m) high.

2) Guardrails shall comply with 33 CFR 143.110.

Item 45

stairways Stairways shall have at least two courses of rails. Top course/handrail min. 36 in (0.9 m) above front tread.

Item 47

Table 2 Arrangement


helicopter landing facilities

Design in accordance with:

— 2009 IMO MODU Code Ch. 13, or— 46 CFR 108.231 to 46 CFR 108.241.

Guidance NoteDNV GL additional Class Notation HELDK-SH meets and exceeds these requirements.

Aluminum helidecks shall comply with NVIC 9-97, CH.1, Enclosure 1, Section 5.2.

Item 46

accommodation spaces Shall comply with 46 CFR 108.193 to 46 CFR 108.215. Item 48

Table 3 Piping systems


marine sanitation devices USCG Approved or compliance with MARPOL 73/78 Annex IV. Item 2

Ship to FOI/FPSO Transfer of Oil and Hazardous Materials

1) Hose assembly shall comply with 33 CFR 154.500 and 156.170. 2) Shutdown and communication capabilities:

— Remote shutdown from control room/operating station— Two-way voice communication between both vessels/units. — Portable radio devices certified intrinsically safe by USCG accepted

Independent Laboratory (e.g. DNV GL).

Item 6

flow flashpoint fuels 1) Systems/installations with prime movers and units that use fuel with a closed-cup flashpoint of less than 60°C (140°F) shall be approved by the Marine Safety Center (MSC).

2) Fuel with flashpoint of not less than 43°C (110°F) is permitted for emergency generators and equipment not located in a Category A machinery space.

Item 8 (b)

vital valves with resilient materials

Vital valves with resilient materials shall:

— be fire-tested to API Standard 607, 2010 6h Ed., or ISO 19921:2005— meet Category A requirements of 46 CFR 56.20-15.

Item 15

nonmetallic piping materials

Plastic and non-metallic pipe installations shall meet the requirements of 46 CFR 56.60-25(a). Non-metallic flexible hoses shall meet the requirements of 46 CFR 56.60-25(b).

Item 16

Table 1 Structures and stability (Continued)



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Table 4 Electrical


electrical bonding Electrical bonding to the hull structure required for:

— Oil piping systems that are separated from the hull structure. — Both sides of connections/fittings with gaskets.

Item 8 (a)

emergency generator 1) Emergency switchboards shall comply with 46 CFR 111.30-29. 2) Emergency generator shall be provided with independent permanent

magnet or residual magnetism type exciter for voltage build up after two months of no operation.

3) The emergency generator or its vital components shall not adjoin a Category A machinery space. Clarification/interpretation reg. separate EGEN buildings necessary.

Guidance NoteMain power acting as emergency power may be considered on a case-by-case basis.

Item 8 (c)

environmental conditions for electrical equipment

A 50°C (122°F) ambient temperature is assumed for all rotating electrical machinery in boiler rooms, engine rooms, auxiliary machinery rooms, and weather decks, unless it can be shown that a 45°C (113°F) ambient temperature will not be exceeded in these spaces.

Item 8 (d)

emergency generator loads

The following items shall be on the emergency consumers list:

— essential marine control, alarm, and monitoring systems— the marine manual and automatic safety shutdown systems— the automatic electric power management system— each critical production/process control/import/export, alarm, and

monitoring system necessary to prevent a process upset— a process safety control system to shut down the flow of hydrocarbon

from all wells and exports to a pipeline— the blowout preventer controls, if used— control systems for all equipment that is required for emergency

operations— the diving equipment, if equipped, that is dependent on the unit for its

power source.

Item 9

ATEX Certification Electrical equipment in hazardous areas is subject to plan review and approval by the MSC. ATEX certification is not accepted by the USCG.

Item 27

electrical equipment in hazardous locations

Equipment shall be tested and listed by an independent laboratory accepted by the USCG under 46 CFR Part 159. Link to accepted independent laboratories: http://cgmix.uscg.mil/eqlabs/.

Item 28

lightning circuits in hazardous locations

Flame or explosion proof lighting fixtures in enclosed hazardous locations shall have:

— At least two lighting branch circuits.— Light for relamping any de-energized circuit.— Light switch outside hazardous location.

Item 30

ventilation requirements in hazardous locations

Ref. Policy Letter, Enclosure 1, Item 31 (a).

Guidance note:The cargo pump room may be classified as Zone 1 if the following three conditions are met per API 505:

— the space is continuously ventilated at least 20x/ min — loss of ventilation is alarmed in a manned space— and combustible gas detection installed.

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Item 31


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general emergency alarm system

Manually operated call points in the following locations:

— in any main control room— at any drilling console— at the feeder distribution panel— in any navigation bridge — in a routinely occupied space that is as far as practicable from all other

activation locations.

Item 43 (d)

obstruction lights and warning devices

The unit shall meet applicable requirements in 33 CFR part 67. Item 44

Table 5 Lifesaving equipment


lifesaving equipment 1) The equipment shall be USCG type approved, or approved under the MRA Agreement.

2) The FOI/FPSO shall comply with:

— 46 CFR 108.503, and — 2009 IMO MODU Code Ch. 10.

Item 32 and 33

3) Lifeboats: 95 kg (210 lbs) per person, 530 mm (21 in) minimum seat width.

4) Dedicated approved rescue boat/launching appliance instead of dual approved life/rescue boat.

Item 33 (a)

Table 6 Fire safety


structural fire protection Except for H-60, all structural fire protection materials shall be USCG type approved, or approved under the MRA Agreement.

Item 34

fire extinguishing — shall be USCG type approved— fire hoses and associated equipment shall comply with 46 CFR 108.425 — fixed low expansion foam systems installed on cargo decks shall comply

with 46 CFR 34.20— collapsible hoses are acceptable on open deck fire hydrants, and in

enclosed columns, pontoons and machinery spaces.

Item 35

fire detection Shall be USCG type approved. Item 35

portable and semi-portable fire extinguishers

Shall be USCG type approved and comply with 46CFR 108.491 to 108.496.

Item 36

fire-fighter’s outfits Fire-fighter’s outfits and self-contained breathing apparatus shall comply with 46 CFR 108.497.

Item 37

means of escape — shall comply with 46 CFR 108.151— solid steel decking in at least one escape route from accommodation

areas to a primary means of escape— doors with provisions for locking shall comply with SOLAS II-2/13.3.2.6

Item 38

marking Marking of fire protection equipment in accordance with 46 CFR 108.621-635 and 108.637.

Item 39

h-rated fire boundaries for deckhouses

Minimum H-60 rating on all normally occupied deckhouses, incl. temporary buildings, facing process areas, wellheads, produced oil storage tanks and similar hazards, extending minimum 10 feet to the sides.

Item 40

Table 4 Electrical (Continued)



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SECTION 3 FLOATING STORAGE UNITS AND FLOATING PRODUCTION, STORAGE AND OFFLOADING UNITS
1 Introduction

1.1 ApplicationThe compliance matrix described in this section may be applied to floating storage units (FSO) and floating production, storage and offloading units (FPSO) units satisfying the following criteria:

— The FSO unit is classed with DNV GL with minimum class notations 1A Storage Unit POSMOOR OFFLOADING.

— The FPSO unit is classed with DNV GL with minimum class notations 1A Production and Storage Unit POSMOOR OFFLOADING.

— The unit will be registered with a national maritime administration (flagged).

Guidance note:USCG’s current position is to require a valid tanker certificate for evacuation during a hurricane situation. Therefore such FPSOs /FSOs require a detachable/ disconnectable turret which can be relatively quickly disconnected in the event of a hurricane or extreme weather. In such situation the vessel will adopt the tanker mode and move out to seek shelter.


1.2 Class notationsClassed units complying with the relevant requirements of this section may, after completion of design reviews and surveys be assigned the additional class notation:

— Storage Unit (US)— Production and Storage Unit (US)

Guidance note:For Floating Storage units (FSOs) the compliance matrix below may be applied as for FPSOs, but without the production related requirements.


2 Compliance matrix

2.1 Application2.1.1 Reference to be made to Ch.1 Sec.1 [4], Table 3 for the applicable DNV GL rules and offshore standards to meet the assigned class notation requirements for FPSOs and FSOs in the OCS.

2.1.2 The objective of this compliance matrix is to specify a list with supplemental USCG requirements that are not otherwise required by DNV GL classification for a stated notation for an FPSO. Accordingly, the matrix is a subset of the USCG requirements listed in enclosure (2) to CG-ENG Policy Letter 01-13.

2.2 Compliance basis for floating storage and offloading unit and floating production storage and offloading unit (US)The following areas will be subject to additional design and equipment requirements as basis for assignment of the (US)-notation for FSOs and FPSOs.


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Table 1 Structures and stability


intact and damage stability

FPSOs shall comply with the following requirements applicable for surface units:

— MARPOL Annex I regulations 27 and 28 (with the exception of paragraph 6);

— 2009 MODU Code Sections 3.6 and 3.7.

In applying the requirements from the 2009 MODU Code:

— The term “Administration” means the Commandant (CG-ENG), USCG.— The term “should” means “Shall”.— The term “recommendations” means “requirements”.

Item 9

demonstration of safe disconnection procedure

FPSOs that employs a disconnectable system for severe weather evasion shall demonstrate that the disconnect procedure does not jeopardize the stability.

Item 10

catwalks, floors and openings

Perimeters shall have guardrails or wire mesh fences at least 1 meter (39 inches) high. If guardrails are used:

— They shall comply with 46 CFR 108.217 to 108.223;— If a toe board is installed, one of the intermediate courses may be

omitted and the other course placed approximately halfway between the top of the toe board and the top course.

Item 25

Table 2 Piping systems


tank arrangement Oil shall not be stored in any tank closer to the stern than 2.0 m. Item 2 (g)

pollution prevention The FPSO shall comply with MARPOL Annex I regulations 23, 29 and 30 (paragraphs 1, 4 and 7 only).

Item 2 (h)

inert gas system in cargo tanks

A fixed inert gas system shall be installed irrespective of the vessels deadweight. Compliance with SOLAS II-2/4.5.5 required, except that a dry type water seal shall not be used.

Item 2 (j)

ballast and produced oil piping

Ballast and produced oil piping systems shall meet the requirements in 33 CFR 157.11(g)(1).

Item 2 (m)

PV valves Pressure vacuum relief valves shall meet the requirements in 46 CFR 162.017 or ISO 15364:2007.

Item 2 (n)

oil transfer hose Produced oil transfer hoses shall comply with the requirements in 33 CFR 154.500 and 33 CFR 156.170.

Item 2 (o)

Table 3 Hazardous locations


hazardous area locations Paragraph (12) and (13) of the Policy Letter Enclosure 2 shall be used to identify hazardous locations.

Item 11

See Policy Letter for Zone 0 and Zone 1 definitions. Item 12 (a),(b)


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Table 4 Electrical and instrumentation

emergency generator loads

The following items shall be on the emergency consumers list:

— essential marine control, alarm, and monitoring systems— the marine manual and automatic safety shutdown systems— the automatic electric power management system— the control system for the position thrusters for the thruster-assisted

mooring system, if installed— each critical production/process control/import/export, alarm, and

monitoring system necessary to prevent a process upset— a process safety control system to shut down the flow of hydrocarbon

from all wells and process systems— control systems for all equipment that is required for emergency

operations— the diving equipment, if equipped, that is dependent on the unit for its

power source— quick disconnect systems that are used to stop all process flow to the

floating installation automatically, without leaks from process fluids.

Item 4

detection of conditions for disconnection

The FPSO shall be able to detect conditions that require disconnection from the turret.

Item 8

ATEX certification Electrical equipment in hazardous areas is subject to plan review and approval by the MSC. ATEX certification is not accepted by the USCG.

Item 11 refer to Item 27 in encl 1

electrical equipment in hazardous locations

Equipment shall be tested and listed by an independent laboratory accepted by the USCG under 46 CFR Part 159. Link to accepted independent laboratories: http://cgmix.uscg.mil/eqlabs/.

Item 11 refer to item 28 in encl 1

lightning circuits in hazardous locations

Flame or explosion proof lighting fixtures in enclosed hazardous locations shall have:

— at least two lighting branch circuits— light for relamping any de-energized circuit— light switch outside hazardous location.

Item 11 refer to item 30 in encl 1

electrical swivel certification

Hydrocarbon product electrical swivels shall be tested and listed or certified by a USCG accepted independent laboratory in accordance with 46 CFR Part 159.

Item 18

Table 5 Fire safety


Fire extinguishing system for power generation unit

A USCG approved fixed fire extinguishing system shall be installed for the power generation unit enclosure.

Item 3 (a) (iv)

Structural fire protection All structural fire protection materials shall be USCG type approved. Item 20

Fire Extinguishing — shall be USCG type approved— fire main and all associated components shall comply with 46 CFR

95.10— fixed low expansion foam systems installed on cargo decks shall comply

with 46 CFR 34.20— collapsible hoses are acceptable on open deck fire hydrants, and in

enclosed columns, pontoons and machinery spaces.

Item 21

Fire Detection Shall be USCG type approved. Item 21

Fire-fighter’s outfits Fire-fighter’s outfits and self-contained breathing apparatus shall comply with 46 CFR 96.35.

Item 22

Wellhead protection If applicable, wellheads (i.e. production areas containing oil and gas risers, export lines and associated shut down valves) with a maximum shut-in pressure exceeding 600 psi shall be enclosed within minimum A-0 barriers to protect any escape routes, lifeboat embarkation stations, fire extinguishing equipment and vital systems needed for power management

Item 24


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SECTION 4 EQUIVALENCIES AND OTHER DESIGN CONSIDERATIONS (INFORMATIVE)
1 GeneralThe intent of this section is to highlight and include certain design and construction issues relating to FOIs operating in the US OCS which may deserve special consideration.

2 Passive ballast systemA significant number of FOIs (SPARS, certain type of semi-submersibles and to an extent certain TLPs) operating in the OCS have a ballast system with different functional design requirements than conventional ballast designs for ships and MODUs. Accordingly, care should be taken when applying the rules to such ‘passive’ type systems to ensure the application is proportional to the criticality of the system to the unit. In all cases, proposed deviations from the classification rules should be vetted with the USCG early in the approval process.

3 External impact load on hullOne of the design conditions for a hull column or leg on a FOI is accidental impact with a supply vessel. In the US Gulf of Mexico, the impact loading is based on a supply boat of 1000 tons moving at 0.5 m/s per API RP-2A. According to DNVGL-OS-A101, a supply boat size of 5000 tons and a speed of 2 m/s is used, which represents a significant difference. To avoid inconsistent application of rules among different units, it is recommended that this difference is discussed early on in the design process with the USCG, and that an appropriate deviation request with justification is submitted as relevant.

4 Fire protection boundariesThe issuance of CG-ENG Policy Letter 01-13 marks a shift in the USCG’s approach to prescribing structural fire protection boundaries and materials for FOIs. Previously, NVIC 9-97 was the standard and it has been common practice among offshore industry vendors to design and manufacture buildings on FOIs accordingly. Policy Letter 01-13 invokes requirements from the 2009 IMO MODU Code, which is more stringent than NVIC 9-97 in certain areas. Additionally, the USCG has published a Notice of Proposed Rulemaking to harmonize their fire fighting regulations with international standards. (See 79 FR 2254: Harmonization of Standards for Fire Protection, Detection, and Extinguishing Equipment; Proposed Rule). Accordingly, it is important to flag these differences early in the project to ensure all are aware of the latest requirements.

5 Platform verification program by a certified verification agent

5.1 GeneralThe platform verification programme has been defined in 30 CFR 250 Subpart I. It states the requirements, the industry standards and the platform program to be undertaken by the facility operator and the platform verification program. The verification program needs to be performed by a nominated CVA (DNV GL has such authorization). The CVAs responsibilities during design, fabrication and installation are defined in 250.915 250.916 and 250.917.

5.2 Scope of assessmentAs specified in 250.916 for design verification for floating facilities (FOIs and FPSOs) the CVA needs to ensure that the requirements of the USCG for structural integrity and stability have been met. Besides the structural integrity and stability, BSEE requires specified independent assesments for the following:

— drilling, production and pipeline risers and riser tensioning system— turrets and turret-hull interfaces (for FPSOs)


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— foundations and anchoring systems— mooring or tethering systems.
Therefore for these units with DNV GL class including the US notation, most of the BSEE requirement for the structural integrity and stability inclusive of mooring, turret and hull interfaces will be satisfied.

The above assesments can be performed under the CVA scheme using the applicable international standards mentioned in 250.901, 2007 NTL G14 and equivalent DNV GL standards (which have been accepted by BSEE under the scheme for previous GOM projects).


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APPENDIX A UNITED STATES COAST GUARD POLICY LETTER

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Enclosure (1): Requirements for FOIs and FPSOs on the U.S. OCS CG-ENG Policy Letter No. 01-13 June 26, 2013 References: (a) ASTM International Standard ASTM F1273 - 91(2007), “Specification for Tank Vent

Flame Arresters” (b) International Maritime Organization Maritime Safety Committee Circular

MSC/Circ.677, “Revised Standards for the Design, Testing and Locating of Devices to Prevent the Passage of Flame into Cargo Tankers”, 1994, as amended.

(c) American Petroleum Institute (API) Recommended Practice (RP) 2FPS, “Planning, Designing, and Constructing Floating Production Systems,” 2011, 2nd Ed.

(d) API RP 2T, “Planning, Designing, and Constructing Tension Leg Platforms,” 2010, 3rd Ed.

(e) ASTM F1122-04(2010), “Standard Specification for Quick Disconnect Couplings (6in. NPS and Smaller)

(f) IMO Resolution A.1023(26), “Code for the Construction and Equipment of Mobile Offshore Drilling Units,” 2009 (2009 MODU Code)

(g) API RP 14FZ, Recommended Practice for Design, Installation, and Maintenance of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class I, Zone 0, Zone 1 and Zone 2 locations, Second Edition, 2013

(h) API Standard 607, “Fire Test for Quarter-turn Valves and Valves Equipped with Nonmetallic Seats”, 2010, 6th Ed.

(i) ISO 19921:2005, “Ships and marine technology – Fire resistance of metallic pipe components with resilient and elastomeric seals – Test methods”

(j) API RP 500, “Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Division I and Division 2”, 2012

(k) National Fire Protection Association (NFPA) 70, “National Electrical Code”, 2011 (l) American National Standards Institute (ANSI) UL 674 – Standard for Electric Motors

and Generators for Use in Division 1 Hazardous (Classified) Locations, Fifth Edition (dated May 31, 2011) (“ANSI/UL 674”)

(m) ANSI/UL 823 – Standard for Electric Heaters for Use in Hazardous (Classified) Locations, Ninth Edition including revisions through November 15, 2007 (dated October 20, 2006)

(n) ANSI/UL 844 – Standard for Luminaires for Use in Hazardous (Classified) Locations, Thirteenth Edition (dated June 29, 2012) (“ANSI/UL 844”)

(o) ANSI/UL 913 - Standard for Intrinsically Safe Apparatus and Associated Apparatus for Use in Class I, II, and III, Division 1, Hazardous Locations, Seventh Edition including revisions through June 3, 2010 (dated July 31, 2006)

(p) ANSI/ISA 12.12.01-2012 (UL 1604)- Non-Incendive Electrical Equipment for Use in Class I and II, Division 2 and Class III, Division 1 and 2 Hazardous (Classified) Locations

(q) ANSI/UL 1203 – Standard for Explosion-Proof and Dust-Ignition-Proof Electrical Equipment for Use in Hazardous (Classified) Locations, Fourth Edition including revisions through October 28, 2009 (dated September 15, 2006)


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(r) ANSI/UL 2225 – Standard for Cables and Cable-Fittings for Use in Hazardous (Classified) Locations, Third Edition February 25, 2011

(s) Canadian Standards Association (CAN/CSA), CAN/CSA-C22.2 No. 0-M91 - General Requirements - Canadian Electrical Code, Part II, July 1991, Reaffirmed 2006

(t) CAN/CSA-C22.2 No. 157-92 - Intrinsically Safe and Non-Incendive Equipment for Use in Hazardous Locations, June 2003, Reaffirmed 2006

(u) C22.2 No. 30-M1986 - Explosion-Proof Enclosures for Use in Class I Hazardous Locations, November 1988, Reaffirmed 2007

(v) C22.2 No. 213-M1987 - Non-Incendive Electrical Equipment for Use in Class I, Division 2 Hazardous Locations, March 1987, Reaffirmed 2008

(w) Factory Mutual (FM) 3600 - Approval Standard for Electric Equipment for use in Hazardous (Classified) Locations General Requirements, November 1998

(x) FM 3610 - Approval Standard for Intrinsically Safe Apparatus and Associated Apparatus for Use in Class I, II, and III, Division 1, Hazardous (Classified) Locations, January 2010

(y) FM 3611 - Approval Standard for Non-Incendive Electrical Equipment for Use in Class I and II, Division 2, and Class III, Divisions 1 and 2, Hazardous (Classified) Locations, December 2004

(z) FM 3615 - Approval Standard for Explosionproof Electrical Equipment General Requirements, August 2006

(aa) FM 3620 - Approval Standard for Purged and Pressurized Electrical Equipment for Hazardous (Classified) Locations, August 2000

(bb) NFPA Standard 496, “Standard for Purged and Pressurized Enclosures for Electrical Equipment”, 2008

(cc) API RP 505, “Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Zone 0, Zone 1 and Zone 2”, 1998

(dd) ANSI/API RP 14F, “Design, Installation, and Maintenance of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class 1, Division 1 and Division 2 Locations”, 2008

(ee) IEC 61892-7, “Mobile and fixed offshore units- Electrical installations- Part 7: Hazardous areas”, 2007

(ff) IEC 60092-502, “Electrical installations in ships –Part 502: Tankers- Special Features”, 1999

(gg) ASTM E1529-10, “Standard Test Methods for Determining Effects of Large Hydrocarbon Pool Fires on Structural Members and Assemblies”

(hh) IMO Resolution MSC.307(88), “International Code for Application of Fire Test Procedures, 2010 (2010 FTP Code)

(ii) API RP 14J, “Recommended Practice for Design and Hazards Analysis for Offshore Production Facilities”, 2001

(jj) IMO Resolution MSC.48(66), “International Life-Saving Application Code,” 2010 (2010 LSA Code)


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(kk) IMO Resolution A.1021(26), “Code on Alerts and Indicators”, 2009

General (1) The floating offshore installation (FOI) must be classed by either the American Bureau of Shipping (ABS), Det Norske Veritas (DNV), or Lloyd’s Register (LR) and receive one of the following notations:

(a) ABS: A1 Floating Offshore Installation (FOI) or other applicable notation described in 1-2-3/3.1 that includes all the elements of “FOI”.

(b) DNV: OI with applicable notations for installation design OR 1A1 for any self propelled units.

(c) LR: OI 100 AT (Unit Type) (Specified Operating Area), with applicable notations for installation design and operating criteria.

(2) Marine sanitation devices (MSD) installed on FOIs and floating production and storage offshore units (FPSO) must be U.S. Coast Guard type approved under 33 CFR Part 159 or may comply with MARPOL 73/78, ANNEX IV in accordance with Navigation and Vessel Inspection Circular 1-09, “Voluntary Compliance with International Sewage Regulations in Annex IV to MARPOL 73/78”.

(3) Flame arresters on the FOI/FPSO must meet the requirements in either reference (a) or reference (b), as amended.

(4) Each FOI/FPSO, other than a tension leg platform (TLP) FOI, must comply with the applicable requirements in reference (c).

(5) Each Tension leg platform (TLP) FOI must comply with the applicable requirements (other than those relating to riser systems) in reference (d).

Ship to FOI/FPSO Transfer of Oil and Hazardous Materials as defined by 33 CFR 154.105 (6) Each hose assembly used for transferring oil or hazardous material (Methanol, LDHI, diesel oil, etc)

must comply with the requirements in 33 CFR 154.500 and 33 CFR 156.170.

(a) The FOI/FPSO must have the following oil transfer emergency shutdown and communications capabilities:

(i) In a continuously manned control room, a remote emergency means to enable the person in charge (PIC) of a transfer operation to stop the flow must be provided.

(ii) The means to stop the flow may be a pump control, a quick-acting power-actuated valve, or another approved operating procedure.

(iii) The means to stop the flow must be operable from the operating station of the PIC of the transfer operation.

(iv) The installation must have continuous two-way voice communication between the PICs of the oil transfer operations on both vessels.

(v) Portable radio devices used during the transfer of flammable or combustible liquids must be tested and listed or certified intrinsically safe for Class I, Division I (IEC Zone 1 or Class I, Zone 1), Group D requirements, by an independent laboratory accepted by the Coast Guard under 46 CFR Part 159.


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(b) Quick-disconnect couplings not designed to reference (e) must meet the following:

(i) Minimum 4:1 safety factor.

(ii) Pipe threads and/or flanges in accordance with reference (e) standards.

(iii) The testing and inspection requirements of reference (e).

Machinery and Electrical Installations (7) Machinery and electrical installations on the FOI must comply with the applicable regulations in reference (f), Chapters 4 and 5. As an alternate, the NEMA or IP ratings in reference (g) Tables 6-10, 6-11 and 6-12 may be used.

(8) In addition, the following requirements apply to FOI/FPSOs:

(a) The FOI/FPSO must comply with the following electrical bonding requirements:

(i) Oil piping systems that are separated from the hull structure must be electrically bonded to the hull structure by a method indicated in subparagraph (iii) of this paragraph.

(ii) An oil pipe joint or an oil hose connection fitting that has a gasket must be electrically bonded by a method indicated in subparagraph (iii) of this paragraph, which bonds with both sides of the connection to the hull structure.

(iii) An electrical bond must be made by one of the following methods:

� A metal bonding strap attached by welding or bolting;

� Two or more bolts that give metal-to-metal contact between the bolts and the parts to be bonded; or

� Metal-to-metal contact between adjacent parts under designed operating conditions. (b) Except as noted below, for prime movers and units that use fuel with a closed-cup flashpoint of less than 60°C (140°F), the complete installation must specifically be approved by the Marine Safety Center (MSC).

(i) Emergency generators, as well as equipment not located in a Category A machinery space, are permitted to use fuel with a flashpoint of not less than 43°C (110°F).

(c) The emergency generator must meet the following:

(i) The requirements for emergency switchboards in 46 CFR 111.30-29.

(ii) An emergency generator must be provided with a permanent magnet, or a residual magnetism type exciter that has a capability of voltage build up after two months of no operation. The voltage built up must be accomplished without the aid of an external electric power source.

(iii) The emergency generator or its vital components must not adjoin a Category A machinery space, or those spaces containing the unit’s main source of electrical power and its vital components. The emergency generator must have an emergency switchboard which must be as near as practicable to the emergency power source but not in the same space as the accumulator batteries. The separate compartments must be accessible from the weather deck, from either location, and on the same deck level. Compartments must not adjoin a Category A machinery


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space or spaces containing the main source of electrical power and its vital component, and cables must be kept clear of the of the bulkheads forming these boundaries.

(d) Unless demonstrated otherwise by engineering calculation or empirical data, an ambient temperature of 40°C (104°F) is assumed except as otherwise stated below.

(i) A 50°C (122°F) ambient temperature is assumed for all rotating electrical machinery in boiler rooms, engine rooms, auxiliary machinery rooms, and weather decks, unless it can be shown that a 45°C (113°F) ambient temperature will not be exceeded in these spaces.

(ii) A 45 °C (113 °F) ambient temperature is assumed for cable and all other non-rotating electrical equipment in boiler rooms, in engine rooms, in auxiliary machinery rooms, and on weather decks. A 30 °C (86 °F) ambient temperature in air conditioned spaces.

(iii) A 55°C (131°F) ambient temperature is assumed for all control and instrumentation equipment.

(iv) If electrical equipment is utilized in a space in which the equipment’s rated ambient temperature is below the assumed ambient temperature of the space, its load must be derated. The assumed ambient temperature of the space plus the equipment’s actual temperature rise at its derated load must not exceed the equipment’s total rated temperature (equipment’s rated ambient temperature plus its rated temperature rise).

(9) For FOIs, in addition to Regulation 5.4 of reference (f), and loads required as per design/operational requirements, the following loads must be arranged so that they can be energized by the emergency generator:

(a) Essential marine control, alarm, and monitoring systems;

(b) The marine manual and automatic safety shutdown systems;

(c) The automatic electric power management system;

(d) Each critical production/process control/import/export, alarm, and monitoring system necessary to prevent a process upset;

(e) A process safety control system to shut down the flow of hydrocarbon from all wells and exports to a pipeline;

(f) The blowout preventer controls, if used;

(g) Control systems for all equipment that is required for emergency operations;

(h) The diving equipment, if equipped, that is dependent on the unit for its power source.

(10) For FOIs, in addition to the emergency generator, the emergency loads in paragraph (9) above must have a temporary or transitional supply source that provides power for at least 30 minutes and must be powered continuously, i.e. loads must not have a power outage.

(11) For FOIs, the above design and engineering standards listed in paragraph (7) and (8) apply to the industrial power system when the system is connected to the ship service power system.

(12) Cranes on FOI/FPSOs must be certified, inspected, tested and designed in accordance with 46 CFR 107.258, 46 CFR 107.259, 46 CFR 107.260, and 46 CFR 108.601, or other standards determined by the Commandant (CG-ENG-3) to provide an equivalent level of safety.


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(13) All FOI/FPSO bilge systems must meet the requirements of either:

(a) SOLAS chapter II-1, regulation 35-1.2; or

(b) Code of Federal Regulations subchapter F, sections 56.50-50 and 56.50-55.

(14) TLP, spar and column-stabilized FOI ballast pumping systems must meet the requirements of section 4.10 of reference (f).

(15) On all FOI/FPSO valves employing resilient materials and installed at the following locations must be fire-tested to either reference (h) or reference (i), and must meet the Category A requirements of 46 CFR 56.20-15:

(a) Vital piping system manifolds; and

(b) Closure for any opening in the shell of the vessel.

Nonmetallic Piping Materials (16) Plastic and nonmetallic pipe installations on FOI/FPSOs must meet the requirements of 46 CFR 56.60-25(a). Nonmetallic flexible hose must meet the requirements of 46 CFR 56.60-25(b).

Fuel Gas Supply Valves (17) On the FOI/FPSOs, fuel supply for service generator prime movers must be fitted with positive shutoff valves arranged for both local control and remote control from an accessible location outside the engine compartment. These valves must be located as close as practicable to the tank or other source of fuel. The installation must have maintenance and testing plans for these valves and operators.

Stability (18) The lightweight displacement and centers of gravity of the FOI/FPSO must be determined in accordance with the requirements in 46 CFR 170 subpart F. This includes submission and approval of a stability test procedure as prescribed by 46 CFR 170.085.

(19) The operating manual must include sufficient stability information to enable the master or person in charge to operate the FOI/FPSO in compliance with the applicable requirements of this section and must be maintained throughout the life of the installation.

(20) Ship-type FOIs, other than those used to store produced oil in bulk, must comply with the requirements in sections 3.2, 3.3, 3.4, 3.5, 3.6, and 3.7 of reference (f), that are applicable to surface units.

(21) Column-stabilized FOIs must comply with the requirements in sections 3.2, 3.3, 3.4, 3.5, 3.6, and 3.7 (except that issuance of a load line certificate is not required) of reference (f) that are applicable to column-stabilized units.

(22) Spar and Deep Draft Caisson FOIs must comply with the following requirements in each condition of operation over the full range of operating drafts:

(a) The height of the vertical center of gravity must not exceed that of the vertical center of buoyancy.


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(b) Curves of righting moments and wind heeling moments must be calculated in accordance with section 3.2 of reference (f), except that the lever of the wind overturning force in paragraph 3.2.6 must be taken to the attachment point of the mooring lines if that is below the center of lateral resistance of the underwater body.

(c) In the intact condition, the area under the righting moment curve to 30 degrees must not be less than 130 percent of the area under the wind heeling moment curve to the same angle, and the downflooding angle must not be less than 30 degrees.

(d) In the intact condition with the wind heeling moment applied, the maximum angle of heel must not be greater than 6 degrees for normal operating conditions and 12 degrees for severe storm conditions.

(e) The spar must comply with the requirements in paragraphs 3.3.2, 3.7.2 through 3.7.6, and section 3.6 of reference (f).

(f) For damage stability assessment purposes, the assumed extent of damage must have a height and width of 3 meters (10 feet) with a horizontal penetration of 1.5 meters (5 feet) inboard from the hull plating. This extent of damage must be assumed at all levels between 3 meters (10 feet) below the minimum operating draft and 5 meters (16.4 feet) above the maximum operating draft.

(i) All compartments within the extent of damage must be assumed to be flooded.

(ii) Any piping and ventilation systems within the extent of damage must be assumed to be damaged, and a positive means of closure for these systems must be provided at all adjacent watertight boundaries to prevent progressive flooding of other compartments.

(iii) In any case where damage of a lesser extent would result in a more severe stability condition, such lesser extent must be assumed.

(g) In the damaged condition, the spar must comply with the requirements in paragraphs 3.4.3, 3.4.4, 3.4.5, and 3.4.6 of reference (f), except that the damage referenced in paragraph 3.4.3.1 must be replaced by the damage indicated in paragraph (f).

(h) In the damaged condition with the wind heeling moment applied, the final waterline must be at least 1.5 meters (5 feet) below the lowest point of the hull upper deck.

(23) TLP FOIs must comply with the following requirements:

(a) Tendon tensions must be maintained in a safe positive range to ensure integrity of the tendons and floating installation in all operating conditions. The analysis to demonstrate a safe positive range of tendon tensions must include all loading conditions and center of gravity variations permitted by the operating manual, and must be conducted in accordance with the applicable provisions of reference (d) and API Bulletin 2INT-MET.

(b) A tendon load monitoring system must be installed in accordance with reference (d). The system must have sufficient redundancy to ensure continued or restored operation in the event of a single component failure.

(c) A tendon removed analysis must be conducted in accordance with reference (d), section 5.6.4.4.

(d) A safe positive range of tendon tensions must also be maintained after assumed flooding from the following damage cases:


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(i) An extent of damage with a height and width of 3 meters (10 feet) and a horizontal penetration of 1.5 meters (5 feet) inboard from the hull plating. This extent of damage must be assumed on the exposed periphery of the hull at all levels between 3 meters (10 feet) below the minimum operating draft and 5 meters (16.4 feet) above the maximum operating draft. However, no vertical bulkhead should be assumed to be damaged except where bulkheads are spaced closer than a distance of one eighth of the column perimeter at the draft under consideration, measured at the periphery. The “exposed periphery of the hull” means outboard of a plane that connects the vertical centerlines of the columns on the periphery of the floating installation;

(ii) Damage to any one hull compartment at or below the waterline at all operating drafts; and

(iii) Damage to any one tendon compartment.

(e) In addition to the provisions in paragraph (a), the analysis to demonstrate a safe positive range of tendon tensions after damage must apply the following provisions:

(i) No pumping out or ballasting of compartments to compensate for flooding may be considered in the analysis.

(ii) All compartments within the extent of damage specified in subparagraph (d)(i) must be assumed to be flooded.

(iii) Any piping and ventilation systems within the extent of damage specified in subparagraph (d)(i) must be assumed to be damaged, and a positive means of closure for these systems must be provided at all adjacent watertight boundaries to prevent progressive flooding of other compartments.

(f) The TLP must comply with the requirements in paragraphs 3.3.2, 3.7.2, and 3.7.3, and section 3.6 of reference (f).

(g) If the OCMI determines that it is necessary, an analysis will be required comparing the tendon tensions from the tendon load monitoring system to the tendon tensions calculated from weight and buoyancy principles. Any significant differences between the tendon tensions in the analysis must be reconciled to the satisfaction of the OCMI.

(24) In applying the requirements of reference (f) in paragraphs (20) to (23) above:

(a) The term “Administration” means the Commandant (CG-ENG), U.S. Coast Guard, except in paragraph 3.3.2, where it means the Commanding Officer, Marine Safety Center (MSC).

(b) The term “should” means “must” and all “recommendations” are “requirements.”

(c) For purposes of paragraph 3.2.1, the free surface of liquids in tanks must be determined according to the IMO 2008 Intact Stability Code.

(d) Paragraphs 3.2.4.2, 3.2.8, and 3.3.3 do not apply.

(25) A site-specific metocean study, performed in accordance with the applicable standards in API Bulletin 2INT-MET, must be conducted to determine the expected environment conditions for the FOI/FPSO location. If the one minute mean wind speed (at 10 meters above sea level) for the 100-year return period is less than 100 knots (51.5 m/s), a minimum 100 knots wind speed must be used as the severe storm condition wind velocity for compliance with the applicable requirements of this section.


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This paragraph does not apply to FOI/FPSOs that are capable of disconnecting from its mooring and riser systems for purposes of severe weather evasion.

(26) All sliding watertight doors on the FOI/FPSO must comply with the requirements listed in 46 CFR 174.100(e) and (f).

Hazardous Locations Electrical installations in hazardous locations on the FOI must meet the following requirements:

(27) Electrical equipment installed in hazardous areas is subject to plan review and approval by the MSC. Equipment certified under the ATEX scheme is not accepted by the U.S. Coast Guard. (28) Electrical installations in hazardous locations must comply with either (a), (b)(i) or (b)(ii) of this paragraph. Standards must not be combined in a manner that would compromise system integrity or safety:

(a) The criteria of reference (j) may be used to identify hazardous locations. When reference (j) is selected to determine hazardous locations, the protection techniques listed in section 500.7 of reference (k) may be used and the equipment requirements in section 500.8 of reference (k) must be met. The equipment must be tested and listed by an independent laboratory accepted by the U.S. Coast Guard under 46 CFR Part 159 as meeting any of the standards of references (l)-(z). You may also use the standards of section (b)(i) of this paragraph. Where these standards are applied, the zone to division mapping criteria of Clause 501.5 of Article 501 of reference (k) must be used. Equipment that meets references (aa) or (bb) is subject to plan review and approval by the MSC.

(b) The criteria of reference (cc) to identify hazardous locations may be used. When reference (cc) is selected to determine hazardous locations, the requirements listed in paragraphs (b)(i) or (b)(ii) may be used.

(i) Equipment identified for Class I locations may meet Sections 505.7 and 505.9 of reference (k) and must be tested and listed by an independent laboratory accepted by the U.S. Coast Guard under 46 CFR Part 159 as meeting one or the combination of the ANSI/ISA 60079 Series of standards incorporated in reference (k) Article 505. You may also use the standards of section (a) of this paragraph. Where these standards are applied, the zone to division mapping criteria of Clause 505.9(C)(1) of Article 505 of reference (k) must be used.

(ii) Electrical apparatus in hazardous locations must meet one or the combination of the IEC 60079-0, -1, -2, -5, -6, -7, -11, -13, -15, -18 and/or -25 standards and be tested by an Ex Testing Laboratory (ExTL) and certified by an Ex Certification Body (ExCB) under the IECEx System, both accepted by the Coast Guard under 46 CFR 159.010. Where these standards are applied, the zone to division mapping criteria of Clause 501.5 of Article 501 of the NEC 2011 may be used.

(29) Cable and wiring in hazardous locations must meet the following:

(a) As allowed in reference (k) Articles 501-505, rigid metal conduit, and MI or HL type cables may be used instead of the marine shipboard cables. Conduits, cable seals and sealing methods must meet Clause 6.8 of references (dd) and (g).


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(b) For hydrocarbon production, production support, process, transfer, and venting systems, the wiring materials and methods in Clause 6.4 of reference (dd) may be used.

(c) The wiring methods for intrinsically safe systems must meet Section 504.30 of reference (k). The installation and wiring to the standards in paragraph (28)(b)(ii), must comply with Clause 7 of reference (ee).

(d) Joints or splices in hazardous locations must be avoided if possible. Any joints or splices must be provided junction boxes or enclosures for hazardous locations.

(30) Lighting circuits serving flameproof or explosion proof lighting fixtures in an enclosed hazardous location must have at least two lighting branch circuits, be arranged so that there is light for relamping any de-energized lighting circuit, and be arranged so that the switch for the room containing flameproof or explosion proof lighting fixtures is not within the hazardous location.

(31) Ventilation requirements for hazardous locations must comply with Clauses 8.1.3, 8.2, and 8.3 of reference (ff). Note: The word “mechanical”, as used in this section, is interchangeable with the word “artificial” in reference (ff).

(a) The power ventilation of enclosed hydrocarbon pump rooms must be sufficient to effect a minimum complete 20 air changes per hour, based upon the volume of the pump room and associated trunks up to the deck at which access from the weather is provided. The power ventilation units must be able to remove vapors from points near the deck or bilges at points where concentrations of vapors may be expected. Enclosed areas containing devices handling hydrocarbons, such as hydrocarbon handling or pump rooms are Class I, Special Division 1 (Zone 0) hazardous locations.

(b) The mechanical ventilation for the enclosed pump-engine compartment that contain the prime movers for the pumps that handle flammable or combustible liquids must be sufficient to provide at least 8 air changes per hour.

Lifesaving Equipment (32) Lifesaving equipment must be USCG type approved. The FOI/FPSO must comply with the lifesaving requirements of 46 CFR 108.503 and chapter 10 of the reference (f), “Lifesaving Appliances and Equipment.”

(33) Equipment approved under the MRA agreement will be accepted; provided it has a Coast Guard type approval series number as per the requirements of NVIC 08-04, Change 1: “Guide to Marine Equipment Approvals Covered by US-EC MRA & by US-EEA EFTA MRA”.

(a) In accordance with 77 Federal Register 70172 “Lifesaving and Fire-Fighting Equipment, Training and Drills Onboard Offshore Facilities and Mobile Offshore Drilling Units (MODUs) Operating on the U.S. Outer Continental Shelf (OCS)” November 23, 2012, it is recommended that:

(i) New or replacement lifeboats use a weight of 95 kg (210 lbs) per person with a minimum seat width of 530 mm (21 inches); and

(ii) A dedicated approved SOLAS rescue boat (USCG approval series 160.156 or equivalent) and dedicated approved launching appliance be provided instead of relying on a dual approved life/rescue boat.


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Enclosure (1): Requirements for FOIs and FPSOs on the U.S. OCS CG-ENG Policy Letter No. 01-13 June 26, 2013 Firefighting and Fire Protection (34) Structural fire protection boundaries and materials for the FOI must comply with Chapter 9, paragraphs 9.2 through 9.3, of reference (f). Except for H-60, all structural fire protection materials must be Coast Guard type approved. Materials that have USCG type approval under the U.S. and EC/EEA MRA agreements are acceptable.

(35) Fire-extinguishing and fire-detection equipment must be USCG type approved, and comply with Chapter 9, paragraphs 9.5, 9.6, 9.8, 9.10 and 9.11, of the reference (f). The fire main system and all associated components, including, but not limited to, fire pumps, fire hoses, fire hydrants, and fire hose nozzles, must comply with 46 CFR 108.425 in lieu of the paragraphs 9.7.20 and 9.7.21 of reference (f). Fixed low expansion foam systems installed on the cargo decks must comply with 46 CFR 34.20 and acceptance is also contingent upon the review of the proposed modifications of the system to account for the fire suppression of both the process modules and the cargo tanks under the modules. AFFF hose reel stations with non-collapsible hose that are USCG approved for fire main service may be substituted for collapsible hoses on open deck fire hydrants, and in enclosed columns, pontoons and machinery spaces.

(36) Portable and semi-portable fire extinguishers must be USCG type approved and comply with 46 CFR 108.491 through 108.496.

(37) Fire-fighter’s outfits and self contained breathing apparatus must comply with 46 CFR 108.497.

(38) Means of escape must comply with paragraph 9.4 of the reference (f) and 46 CFR 108.151. To satisfy paragraph 9.4.5 of reference (f) at least one escape route from accommodation areas to a primary means of escape must provide protection for escaping personnel from fires, blowouts, and explosions. Solid steel decking must be used in this escape route. Additionally, all doors in escape routes must open in the direction of travel to the embarkation stations and survival craft. Any doors with provisions for locking must comply with SOLAS regulation II-2/13.3.2.6.

(39) Fire protection equipment must be marked in accordance with 46 CFR 108.621 through 108.635 and 108.637.

(40) Exterior boundaries of all normally occupied deckhouses or temporarily installed modular buildings that are normally occupied, including overhanging decks that face process areas, wellheads, produced oil storage tanks and similar hydrocarbon hazards must meet minimum H-60 rating standards, and extend on the sides of any such structures for a minimum distance of 10 feet. H-60 test methods must be in accordance with:

(a) Reference (gg), test method C, Tests of Fire-Containment Capability or Walls; or

(b) Annex 1, Part 3 of reference (hh), using the H-class time-temperature curve, where the furnace temperature reaches 815°C after 3 minutes, 1010°C after 5 minutes, and is maintained between 1010°C and 1180°C for the duration of the test.

(41) Any escape routes, lifeboat embarkation stations, fire extinguishing equipment and vital systems needed for power management must be protected from any fired vessels such as glycol re-boilers and hot oil heaters by barriers with a minimum A-0 rating.

(42) General arrangement of process areas and segregation of fuel and ignition sources must be in accordance with reference (ii).


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General Emergency Alarm Systems (43) The general emergency alarm system for the FOI/FPSO must comply with the following:

(a) Each general emergency alarm system to signal personnel to their emergency stations must be audible throughout the FOI/FPSO and must be distinct and unambiguous from other audible alarm signals. The general emergency alarm must continue to function after it has initiated until it is manually turned off or is temporarily interrupted by a message on the public address system.

(b) The general emergency alarm must:

(i) Be audible in all permanent, temporary, and crew accommodation spaces, and in all crew working spaces where persons may be maintaining, repairing, or operating equipment, stowing or drawing store of equipment, or transiting, such as public spaces; work spaces; machinery spaces; workshops; galleys; emergency fire pump rooms; bow thruster rooms; storage areas for paint, rope, and other stores; and under deck passageways and open decks;

(ii) The alarm system must provide a minimum sound pressure levels for the general emergency alarm tone specified in chapter VII, section 7.2.1.2 and 7.2.1.3 of reference (jj).

(c) Wiring materials for the general emergency alarm system must meet the construction and testing requirements for marine shipboard cables.

(d) Manually operated contact makers must be installed in the following locations:

(i) In the main control room, if provided;

(ii) At the drilling console on a unit with a drilling package;

(iii) At the feeder distribution panel;

(iv) In the navigation bridge, if there is a navigation bridge; and

(v) In a routinely occupied space that is as far as practicable from all other activation locations.

(e) The general emergency alarm system must have at least two branch supply circuits for the general emergency alarm system. One supply must be from the main switchboard and the other must be from an emergency source of power that meets SOLAS II-1/42 or II-1/43 or reference (f) (as applicable). An automatic change-over switch from these feeders must be located, or adjacent to, the feeder distribution panel. The emergency power source may be a battery, provided that has the capacity for at least 30 minutes of continuous operation and 18 hours in standby, and a battery charger that is charged from the emergency switchboard.

(f) The general emergency alarm system feeders and branch circuits must have a feeder distribution panel to divide the system into the necessary number of zone feeders, except where, because of the arrangement of the FOI/FPSO, only one zone feeder is necessary.

(g) General emergency alarm feeders and branch circuit cables must be in passageways and must not be in staterooms, lockers, galleys, machinery spaces, or other enclosed spaces, unless it is necessary to supply general emergency alarm signal in those spaces.

(h) The general emergency alarm must have flashing lights or rotating beacons installed in locations, where the general emergency alarm signal cannot be heard due to high ambient noise, and must meet the requirements of section 6 and equipment marked in colors specified in reference (kk).


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(i) Each general emergency alarm signal and/or alarm sounding device on the system must be marked with visual indicators that meet the requirements of reference (kk).

Obstruction Lights and Warning Devices (44) The FOI/FPSO must meet the applicable requirements for obstruction lights and warning devices in 33 CFR part 67.

Catwalks, Floors, and Openings (45) The unprotected perimeter of all catwalks, floor or deck areas, and openings on FOIs must be rimmed with guardrails or wire mesh fences, at least 42 inches high. Guardrails used on FOIs must comply with the requirements in 33 CFR 143.110.

Helicopter Landing Facilities (46) Helicopter landing facilities, on all FOI/FPSOs, must be designed in accordance with one of the following standards:

(a) The requirements in Chapter 13 of reference (f); or

(b) The requirements in 46 CFR 108.231 through 46 CFR 108.241.

(c) In addition to meeting the requirements in paragraph (46)(a) or (46)(b) above, aluminum helidecks must also meet the provisions of NVIC 9-97, CH-1, “Guide to Structural Fire Protection” in Enclosure 1, Section 5.2.

Stairways (47) Stairways on the FOI/FPSO must have at least two courses of rails. The top course must serve as a handrail and be at least 36 inches above the front tread.

Accommodation spaces (48) Accommodation spaces in the FOI/FPSO must comply with the requirements in 46 CFR 108.193 through 46 CFR 108.215.


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Enclosure (2): Requirements for FPSOs on the U.S. OCS CG-ENG Policy Letter No. 01-13 June 26, 2013 References: (a) IMO Specifications for the Design, Operation and Control of Crude Oil

Washing Systems adopted by resolution A.446(XI) and amended by resolution A.497(XII) and further amended by resolution A.897(21)

(b) ISO 15364:2007, “Ships and marine technology – Pressure/vacuum valves for cargo tanks”

(c) IMO Resolution A.1023(26), “Code for the Construction and Equipment of Mobile Offshore Drilling Units,” 2009 (2009 MODU Code)

(d) API RP 500, “Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Division I and Division 2”, 2012

(e) API RP 505, “Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Zone 0, Zone 1 and Zone 2”, 1998

For a floating production, storage, and offloading unit (FPSO) design, the requirements in this enclosure should be combined with the requirements in enclosure (1). Where the requirements of enclosures (1) and (2) differ for an FPSO, enclosure (2) takes precedence.

General (1) The FPSO must be classed by either the American Bureau of Shipping (ABS), Det Norske Veritas (DNV), or Lloyd’s Register (LR) and receive the following notations as applicable:

(a) ABS: A1 Floating Production, Storage and Offloading System (ship-type) (Disconnectable) AMS

(b) DNV: 1A1, Oil Production, Oil Storage, Oil Loading with additional notations applicable to the installation design

(c) LR: OI 100 AT Floating production and oil storage installation, with additional notations applicable to the installation design and operating criteria. If a notation applicable to mobile units is required, the designation “OI” will be replaced with “OU” and other notations modified as necessary.

Produced Oil Storage and Handling (2) The following requirements apply:

(a) Ballast water must not be carried in any fuel tanks.

(b) Ballast water must not be carried in any produced oil storage tanks, except when considered necessary for the safety of the FPSO in a severe weather emergency.

(c) Ballast tank capacity must be sufficient to meet the following draft and trim requirements with the produced oil storage tanks empty:

(i) The molded draft amidship (dm) in meters, without taking into account any hull deformation, must not be less than dm = 2.0 + 0.02L.

(ii) The drafts at the forward and after perpendiculars must correspond to that determined by the draft amidship in paragraph (c)(i), in association with a trim by the stern of no more than 0.015L.


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(iii) If a self-propelled FPSO employs a disconnectable system, the minimum draft at the after perpendicular must be sufficient to obtain full immersion of the propeller.

(d) Double hull requirements in 33 CFR 157.10d(c)(1)(i) and 33 CFR 157.10d(c)(2)(i), and the requirements in 33 CFR 157.10d(c)(3) and 33 CFR 157.11(g)(2) must be met.

(e) The aggregate volume of the double hull tanks, forepeak tanks, and afterpeak tanks must not be less than the ballast tank capacity required in paragraph (c).

(f) Oil must not be stored in any tank extending forward of the collision bulkhead except independent fuel oil tanks that must serve adjacent deck equipment that cannot be located further aft. Such tanks must be as small and as far aft as practicable.

(g) Oil must not be stored in any tank closer to the stern than 2.0 meters.

(h) The FPSO must comply with MARPOL Annex I regulations 23, 29 and 30 (paragraphs 1, 4 and 7 only).

(i) The FPSO must comply with SOLAS regulation II-2/4 (paragraphs 5.2, 5.3, 5.4, 5.9 and 5.10 only), and regulation II-2/9 (paragraphs 2.4.2.5 and 2.4.2.6 only).

(j) Irrespective of its deadweight, a fixed inert gas system must be installed that complies with the requirements in SOLAS regulation II-2/4.5.5, except that a dry type water seal must not be used.

(k) If crude oil washing equipment is installed, it must comply with the crude oil washing system safety requirements in reference (a).

(l) If an oil piping system interconnects produced oil storage tanks, the system must have valves to separate the tanks from each other.

(m) Ballast and produced oil piping systems must meet the requirements in 33 CFR 157.11(g)(1).

(n) Pressure vacuum relief valves must meet the requirements in 46 CFR 162.017 or reference (b).

(o) Each produced oil transfer hose must comply with the requirements in 33 CFR 154.500 and 33 CFR 156.170.

(p) The produced oil pumping/piping systems must be arranged independently from all other systems. Recovered oil transfer pumps and piping (including fill, discharge, vent, and sounding piping) must not be located in or pass through any accommodation, service or machinery spaces.

Machinery and Electrical Installations (3) Machinery and electrical installations must comply with the applicable cargo ship regulations in SOLAS, Chapter II-1, Parts C, D and E. In addition, the following requirements apply:

(a) The FPSO must comply with the arrangement requirements in SOLAS regulation II-2/4.5.1, except that a power generation unit may be located above the produced oil storage tanks if:

(i) The power generation unit and all related systems are located outside of the hazardous area locations;


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(ii) The power generation unit exhaust pipes do not emit sparks or discharge exhaust gas in the direction of a hazardous area;

(iii) The power generation unit is enclosed in A-class divisions if used for emergency shipboard power service or is required to supply loads necessary to maintain or restore the propulsion plant, including thrusters; and

(iv) A Coast Guard approved fixed fire extinguishing system is installed for the power generation unit enclosure.

(4) In addition to regulations 42.4 and 43.2, Chapter II-1 SOLAS, and loads required as per design/operational requirements, the following additional loads must be arranged so that they can be energized by the emergency generator:

(a) Essential marine control, alarm, and monitoring systems;

(b) The marine manual and automatic safety shutdown systems;

(c) The automatic electric power management system;

(d) The control system for the position thrusters for the thruster-assisted mooring system, if installed;

(e) Each critical production/process control/import/export, alarm, and monitoring system necessary to prevent a process upset;

(f) A process safety control system to shut down the flow of hydrocarbon from all wells and process systems;

(g) Control systems for all equipment that is required for emergency operations;

(h) The diving equipment, if equipped, that is dependent on the unit for its power source;

(i) Quick disconnect systems that are used to stop all process flow to the floating installation automatically, without leaks from process fluids.

(5) In addition to the emergency generator, the emergency loads in paragraph (4) above must have a temporary or transitional supply source that provides power for at least 30 minutes.

(6) If self propelled: the emergency generator is used for part or all of the electric power necessary to start the installation’s electric and propulsion plants (via a bus-tie to the main switchboard from a dead-ship condition), the emergency power source or emergency generator must be capable of providing power to all the emergency loads, in addition to the power used to start the installation’s electric and propulsion plants. If arranged for feedback operation, the emergency bus-tie to the main switchboard must open automatically upon overload of the emergency generator before the emergency generator is tripped off the line due to the overload.

(7) The above design and engineering standards in paragraph (3) of this section apply to the industrial power system when the system is connected to the ship service power system.

Criteria for Emergency Disconnect (8) The FPSO must be able to detect conditions that require disconnection from the turret, such as:

(a) Current or predicted environmental conditions in excess of the FPSO design capabilities;

(b) Exceeding turret and disconnect systems’ operational limits;


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(c) Exceeding vessel motion operational limits.

Stability (9) The FPSO must comply with the requirements in MARPOL Annex I regulations 27 and 28 (with the exception of paragraph 6), and the requirements in sections 3.6 and 3.7 of reference (c), that are applicable to surface units. In applying the requirements from reference (c):

(a) The term “Administration” means the Commandant (CG-ENG), U.S. Coast Guard.

(b) The term “should” means “must”.

(c) The term “recommendations” means “requirements”.

(10) Any FPSO that employs a disconnectable system for severe weather evasion must demonstrate that the disconnect procedure does not jeopardize the stability.

Hazardous Locations (11) In lieu of using the criteria of references (i) and (bb) of enclosure (1) to identify hazardous locations, paragraphs (12) and (13) of this enclosure must be used. Except as noted in paragraphs (14) and (15) of this enclosure, electrical installations in hazardous locations must meet paragraphs (26) through (30) of enclosure (1).

(12) Hazardous location classification of storage and handling locations for hydrocarbons with closed-cup flashpoints not exceeding 140°F (60°C).

(a) The following are Zone 0 locations:

(i) Enclosed areas containing devices handling hydrocarbons, such as hydrocarbon handling or pump rooms;

(ii) The interiors of hydrocarbon storage tanks, slop tanks, any pipework for pressure relief or other venting systems for hydrocarbon and slop tanks, pipes, and equipment containing the hydrocarbon or developing flammable gases or vapors;

(iii) Areas on an open deck, or a semi-enclosed space on an open deck, within 0.5 meters of any hydrocarbon storage tank outlet, hydrocarbon gas or vapor outlet, ullage opening, sounding pipe, hydrocarbon tank opening for pressure release, or hydrocarbon storage tank pressure or vacuum valve provided to permit the flow of small volumes of gas or vapor mixtures caused by thermal variation;

(iv) Areas on an open deck, or semi-enclosed spaces on an open deck, within 0.5 meters of any hydrocarbon handling or pump room entrance, or hydrocarbon ventilation handling or pump room ventilation inlet or outlet;

(v) Areas in the vicinity of any hydrocarbon vent outlet for the free flow of large volumes of vapor mixtures during hydrocarbon loading and discharging of storage tanks, within a vertical cylinder of unlimited height, of 1 meter radius centered upon the vent outlet, and within a hemisphere of 1-meter radius below the vent outlet; and

(vi) Areas in the vicinity of any hydrocarbon high-velocity vent outlet during hydrocarbon loading and discharging of storage tanks, within a vertical cylinder of unlimited height, of 0.5 meters radius centered upon the vent outlet, and within a hemisphere of 0.5 meters radius below the vent outlet.


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(b) The following are Zone 1 locations:

(i) Areas on an open deck, or a semi-enclosed space on an open deck, that are 2.5 meters beyond the Zone 0 areas cited in paragraphs (12)(a)(iii) and (12)(a)(iv) of this section;

(ii) Areas on an open deck, or a semi-enclosed space on an open deck, that are within 3 meters of any hydrocarbon manifold valve, hydrocarbon valve, hydrocarbon pipe flange, hydrocarbon tank hatches, sight ports, tank cleaning openings, and openings into cofferdams or other Zone 1 spaces;

(iii) Regardless of the level of natural ventilation, areas on an open deck above the tank top of each hydrocarbon tank extending out 3 meters beyond the tank top boundaries of each hydrocarbon tank, up to a height of 2.4 meters above the deck;

(iv) Areas on open deck within spillage coamings surrounding hydrocarbon manifold valves extending 3 meters beyond the boundaries of the spillage coamings, up to a height of 1.2 meters;

(v) A void space or an enclosed space, including cofferdams and permanent (e.g., segregated) ballast tanks, immediately above, below, or adjacent to an integral hydrocarbon storage tank;

(vi) A hold space containing an independent hydrocarbon storage tank;

(vii) Compartments for hydrocarbon transfer hoses;

(viii) Enclosed or semi-enclosed spaces in which pipes containing hydrocarbons are located;

(ix) Areas 7.5 meters beyond the cylinder and 7.5 meters beyond the hemisphere of the Zone 0 hazardous areas cited in paragraph (12)(a)(v) of this section; and

(x) Areas 5.5 meters beyond the cylinder and 5.5 meters beyond the hemisphere of the Zone 0 hazardous areas cited in paragraph (12)(a)(vi) of this section;

(c) The following are Zone 2 locations:

(i) Areas on an open deck, or a semi-enclosed space on an open deck, that are 1.5 meters beyond the Zone 1 areas cited in paragraphs (12)(b)(i), (12)(b)(ii), (12)(b)(iii), and (12)(b)(iv) of this section;

(ii) Areas 1.5 meters beyond the cylinder and 1.5 meters beyond the hemisphere of the Zone 1 hazardous areas cited in paragraph (12)(b)(ix) of this section;

(iii) Areas 4 meters beyond the cylinder and 4 meters beyond the hemisphere of the Zone 1 hazardous areas cited in paragraph (12)(b)(x) of this section; and

(iv) Enclosed spaces beyond the open deck areas cited in paragraph (12)(b)(iii) which are below the level of the main deck, and have an opening onto the main deck or at a level less than 0.5 meters above the main deck, unless the entrances to such spaces, including ventilation inlets and outlets, are situated at least 5 meters from the closest integral hydrocarbon tank bulkhead and at least 10 meters measured horizontally from any integral hydrocarbon tank outlet or gas or vapor outlet; and the spaces are mechanically ventilated.


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No. 01-13 June 26, 2013 (13) Hazardous location classification of heated combustible hydrocarbon storage and handling locations.

(a) This section applies to storage and handling locations for hydrocarbons with closed-cup flashpoints exceeding 60°C (140°F).

(b) The interiors of storage tanks and integral tanks containing hydrocarbons with closed-cup flashpoints of 60 °C (140°F) or higher and heated to within 15 °C (59°F) of its flashpoint are considered Zone 0. The hazardous locations in paragraphs (12)(a)(iii), (12)(a)(iv), (12)(b)(i), (12)(b)(ii) and (12)(c)(i) apply.

(14) Requirements for enclosed locations containing devices handling hydrocarbons with closed-cup flashpoints not exceeding 60°C (140°F).

(a) Hydrocarbon pumps must be isolated from all sources of vapor ignition by gastight bulkheads. The gastight bulkhead between the pump room and the pump-engine compartment may be pierced by fixed lights, drive shaft, and pump-engine control rods, provided that the shafts and rods are fitted with stuffing boxes where they pass through the gastight bulkheads. The access to a hydrocarbon pump enclosed room must be from the open deck.

(b) The hydrocarbon pumping/piping systems must be arranged independently from all other systems. Hydrocarbon transfer pumps and piping (including fill, discharge, vent, and sounding piping) must not be located in or pass through any accommodation, service or machinery locations.

(c) Fixed lights in hydrocarbon pump enclosed locations must be lighted through fixed glass lenses in the bulkhead or overhead. Each fixed glass lens must be wire-inserted glass that is at least 6.35 mm (0.25 inches) thick and arranged to maintain the watertight and gastight integrity of the structure. The fixed glass lens may form a part of a listing fixture if the following are met:

(i) There is no access to the interior of the fixture from the hydrocarbon pump or handling room.

(ii) The fixture is vented to the engine room or a similar non-hazardous location.

(iii) The fixture is wired from outside the cargo handling room.

(iv) The surface temperature of the fixed glass lens on the hydrocarbon pump or handling room, based on an ambient temperature of 40°C, must not be higher than 180°C.

(d) An enclosed hydrocarbon handling location that precludes the lighting arrangement or where the lighting arrangement does not give the required illumination in paragraph (13)(c) above, must have explosion proof or, flameproof (Ex “d”), or flameproof-increased safety (Ex “de”) lighting fixtures.

(15) In lieu of meeting paragraphs (12) through (14) the FPSO may meet 46 CFR 111.105-29 and 31.

Production Processing/Support Systems and Associated Venting (16) Hazardous area classification of production processing and process systems, venting, production support systems, and auxiliary equipment for processing hydrocarbon liquid and gas mixtures from wells or other sources, must meet the applicable requirements and classification of


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No. 01-13 June 26, 2013 hazardous areas in paragraphs (11), (12) and (15), and the applicable appendixes of references (d) and (e).

Hazardous Areas for Hydrocarbon Product Swivels, Turrets, and Yokes (17) The hazardous location classification of hydrocarbon product swivels, internal or external turrets, yokes, and associated electrical apparatus or equipment must meet the following:

(a) The internals of tanks, swivels or pipes containing hydrocarbons are considered Zone 0 locations.

(b) An enclosed location where a hydrocarbon product swivel is installed is considered a Zone 1 location.

(c) In a non-enclosed location, the area within 3 meters (10 feet) of a hydrocarbon product swivel is considered a Zone 2 location.

(18) The hydrocarbon product electrical swivel, must be tested and listed or certified by a Coast Guard accepted independent laboratory in accordance with 46 CFR Part 159.

(19) The current rating of the hydrocarbon product electrical swivel (slip ring) must be adequate to carry the full-load current of the equipment supplied.

Firefighting and Fire Protection (20) Structural fire protection boundaries and materials must comply with SOLAS Cargo ship Method 1C requirements. All structural fire protection materials must be Coast Guard type approved.

(21) Fire-fighting and fire-detection equipment, except for the fire main system, must comply with SOLAS Cargo ship requirements. The fire main system and all associated components, including, but not limited to, fire pumps, fire hoses, fire hydrants, and fire hose nozzles, must comply with 46 CFR 95.10. Fixed low expansion foam systems installed on the cargo decks must comply with 46 CFR 34.20 and acceptance is also contingent upon the review of the proposed modifications of the system to account for the fire suppression of both the process modules and the cargo tanks under the modules. AFFF hose reel stations with non-collapsible hose that are Coast Guard approved for fire main service may be substituted for collapsible hoses on open deck locations, and in enclosed columns, pontoons and machinery spaces. All equipment must be Coast Guard type approved.

(22) Fire-fighter’s outfits and self contained breathing apparatus must comply with 46 CFR 96.35.

(23) Produced oil pump rooms must be separated from adjacent normally occupied rooms by A-60 barriers, except that bulkheads and decks separating pump rooms from machinery spaces of category and other machinery spaces may be reduced to A-0. Such bulkheads may be penetrated by pump shaft glands, provided that gas-tight seals are provided to prevent seepage of flammable vapors into the machinery space.

(24) If applicable, wellheads (i.e. production areas containing oil and gas risers, export lines and associated shut down valves) with a maximum shut-in pressure exceeding 600 psi must be enclosed within minimum A-0 barriers to protect any escape routes, lifeboat embarkation stations, fire extinguishing equipment and vital systems needed for power management.


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No. 01-13 June 26, 2013 Catwalks, Floors, and Openings (25) The unprotected perimeter of all catwalks, floor or deck areas, and openings must be rimmed with guardrails or wire mesh fences, at least 1 meter (39 inches) high. If guardrails are used:

(a) They must comply with the requirements in 46 CFR 108.217 through 46 CFR 108.223;

(b) If a toe board is installed, one of the intermediate courses may be omitted and the other course placed approximately halfway between the top of the toe board and the top course.


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DNVGL-SI-0003: Verification for compliance with United States … · 2015. 11. 2. · Statutory interpretations DNVGL-SI-0003 – Edition July 2015 Page 3 Verification for compliance