dnvgl-se-0003 verification for compliance with …the service specifications lay down procedural...

SERVICE SPECIFICATION

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.

DNVGL-SE-0003:2014-04

Verification for compliance with United States regulations on the outer continental shelf

© DNV GL AS 2014-04

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

This service document has been prepared based on available knowledge, technology and/or information at the time of issuance of this document, and is believedto reflect the best of contemporary technology. The use of this document by others than DNV GL is at the user's sole risk. DNV GL does not accept any liabilityor responsibility for loss or damages resulting from any use of this document.

FOREWORDThe service specifications lay down procedural requirements for obtaining and retaining certificates andother conformity statements to the objects in question.

Service specification – DNVGL-SE-0003:2014-04


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entCHANGES – CURRENT

GeneralThis is a new document.

On 12 September 2013, DNV and GL merged to form DNV GL Group. On the 25th of November 2013 Det

Norske Veritas AS became the 100% shareholder of Germanischer Loyd SE, the parent company of the GL

Group, and on 27th November 2013 Det Norske Veritas AS, company registration number 945 748 931,

changed its name to DNV GL AS. For further information, see www.dnvgl.com. Any reference in this

document to “Det Norske Veritas AS”, “Det Norske Veritas”, “DNV”, “GL”, “Germanischer Loyd SE”, “GL

Group” or any other legal entity name or trading name presently owned by the DNV GL Group shall therefore

also be considered a reference to “DNV GL AS”.

www.dnvgl.com



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ntsCONTENTS

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

CH. 1 PRINCIPLES AND PROCEDURES ................................. 6

Sec.1 Introduction.................................................................................................. 6

1 Introduction .............................................................................................6

2 General .....................................................................................................6

2.1 Objective...........................................................................................6

2.2 Scope ...............................................................................................6

2.3 Structure...........................................................................................6

3 Definitions ................................................................................................7

3.1 Verbal forms ......................................................................................7

3.2 DNV GL definitions..............................................................................7

4 References................................................................................................8

4.1 General ............................................................................................8

5 Abbreviations .........................................................................................10

Sec.2 Regulatory basis and legal provisions ....................................................... 11

1 Regulatory basis principles.....................................................................11

1.1 Jurisdictions.....................................................................................11

1.2 OCS facilities....................................................................................11

1.3 Code of federal regulations ................................................................11

1.4 Alternate design and equipment standards...........................................12

1.5 Regulatory considerations for FOIs and FPSOs .....................................12

1.6 Equivalent design and construction considerations ................................12

2 Classification principles ..........................................................................13

2.1 General ...........................................................................................13

2.2 Classification of FOIs and FPSOs including FSOs....................................13

2.3 Class notations.................................................................................13

2.4 Main character of class ......................................................................13

2.5 Basic design notations.......................................................................13

2.6 Service notations..............................................................................14

3 (US)-notation .........................................................................................14

3.1 General ...........................................................................................14

3.2 Compliance matrix for OCS ................................................................14

CH. 2 DESIGN AND CONSTRUCTION PROVISIONS............. 16

Sec.1 Introduction................................................................................................ 16

1 General ...................................................................................................16

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

Sec.2 Floating offshore installations..................................................................... 17

1 Introduction ...........................................................................................17

1.1 Application.......................................................................................17

1.2 Class notations.................................................................................17

2 Compliance matrix..................................................................................17

2.1 Application.......................................................................................17

2.2 Compliance matrix for floating offshore installations with (US) Notation ....17



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ntsSec.3 Floating storage units and floating production, storage and

offloading units ........................................................................................... 21

1 Introduction ...........................................................................................211.1 Application.......................................................................................211.2 Class notations.................................................................................21

2 Compliance matrix..................................................................................212.1 Application.......................................................................................212.2 Compliance basis for FSO and FPSO Unit (US) .......................................21

Sec.4 Equivalencies and other design considerations (informative) .................... 24

1 General ...................................................................................................24

2 Passive ballast system:...........................................................................24

3 External impact load on hull ...................................................................24

4 Fire protection boundaries......................................................................24

5 Platform verification program by a certified verification agent ..............245.1 General ...........................................................................................245.2 Scope of assessment.........................................................................24

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



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Section 1CHAPTER 1 PRINCIPLES AND PROCEDURES

SECTION 1 INTRODUCTION

1 Introduction

DNV 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 Objective

This 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 Scope

2.2.1 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.

---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---

2.3 Structure

This 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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Section 13 Definitions

3.1 Verbal forms

3.2 DNV GL definitions

3.2.1 Approval or approved: Denotes acceptance by DNV GL of documentation showing design solutions,

arrangements and/or equipment to comply with the rules.

3.2.2 Assessment: An act of assessing, appraising or evaluating a condition of a product, process or

system.

3.2.3 Certificate: A document confirming compliance with the Society’s rules or with other rules and

regulations for which the Society has been authorized to act.

3.2.4 Certification: a service confirming compliance with applicable requirements on the date that the

survey was completed.

3.2.5 Certification 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,

3.2.6 Class: Class is assigned to and will be retained by units complying with applicable requirements of

the Society’s rules.

3.2.7 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.

3.2.8 Classification certificate: Issued upon assignment or renewal of class. Its validity is five years

subject to successful completion of annual and intermediate surveys.

3.2.9 Client: The party having requested classification or having assumed ownership of a classed offshore

unit or installation. In cases where owners have authorised another party to operate the unit or installation

on their behalf, such party is regarded as the client.

3.2.10 Contract: The specific agreement between DNV GL and the customer. It 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.

3.2.11 Customer: Signifies the party who has requested the Society’s service.

3.2.12 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.

3.2.13 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.

3.2.14 Offshore installation: A collective term to cover any construction, buoyant or non-buoyant,

designed and built for installation at a particular offshore location.

Table 1 Verbal forms

Term Definition

Shall 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.



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3.2.15 Owner: In the context of this Offshore Service Specification, the Owner is defined as the party

responsible for the offshore unit or installation including its operation and safety.

3.2.16 Recognised classification society: A classification society which is a full or associate member of

IACS.

4 References

4.1 General

4.1.1 This Offshore Service Specification 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.

4.1.2 Legacy DNV documents referred to are given in Table 2.

4.1.3 Other standards and regulatory basis references for compliance as referred to herein are given in

Table 3. Only parts referred to in the main text of this document or CG-ENG Policy Letter No. 01-13 are

applicable.

Table 2 DNV GL References

Reference Title

DNV-OSS-102 Rules for Classification of Floating Production, Storage and Loading Units

DNV-OS-A101 Safety Principles and Arrangements

DNV-OS-B101 Metallic Materials

DNV-OS-C102 Structural Design of Offshore Ships

DNV-OS-C103 Structural Design of Column-Stabilised Units (LRFD method)

DNV-OS-C104 Structural Design of Self-Elevating Units (LRFD method)

DNV-OS-C105 Structural Design of TLPs (LRFD method)

DNV-OS-C106 DNV-OS-C106 Structural Design of Deep Draught Floating Units (LRFD method)

DNV-OS-C201 Structural Design of Offshore Units (WSD method)

DNV-OS-C301 Stability and Watertight Integrity

DNV-OS-C401 Fabrication and Testing of Offshore Structures

DNV-OS-D101 Marine and Machinery Systems and Equipment

DNV-OS-D201 Electrical Installations

DNV-OS-D202 Automation, Safety, and Telecommunication Systems

DNV-OS-D301 Fire Protection

DNV-OS-E201 Oil and Gas Processing Systems

DNV-OS-E301 Position Mooring

DNV-OS-E401 Helicopter Decks

Table 3 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



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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

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

Table 3 Other references (Continued)

Reference Title



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Guidance note:

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


5 AbbreviationsThe abbreviations given in Table 4 are used in this document.

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

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 Mobile

Offshore 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 4 Abbreviations

Abbreviation Full Name

BSEE Bureau of Safety and Environmental Enforcement

CFR Code of Federal Regulations

CVA Certified Verification Agent

DHS 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

OSS Offshore Service Specification

NVIC Navigation and Vessel Inspection Circular

USCG United States Coast Guard

Table 3 Other references (Continued)

Reference Title



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Section 2SECTION 2 REGULATORY BASIS AND LEGAL PROVISIONS

1 Regulatory basis principles

1.1 Jurisdictions

1.1.1 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 Outer Continental Shelf (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, this OSS 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 OCS facilities

Under 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 regulations

Commercial 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 standards

1.4.1 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. The Coast Guard 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 App.A.


1.5 Regulatory considerations for FOIs and FPSOs 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 OSS 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 considerationsUS Coast Guard 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 Chapter 2 Sec.4.

Table 1 Regulatory subchapters applicable to specific units

CFR Title Subchapter Applicability

33 N Outer Continental Shelf 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 General

2.1.1 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 FOIs and FPSOs including FSOs

The 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 service specification DNV-OSS-102 “Rules for Classificaton of Floating Prodcution, Storage and Loading Units” for details on

classification principles, scope, Notations and procedures for classification


2.3 Class notations

Classed 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 class

2.4.1 The notation 1A1 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 notations

The 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 General

3.1.1 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 OSS 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 DNV OSS-101, Ch. 2, Sec. 6 specifying the DRILL (US) notation.


3.2 Compliance matrix for OCSChapter 2 of this OSS 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 listed items in Ch.2 Sec.2

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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(for FOI) and 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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Section 1CHAPTER 2 DESIGN AND CONSTRUCTION

PROVISIONS

SECTION 1 INTRODUCTION

1 General

1.1 General

1.1.1 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 2SECTION 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 Application

2.1.1 Reference to be made to Ch.1 Sec.1 [4], Table 2 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 DescriptionUSCG 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 DNV-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


Letter, Encl. 1

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


Letter, Encl. 1

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)


Letter, Encl. 1



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Table 4 Electrical


Letter, Encl. 1

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 NoteThe 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 shall be alarmed in a manned space; and combustible gas detection installed.

Item 31

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)

http://cgmix.uscg.mil/eqlabs/



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Obstruction lights and

warning devices

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

Table 5 Lifesaving equipment


Letter, Encl. 1

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


Letter, Encl. 1

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 46

CFR 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)


Letter, Encl. 1



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Section 3SECTION 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 1A1 Storage Unit POSMOOR

OFFLOADING.

— The FPSO unit is classed with DNV GL with minimum class notations 1A1 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 shall be applied as for FPSOs, but without the production related

requirements.


2 Compliance matrix

2.1 Application

2.1.1 Reference to be made to Ch.1 Sec.1 [4], Table 2 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 FSO and FPSO 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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Section 3Table 1 Structures and stability


Letter, Encl. 2

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


Letter, Encl. 2

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


Letter, Encl. 2

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


Letter, Encl. 2

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 11refer

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


Letter, Encl. 2

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

http://cgmix.uscg.mil/eqlabs/



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Section 4SECTION 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 system:A 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 DNV-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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Section 4

— 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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AAPPENDIX A UNITED STATES COAST GUARD POLICY LETTER



DNV GL AS

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A



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A

Enclosure (1): Requirements for FOIs and FPSOs on the U.S. OCS CG-ENG Policy Letter

No. 01-13

June 26, 2013

1

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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AEnclosure (1): Requirements for FOIs and FPSOs on the U.S. OCS CG-ENG Policy Letter

No. 01-13

June 26, 2013

2

(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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No. 01-13

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3

(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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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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1

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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(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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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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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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