[Federal Register Volume 70, Number 137 (Tuesday, July 19, 2005)]
[Rules and Regulations]
[Pages 41556-41583]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 05-14038]



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Part IV





Department of the Interior





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Minerals Management Service



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30 CFR Part 250



Oil and Gas and Sulphur Operations in the Outer Continental Shelf 
(OCS)--Fixed and Floating Platforms and Structures and Documents 
Incorporated by Reference; Final Rule

  Federal Register / Vol. 70, No. 137 / Tuesday, July 19, 2005 / Rules 
and Regulations  

[[Page 41556]]


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DEPARTMENT OF THE INTERIOR

Minerals Management Service

30 CFR Part 250

RIN 1010-AC85


Oil and Gas and Sulphur Operations in the Outer Continental Shelf 
(OCS)--Fixed and Floating Platforms and Structures and Documents 
Incorporated by Reference

AGENCY: Minerals Management Service (MMS), Interior.

ACTION: Final rule.

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SUMMARY: This rule amends our regulations concerning platforms and 
structures to include coverage of floating offshore oil and gas 
production platforms. The rule also incorporates into MMS regulations a 
body of industry standards pertaining to floating production systems 
(FPSs). Limited changes are also made to regulations concerning oil and 
gas production safety systems; and pipelines and pipeline rights-of-
way. These changes are needed because of the rapid increase in 
deepwater exploration and development, and industry's increasing 
reliance on floating facilities for those activities. Incorporating the 
industry standards into MMS regulations will save the public the costs 
of developing separate, and possibly duplicative, government standards, 
and will streamline our procedures for reviewing and approving new 
offshore floating platforms.

DATES: This rule becomes effective on August 18, 2005. The 
incorporation by reference of the publications listed in the regulation 
is approved by the Director of the Federal Register as of August 18, 
2005.

FOR FURTHER INFORMATION CONTACT: Tommy Laurendine, Chief, Office of 
Structural and Technical Support (OSTS) at (504) 736-5709 or FAX (504) 
736-1747.

SUPPLEMENTARY INFORMATION: 

Background

    In response to the rapid increase in deepwater oil and gas 
exploration and development, on December 27, 2001, MMS published a 
proposed rule (66 FR 66851-66865) to amend subpart I of 30 CFR part 
250--Platforms and Structures. The proposed rule was designed to 
streamline the permitting process for floating platforms, and to 
incorporate by reference into MMS regulations industry standards 
addressing various aspects of FPSs.
    The remarkable increase in oil and gas exploration, development, 
and production in deepwater is due to the development of new 
technologies that (1) enable drilling and production in deeper waters; 
and (2) reduce operational costs and risks. In 1993, deepwater areas of 
the OCS (water depths greater than 1,000 feet, or 305 meters) accounted 
for approximately 12 percent of the oil and 2 percent of the gas of 
total offshore production. Discovery and development of deepwater 
fields began accelerating in 1994. By the end of 2004, deepwater areas 
accounted for about 62 percent of the oil and 32 percent of the gas of 
total offshore production.
    The productivity of the new deepwater wells is enormous compared to 
past wells in more shallow waters. Historically, offshore wells 
generally have produced between 200 and 300 barrels (bbls) of oil per 
day. However, some deepwater wells have produced at rates over 30,000 
bbls per day. Success in deepwater is evident in both the high 
production rates and sustained drilling for new discoveries announced 
each year. Exploratory drilling has moved into water depths of over 
10,000 feet (3,048 meters).
    By 2003, 27 permanent development platforms had been approved for 
installation in waters over 1,000 feet deep (305 meters). Of these, 16 
structures are floating platforms and 11 are fixed. All of these 
production platforms were approved on a case-by-case basis under 
existing regulations. However, it will streamline the permitting 
process for MMS to have a designated body of standards to specifically 
deal with the whole new class of floating production platforms. The 
offshore oil and gas industry has already developed its own body of 
standards because of the recognized need to streamline the design 
process for floating platform facilities and their subsystems. In 
addition to describing the primary platform facilities, the industry 
standards also govern production and pipeline risers, station-keeping 
and mooring systems, flexible pipelines, and hazards analysis.

Use of Industry Standards

    Under existing regulations, lessees and operators must use 
standards that are acceptable to MMS or they will not receive a permit 
to proceed with their development plans. If they do not choose to use 
standards already incorporated in the regulations, they have the option 
to use equivalent standards, provided they first obtain our approval.
    The 1996 National Technology Transfer and Advancement Act (NTTAA) 
(Pub. L. 104-113) directs Federal agencies to achieve greater reliance 
on voluntary standards and standards-developing organizations by 
participating in developing voluntary standards without dominating the 
process. The NTTAA encourages ``the use by Federal agencies of private 
sector standards, emphasizing where possible the use of standards 
developed by private, consensus organizations'' to eliminate 
``unnecessary duplication and complexity'' in developing standards and 
regulations. Office of Management and Budget (OMB) Circular A-119 
specifies the requirements for Federal agencies to implement the NTTAA. 
According to Circular A-119, agencies must use domestic and 
international voluntary consensus standards in their regulatory and 
procurement activities instead of government standards, unless they 
determine that the use of consensus standards would be inconsistent 
with applicable law or otherwise impractical.

The Purpose of This Rule

    The purpose of this rule is to incorporate into MMS regulations a 
body of industry standards that will enable MMS to more efficiently 
examine plans and issue permits for floating offshore platforms. Until 
this rulemaking, MMS regulations have not specifically addressed these 
facilities separately from fixed platforms. Therefore, this rule 
includes a complete rewrite of subpart I of 30 CFR part 250 to address 
floating platforms. This rule also modifies select sections of subpart 
J concerning the incorporation of American Petroleum Institute (API) 
Spec 17J and its use when installing pipelines constructed of unbonded 
flexible pipe. Select sections of subpart H are modified to reference 
API Recommended Practice (RP) 14J as well as API Spec 17J. 
Incorporating the voluntary industry standards will save the public the 
cost of developing government-specific standards.
    This rule will enhance the efficient exploration and development of 
the most promising new sources of United States oil and gas supplies in 
the deepwater areas of the OCS in two ways. First, it will provide more 
certainty to the lessees' design engineers so that they will know in 
advance what design criteria are acceptable to MMS. Second, it will 
enhance MMS engineers' abilities to review each new project to ensure 
structural integrity, operational and human safety, and environmental 
protection. The rule will establish a single body of standards on which 
each new project can be based, and result in streamlining the 
regulatory review process.

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    Incorporating the industry standards into MMS regulations will 
dictate that respondents comply with the requirements in the 
incorporated documents. This includes certified verification agent 
(CVA) reviews and hazards analyses. This will increase the number of 
CVA nominations and reports associated with the facilities, and require 
hazards analysis documentation for new floating platforms. (In some of 
the industry standards, the CVA is referred to as an independent 
verification agent (IVA)). Industry sources estimate that it will cost 
an average of $1.2 million to apply hazards analysis to each new 
floating production facility. Requiring the industry hazards analysis 
standard for all new deepwater floating production platforms will be 
the most costly element of this rule.
    With this final rule, MMS will incorporate seven API standards, and 
one American Welding Society (AWS) standard. MMS has actively 
participated in developing several of these standards, and believes 
that it would be difficult for the agency to write government 
regulations that would be either as technically detailed or as broad in 
scope as the standards. Incorporating these standards will help reduce 
the size and complexity of subpart I. Moreover, writing government 
regulations embodying these standards would be time-consuming and not 
economically efficient. Nor could it be done with the same level of 
expertise that was involved in the industry effort. MMS believes that 
it is entirely within the letter and spirit of the NTTAA that these 
voluntary industry standards be incorporated into our regulations. It 
is in the public interest that MMS adopt these standards.
    The eight industry standards to be incorporated are as follows:
    (1) API RP 2RD, Design of Risers for Floating Production Systems 
(FPSs) and Tension-Leg Platforms (TLPs), First Edition, June 1998, API 
Order No. G02RD1. This standard covers drilling, production, and 
pipeline risers associated with all FPSs, including spars, TLPs, column 
stabilized units (CSUs), and floating production, storage, and 
offloading units (FPSOs). Moreover, it deals with construction of 
flexible riser systems, which are not explicitly covered under current 
regulations.
    (2) API RP 2SK, Recommended Practice for Design and Analysis of 
Stationkeeping Systems for Floating Structures, Second Edition, 
December 1996, Effective Date: March 1, 1997, API Order No. G02SK2. 
This standard addresses station-keeping systems for floating platforms. 
These systems are not explicitly covered under current regulations.
    (3) API RP 2T, Recommended Practice for Planning, Designing, and 
Constructing Tension Leg Platforms, Second Edition, August 1997, API 
Order No. G02T02. Over the past 13 years, every application for a TLP 
installation in the OCS has relied on API RP 2T as the basis for its 
design. MMS has approved each of these applications on a case-by-case 
basis. There are now eight such installations in deepwater areas. For 
all practical purposes, API RP 2T is the de facto industry guideline on 
the design and construction of TLPs. In some areas, API RP 2T relies 
heavily on the analysis contained in API RP 2A, which is already 
incorporated into MMS regulations, particularly for environmental 
loading and foundation and anchoring factors. Considered by itself, API 
RP 2T imposes no new reporting requirements or third-party review 
requirements.
    (4) API RP 2FPS, Recommended Practice for Planning, Designing, and 
Constructing Floating Production Systems, First Edition, March 2001, 
API Order No. G2FPS1. API RP 2FPS serves as an ``umbrella document'' 
for all FPSs, except for TLPs (covered by API RP 2T). It incorporates 
as second-tier standards the requirements of API RP 2RD, API RP 2SK, 
API RP 14J, API Spec 17J, and those of other standards. Considered by 
itself, API RP 2FPS imposes no new reporting requirements or third-
party review requirements.
    (5) API RP 14J, Recommended Practice for Design and Hazards 
Analysis for Offshore Production Facilities, First Edition, September 
1, 1993, API Order No. 811-07200. Implementing this standard for all 
new deepwater floating production platforms will be the most costly 
element of this rule for industry. During 2000, a consensus was reached 
within the industry that the complexities and safety issues involved in 
FPSs warrant the application of this standard to all new FPSs, 
variously described as CSUs, TLPs, spars, and FPSOs, etc. Deepwater 
FPSs are the most complex systems on the OCS, and can include numerous 
production wells that flow at over 20,000 bbls per day. Therefore, MMS 
has concluded that new floating production facilities should be 
assigned the highest priority for conducting hazards analysis. This 
analysis should follow one or more of the methods described in API RP 
14J. Further, MMS believes it is most efficient to address potential 
safety and environmental hazards during the facility design phase. 
(Hazards analysis is much less useful and less cost-effective when 
applied to facilities that are already installed.) MMS will require an 
analysis of operational hazards to be included as an integral part of 
all Deepwater Operations Plans. Industry sources estimate that it will 
cost an average of $1.2 million to apply API RP 14J hazards analysis in 
the design of each new floating production facility.
    (6) API Specification (Spec) 17J, Specification for Unbonded 
Flexible Pipe, Second Edition, November 1999, Effective Date: July 1, 
2000, API Order No. G17J02. For several years MMS has been permitting 
remote subsea wells that use flexible pipe for deep sea production 
pipelines. API Spec 17J serves the interests of environmental 
protection and safety by providing guidance to both regulators and 
industry on the proper design and construction of flexible pipelines 
and flowlines. The industry projects that up to 50 percent of future 
deepwater wells will be remote subsea wells tied back to existing 
production platforms. There will also be an increasing number of 
shallow water subsea tie-backs. Therefore, this standard will be 
essential for future production operations.
    (7) American Welding Society, AWS D3.6M:1999, Specification for 
Underwater Welding (AWS D3.6M). MMS refers to this document every time 
we receive an application for an underwater welding repair. This 
document is analogous and complementary to the AWS Standard D1.1 
(Structural Welding Code-Steel), which is used for above-water welding. 
Both AWS D1.1 and AWS D1.4 (Structural Welding Code-Reinforcing Steel) 
have been incorporated into current MMS regulations for over 20 years. 
Further, MMS was a member of the subcommittee which developed AWS 
D3.6M. Underwater welding is used infrequently because of the expense 
involved in making such repairs. However, it has been used with great 
success over the years to solve several complex underwater repair 
problems, some in very deep water. MMS presently receives applications 
for underwater welding repairs on an infrequent basis, and AWS D3.6M is 
the primary document the industry follows for these purposes. This 
standard needs to be incorporated into our regulations because MMS 
anticipates a growing future need for underwater welding repairs. 
Considered by itself, AWS D3.6M imposes no new reporting requirements 
or third-party review requirements.
    (8) API RP 2SM, Recommended Practice for Design, Manufacture, 
Installation, and Maintenance of Synthetic Fiber Ropes for Offshore

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Mooring, First Edition, March 2001, API Order No. G02SM1. This is a new 
API RP that addresses an important component of offshore mooring 
systems. To date, synthetic fiber ropes have seen only limited use in 
the mooring systems of floating OCS platforms. Given the lack of long-
term experience with the use of synthetic fiber rope, API RP 2SM will 
serve as the primary reference document for use in approving 
applications which propose the use of such mooring systems. MMS was a 
member of the API subcommittee which developed API RP 2SM.

Regulatory Changes in Addition to Documents Incorporated by Reference

    This final rule totally reorganizes subpart I. Much of this 
reorganization is a result of MMS'' incorporation of the 21st edition 
of API RP 2A WSD, Recommended Practice for Planning, Designing and 
Constructing Fixed Offshore Platforms--Working Stress Design; Twenty-
First Edition, December 2000. This document was incorporated into MMS 
regulations, under separate rulemaking, on April 21, 2003. The 
incorporation allowed the elimination of much of the verbiage in the 
current subpart I regulations. Subpart I was further reorganized for 
clarity in this final rule.
    In addition to incorporating new industry documents, the revised 
subpart I adds language specific to FPSs. This language complements the 
December 16, 1998, Memorandum of Understanding (MOU) between MMS and 
the U.S. Coast Guard (USCG) that was published in the Federal Register 
on January 15, 1999 (64 FR 2660). The MOU describes our respective and 
overlapping responsibilities for regulating oil and gas activities on 
the OCS.

Discussion and Analysis of Comments

    Since the MMS first proposed this rule in December 2001, the 
location and numbering of many of the proposed regulatory sections has 
changed. In some cases, the changes were made to provide a more logical 
progression of the approval process. In other instances, proposed 
regulatory sections were moved and renumbered in this final rule to 
accommodate industry commentors' suggestions and additions to the 
proposed rules. The following table shows the final rule section 
numbers and the original proposed sections:

------------------------------------------------------------------------
        Final section of 30 CFR             Proposed section of 30 CFR
------------------------------------------------------------------------
Sec.   250.105.........................  Sec.   250.105
Sec.   250.198.........................  Sec.   250.198
Sec.   250.199.........................  New content not in proposed
                                          rule.
Proposed wording deleted from final      Sec.   250.204
 rule..
Sec.   250.800.........................  Sec.   250.800
Sec.   250.803.........................  Sec.   250.803
Sec.   250.900.........................  Sec.   250.900
Sec.   250.901.........................  Sec.   250.901
Sec.   250.902.........................  Sec.   250.917
Sec.   250.903.........................  Sec.   250.914
Sec.   250.904.........................  New content not in proposed
                                          rule.
Sec.   250.905.........................  Sec.   250.902
Sec.   250.906.........................  These requirements are not in
                                          the proposed rule.
                                          Requirements are from
                                          superseded regulations at Sec.
                                            250.909.
Sec.   250.907.........................  Sec.   250.915
Sec.   250.908.........................  Sec.   250.913
Sec.   250.909.........................  New content not in proposed
                                          rule.
Sec.   250.910.........................  Sec.   250.903
Sec.   250.911.........................  Sec.   250.904
Sec.   250.912.........................  Sec.   250.905 and Sec.
                                          250.907
Sec.   250.913.........................  Sec.   250.906
Sec.   250.914.........................  Sec.   250.908
Sec.   250.915.........................  Sec.   250.909
Sec.   250.916.........................  Sec.   250.910
Sec.   250.917.........................  Sec.   250.911
Sec.   250.918.........................  Sec.   250.912
Sec.   250.919.........................  Sec.   250.916
Sec.   250.920.........................  New content not in proposed
                                          rule.
Sec.   250.921.........................  Sec.   250.913; new content not
                                          in proposed rule.
Sec.   250.1002........................  Sec.   250.1002
Sec.   250.1007........................  Sec.   250.1007
------------------------------------------------------------------------

    Eight organizations submitted nine comments on the proposed 
rulemaking. Respondents included the American Bureau of Shipping (ABS); 
the Offshore Operator's Committee (OOC); Shell Exploration & Production 
Company (Shell), which commented twice; the Independent Petroleum 
Association of America (IPAA); the National Ocean Industries 
Association (NOIA); ChevronTexaco; Newfield Exploration Company 
(Newfield); and ATP Oil & Gas Corporation (ATP). These respondents 
raised a number of complex issues that are discussed immediately below.

Issue No. 1: Subpart I Should Be Broken Down To Separately Address 
Fixed and Floating Platforms

    ChevronTexaco commented as follows:

    There are significant differences between the two field 
development concepts covered by the proposed rewrite of Subpart I: 
The fixed production platform and the floating production platform. 
These differences include such things as number of deployments of 
each concept (a handful of floating production platforms versus 
thousands of shallow and deepwater fixed platforms); design, 
fabrication, and installation complexity; availability of design 
firms and CVA firms; and cost. ChevronTexaco suggests that forcing 
one Subpart to cover both concepts is extremely confusing, lacks 
focus on the unique characteristics of the individual concepts, and 
creates a document that is difficult to read. ChevronTexaco 
recommends two distinctly separate sections of CFR 250, either 
within Subpart I, or preferably in a new Subpart covering floating 
production platforms. Ultimately, ChevronTexaco feels

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this will provide for a clearer document by removing the ambiguities 
created by attempting to use wording originally written for fixed 
platform in rules for floating platforms.

    More specifically, OOC commented concerning proposed Sec.  250.902 
(Sec.  250.905 in the final rule):

    * * * The proposed regulations seems [sic] to assume that the 
design stages of a floating platform matches that for a fixed 
platform. For a fixed platform, in many cases the platform is fully 
designed and is then fabricated. For a floating platform, the design 
may be done in stages with fabrication commencing on various systems 
prior to the final design of other systems. This rule making does 
not seem to take this into account. We suggest that MMS investigate 
project sequencing and take that into account in the rulemaking.

    NOIA, Shell, and Newfield all provided similar comments on this 
question.
    The Platform Verification Program (PVP) described in this final 
rule at Sec. Sec.  250.909--250.918 (Sec. Sec.  250.903--250.912 in the 
proposed rule) covers all new floating production platforms and fixed 
platforms meeting one or more of five very specific criteria: (1) 
Platforms installed in water depths exceeding 400 feet (122 meters); 
(2) platforms having natural periods in excess of 3 seconds; (3) 
platforms installed in areas of unstable bottom conditions; (4) 
platforms having configurations and designs which have not previously 
been used or proven for use in the area; or (5) platforms installed in 
seismically active areas. The final rule language was changed to 
highlight the differences between the requirements for fixed and 
floating structures, but MMS concluded that separate subparts were not 
necessary.
    MMS agrees that the third-party justification procedures for fixed 
versus floating platforms can differ significantly based on 
certification procedures (e.g., use of a CVA versus a classification 
society) and the regulatory agencies involved (e.g., primarily MMS for 
a fixed platform, versus both MMS and USCG for a floating platform). 
The regulatory language for certification under the PVP is written 
broadly so that it can cover both fixed and floating platforms.
    The specific path to obtain approval for a particular platform will 
be based on the structural components and environmental conditions 
peculiar to that platform. It is quite conceivable that a floating 
platform will undergo more complicated design, CVA, and approval 
processes than a fixed platform. After evaluating the comments, MMS 
concluded that it is better to allow engineering staffs to use their 
judgment in obtaining the various approvals than to try to write a 
``cookbook'' regulation on the step-by-step certification or 
classification process for the design, fabrication, and installation of 
a hypothetical platform.
    New innovations in offshore platforms are constantly emerging, and 
it would be impractical, if not impossible, to cover all the 
permutations in design or construction that could eventually evolve. 
The fact that most of the deepwater facilities MMS has permitted are 
floating facilities provides convincing evidence in favor of staying 
flexible in adapting our regulations to various types of facilities.
    Some commentors believe it would be more confusing to separate 
subpart I into ``fixed'' and ``floating'' components, because of the 
many systems and technical problems which both types of platforms have 
in common. MMS agreed, and concluded that it was less satisfactory to 
have two subsections, because the greater specificity concerning either 
type of system could encourage more micro-managing in the final 
regulations. This could lead to less flexibility for innovative 
designs.
    OOC commented concerning proposed Sec.  250.901(a):

    * * * In lieu of listing the standards for fixed and floating 
platforms together, it would be clearer if three lists were given: 
1. Fixed only, 2. floating only and 3. fixed and floating. This 
would eliminate confusion on the applicability of standards such as 
14J which only new floating platforms have to meet.

    Shell and Newfield provided similar comments.
    MMS agreed, and has added a chart to the final regulation to reduce 
confusion about the applicability of referenced industry standards.

Issue No. 2: The Subpart I Revisions Do Not Follow the MOU Between MMS 
and USCG

    OOC, in commenting on proposed Sec.  250.904(e), now final Sec.  
250.911(g), asserted that ``The MOU gives the USCG sole jurisdiction 
over the structural design of ship-shaped hulls and superstructures.''
    MMS disagrees, and believes that this assertion oversimplifies the 
MOU provisions assigning MMS's and USCG's respective and joint 
responsibilities for offshore floating platforms. The specific items 
listed in proposed Sec.  250.903(b), and now in Sec.  250.910(b) of 
this final rule, include the following structures normally associated 
with floating platforms: (1) Drilling and production risers, and riser 
tensioning systems; (2) turrets and turret-and-hull interfaces; (3) 
foundations and anchoring systems; and (4) mooring or tethering 
systems. The following paragraphs address these items in their 
respective order with regard to the MOU between MMS and USCG.
    Section III of the MOU contains a table listing the agencies' 
respective and joint responsibilities associated with mobile offshore 
drilling units (MODUs) and fixed and floating OCS facilities. The table 
indicates in Item 2.c that, for all floating facilities, MMS is the 
lead agency for ``risers (drilling, production, and pipeline)'' and 
further notes that ``Some pipeline risers may be subject to the 
Research and Special Programs Administration's (RSPA) jurisdiction'' 
(64 FR 2662).
    Concerning ``turrets and turret-and-hull interfaces,'' Item 2.a of 
the MOU Section III table states as follows (64 FR 2661):

    USCG responsibilities for fabrication, installation, and 
inspection of floating units are found in 33 CFR Subchapter N. MMS 
responsibilities are found in 30 CFR Subpart I. USCG and MMS will 
each review the design of the turret and turret/hull interface 
structure for ship-shaped floating facilities. All other aspects of 
the design and fabrication of all ship-shape floating facilities 
will receive only USCG review. All design, fabrication, and 
installation activities of all non-ship-shape floating facilities 
will be reviewed by both agencies.

    Thus the MOU clearly shows that MMS and USCG both have 
responsibility for reviews of the turret and turret/hull interface 
structure of ship-shaped floating facilities.
    Concerning ``foundations and anchoring systems,'' Item 4.a of the 
MOU Section III table indicates that MMS is the lead agency for 
foundations for both fixed and floating facilities (64 FR 2662). The 
MOU was written this way because MMS is the Federal agency with the 
geotechnical expertise essential for reviewing and evaluating 
foundation integrity for fixed and floating production platforms.
    Closely related to ``foundations and anchoring systems'' are 
``mooring or tethering systems.'' Item 4.b of the MOU Section III table 
indicates that ``mooring and tethering systems'' for floating 
production facilities are under the joint responsibility of both MMS 
and USCG. USCG is unquestionably the agency with the expertise and 
responsibility for determining the safety and integrity of the hull of 
a ship-shaped FPS. However, the anchoring and mooring system for a 
ship-shaped FPS is inherently different from the anchoring and mooring 
system for a ship. The FPS must remain moored on location for many 
months, if not

[[Page 41560]]

years, and in such a way that oil and gas production systems will not 
be adversely affected by excessive movement. For Item 4.b, the MOU 
states that ``USCG is not responsible for site specific mooring 
analysis.'' The question of an effective and safe mooring system cannot 
be considered apart from the question of the sea bottom into which the 
mooring system is anchored. Again, MMS is the agency with the 
geotechnical expertise to determine whether the mooring system for a 
FPS is being anchored into stable sediments.
    OOC, commenting on proposed Sec.  250.901(a) stated:

    * * * In the current MOU between MMS and USCG, the agencies have 
joint jurisdiction over the structural design on non-ship shaped 
hulls. USCG treats floating production platforms as MODUs. In 46 CFR 
108.113, USCG requires each unit to meet the structural standards of 
the American Bureau of Shipping ``Rules for Building and Classing 
Offshore Mobile Drilling Units''. There is concern that there could 
be conflicts between the recommended practices and standards 
proposed for adoption in this rulemaking and the USCG structural 
requirements. Industry has not undertaken an exhaustive study to 
determine if conflicts exist. Further, it is confusing to industry 
to have joint jurisdiction over the same system, especially when the 
criteria is [sic] different. It is suggested that MMS and USCG work 
together and either adopt the same criteria for systems in which 
they have joint jurisdiction or that one agency clearly be given the 
lead jurisdiction for each system and move away from the joint 
jurisdiction where both agencies have to approve a system.

    Shell, NOIA, and Newfield expressed similar concerns.
    MMS believes that the respondents' concerns about coordination 
between MMS and USCG are overstated. MMS further believes that the 
procedures outlined in the new subpart I and the provisions of the MOU 
between MMS and USCG are sufficient to mitigate industry's concerns of 
duplicative and conflicting requirements between MMS and USCG. That 
said, conflicts cannot be entirely avoided. In the responsibilities 
section of the current MOU, three general classifications of facilities 
are identified (i.e., MODU, fixed facility, and floating facility). The 
lead agency for each system and sub-system is also identified.
    Since USCG reviews the general marine requirements for floating 
facilities from a ship perspective, and MMS reviews oil and gas 
operations on this facility from a platform perspective, it is not 
always possible to adopt the same criteria. However, the MOU requires 
the identified lead agency to coordinate with the other agency, as 
appropriate, and also requires that both agencies work together to 
develop necessary standards and to minimize duplicative and conflicting 
requirements whenever there are overlapping responsibilities. MMS does 
not believe that anything in this final rulemaking will prevent this 
coordination from continuing.

Issue No. 3: There Could Be Conflicts Between the MMS Platform 
Verification Program and the USCG Subchapter N Requirements for 
Floating Facilities

    OOC commented as follows in its cover letter:

    * * * In the current Memorandum of Understanding (MOU) between 
MMS and USCG, both agencies have joint jurisdiction and 
responsibility to review and approve the structural design of non 
ship shaped floating platforms. Prior to this rulemaking, MMS did 
not have regulations expressly covering floating platforms; 
therefore, floating platforms have been designed in accordance with 
USCG regulations which rely heavily on American Bureau of Shipping 
Rules for Building and Classing Mobile Offshore Drilling Units (ABS 
MODU rules). USCG has approved the use of other rules and guides as 
well as industry standards as appropriate to supplement the ABS MODU 
rules. Due to the high level of activity in deepwater and the 
limited staff available within companies, we have not undertaken an 
exhaustive comparative review of the proposed documents to be 
incorporated by reference with the ABS MODU rules. However, there is 
a high probability that conflicts may occur. In the event that 
conflicts do occur, how will the conflict be resolved between MMS 
and USCG regulations on the same system?
    The joint jurisdiction of MMS and USCG over the same systems is 
confusing to industry, especially when conflicts occur. There are 
several approaches that we believe MMS and USCG could consider to 
eliminate the concern over joint jurisdiction. One would be to adopt 
identical regulations for systems subjected to joint jurisdiction. 
Or, MMS and USCG could work together to clearly identify lead 
agencies with the authority to approve each system in lieu of both 
agencies approving each system. Or, since the concept of 
verification agents is acceptable to both MMS and USCG, a 
verification agent that is acceptable to both agencies could review 
the project utilizing the best regulations and standards for the 
specific project or system, regardless if the regulations were 
identical between the two agencies.

    Continuing coordination between MMS and USCG is required during the 
review and approval of OCS floating platforms. For the reasons stated 
under the preceding Issue No. 2, it is unrealistic to expect MMS and 
USCG to adopt identical standards because of the different natures of 
the types of facilities they regulate, and the separate 
responsibilities assigned to each agency by Congress. Both agencies 
have worked diligently through various MOUs over the years to adapt 
their regulatory requirements to changing technology, circumstances, 
and statutory responsibilities.
    USCG is currently revising the regulations at 33 CFR subchapter N. 
Since these are draft regulations, MMS believes it would be 
counterproductive at this time to do a complete and detailed comparison 
between our final subpart I regulations and the USCG proposed version 
of 33 CFR subchapter N. Prior to finalizing subchapter N, USCG and MMS 
have agreed to do a detailed comparison of the floating platform 
requirements of both agencies to identify and eliminate potential 
conflicts to the maximum extent practicable.
    Concerning the matter of CVAs that are acceptable to both MMS and 
USCG, neither MMS nor USCG believes it should be in the business of 
certifying or recommending CVAs. Nevertheless, MMS would encourage 
lessees to submit qualification statements for CVAs that would be 
acceptable to both MMS and USCG.

Issue No. 4: It Is Unclear What Submissions MMS Expects To Receive

    OOC commented concerning proposed Sec.  250.903(b), Sec.  
250.910(b) in this final rule:

    * * * Since the structures listed as (1)(2)(3) and (4) are not 
mentioned in (proposed) Sec.  250.902, it is not clear what 
information MMS expects to be provided in the application process or 
in the CVA process. Please clarify.

    For clarity in this final rule, language was added to the table in 
Sec.  250.905(d), (f), and (h) concerning the items listed in proposed 
Sec.  250.903(b). Briefly summarized, MMS expects to see all structures 
under our jurisdiction submitted through the normal platform approval 
process. The PVP is required for all platforms that do not meet 
standard design criteria for shallow waters. This will always be the 
case for a floating platform.

Issue No. 5: It Is Unclear What Is Expected of the CVA Process for 
Floating Platforms

    Concerning proposed Sec.  250.905(a), OOC commented:

    * * * The design verification plan requirements are confusing. 
The proposed regulation appears to be based on CVA processes for 
fixed platforms. These are not applicable for floating platforms. 
MMS should write separate requirements for CVA processes for fixed 
and floating systems. For floating systems, the operator submits the 
design documentation specified in (1), (2) and (3) directly to the 
CVA, not to MMS to

[[Page 41561]]

give to the CVA. Is this a change in the program? Also, in most 
cases for a floating system, all the required information will not 
be given to the CVA at one time, but rather will be given to the CVA 
in a sequential manner as it is generated. It is recommended that 
MMS investigate the process used for the floating systems to date 
and modify the proposed rule accordingly.

    OOC provided nearly identical comments on proposed Sec.  
250.905(b). Shell provided similar comments. Those proposed subsections 
were renumbered as Sec. Sec.  250.912(a) and (b) in this final rule.
    As explained above in Issue No. 1, concerning whether subpart I 
should be broken down to separately address fixed and floating 
platforms, MMS agrees that a floating platform probably will undergo 
more complicated design, CVA, and approval processes than a fixed 
platform. MMS concluded that it is better to allow the companies' 
engineering staffs to use their judgment in obtaining the various 
approvals rather than for MMS to impose a rigid step-by-step 
certification or classification process for the design, fabrication, 
and installation of each style and permutation of a platform.
    MMS has not changed the program with respect to how PVP materials 
are submitted to the CVA. MMS has always required this information to 
be directly provided by the operator to both MMS and the CVA. The CVA's 
responsibilities during the design, fabrication, and installation 
phases are described in final Sec. Sec.  250.916, 250.917, and 250.918, 
respectively. The CVA for each phase will not be able to perform these 
responsibilities in a proper manner without access to all the 
documentation submitted to MMS.
    MMS agrees with OOC that in most cases, and for floating platforms 
in particular, required information will not be given to either the CVA 
or MMS at one time, but rather will be provided in a sequential manner 
as it is generated. This is to be expected, and is acceptable from our 
viewpoint. MMS is willing to review Platform Verification and CVA 
documentation as it becomes available, and there is no requirement in 
our regulations to submit it at one time. The only MMS requirements 
with respect to timing are the requirement in new Sec.  250.912(a) that 
the lessee may not submit its design verification plan before 
submitting a Development and Production Plan (DPP) or a Development 
Operations Coordination Document (DOCD), and the requirement in new 
Sec.  250.912(d) that operators combine fabrication verification plans 
and installation verification plans for man-made islands.
    This final rule should make it easier to obtain approvals for 
floating offshore platforms. MMS has concluded that it is best to issue 
this final rule, rather than re-propose it with two separate CVA 
processes for fixed and floating platforms, as OOC suggests.
    Concerning proposed Sec.  250.910(d), located at Sec.  250.916(c) 
in this final rule, OOC continued:

    * * * It should also be recognized that for floating systems, 
the CVA has been verifying the design to the USCG requirements since 
MMS had not established design requirements. It will take the CVA 
longer to verify the design to the new requirements. In the cases 
where the CVA is also approving the design for Class and/or USCG, 
they will also have to verify the design to those requirements.

    MMS agrees that it may take the CVA longer to verify the design to 
the new regulatory requirements. For those cases where the CVA is also 
approving the design for Class and USCG requirements, USCG will also 
have to verify the design requirements. This process is addressed in 
the current MOU between MMS and USCG.
    OOC and Shell requested that naval architects be included in the 
list of personnel conducting the design verification described in 
proposed Sec.  250.905(a). MMS agrees, and Sec.  250.912(a) of our 
final rule has been amended accordingly.
    Concerning proposed Sec.  250.911(f), OOC and Shell requested, 
``Please clarify if the fabrication CVA is expected to verify the 
center of gravity, etc. that is normally considered to be part of the 
USCG review and approval.''
    MMS understands industry's concerns about coordination between MMS 
and USCG, particularly regarding floating platforms, and added language 
to final Sec. Sec.  250.916(b) and 250.917(b) stating, ``For floating 
platforms, the CVA must ensure that the requirements of the USCG for 
structural integrity and stability, e.g., verification of center of 
gravity, etc., have been met.''
    Concerning proposed Sec.  250.905(c), (Sec.  250.912(c) in this 
final rule), OOC commented, ``We assume that the inspections discussed 
in (4) are the inspections performed immediately after installation to 
ensure that no damage was done during the installation activities.''
    OOC is correct. The final rule includes revised language in Sec.  
250.912(c)(4) to clarify this point. In some cases it may be desirable 
to conduct intermediate inspections during installation to ensure that 
the installation is continuing according to plan.

Issue No. 6: The Submission and Review Timeframes for Various Documents 
Are Unclear

    OOC and Shell commented concerning the proposed Sec.  250.904(b) 
requirement for three copies each of the design verification, 
fabrication verification, and installation verification plans, now 
contained in Sec.  250.911(c) of this final rule, that the ``MMS should 
establish a time frame for approval following the submittal of the 
required plans.''
    MMS does not agree. The industry respondents themselves have all 
expressed concerns about the complexity of the new subpart I approval 
processes, and uncertainty about their own ability to provide adequate 
documentation to obtain the necessary approvals from both MMS and USCG. 
The submission, review, and approval processes are all very complex. 
Therefore, MMS concluded that it would be unwise to try to put a 
scheduled approval process in place for any segment of the PVP. As 
discussed above under Issue No. 5, MMS agrees with OOC that in most 
cases, and for floating platforms in particular, required information 
will not be given to either the CVA or MMS at one time, but rather will 
be provided in a sequential manner as it is generated. The regulations 
do not require that all information under the PVP be submitted at one 
time.
    As mentioned earlier in our discussion of Issue No. 2, some 
conflicts between MMS and USCG cannot be avoided, and this means that 
there can be no certain schedule for review and approval. In the 
responsibilities section of the MOU between MMS and USCG, a lead agency 
is identified not only for each system, but also for each sub-system. 
For example, each agency is identified as the lead agency for some 
aspect of the station keeping system (including foundations, moorings, 
and tethering systems; or dynamic positioning). Each agency must review 
the design of the station keeping system with respect to foundations, 
moorings, and tethering systems, since it affects the floating 
stability of the facility and the drilling and production operations on 
the facility. Any disagreements will need to be discussed and resolved, 
and MMS cannot guarantee a certain review and approval schedule in such 
situations.
    Concerning proposed Sec.  250.910(d), now Sec.  250.916(c) in this 
final rule, OOC commented:

    * * * These requirements appear to be based on fixed platforms 
and are not applicable to floating platforms. The requirement to 
submit the design CVA

[[Page 41562]]

reports within 6 weeks of receipt of the design data for a fixed 
platform is too short a period. Recommend that the requirement be 
revised to within 90 days of the receipt of the design data, but at 
least prior to facility installation. For floating platforms, the 
complete design data is not provided to the CVA in one package; 
therefore, there should be some recognition of a phased approach. In 
all cases, the final report should be issued to MMS prior to 
installation.

    Shell provided similar comments.
    MMS agrees with OOC and Shell, and amended final Sec.  250.916(c) 
to specify that the CVA must submit the design verification report 
within 90 days of the receipt of the design data. However, MMS has also 
specified that the design verification report must be submitted before 
fabrication begins, rather than before installation begins.
    Also, OOC and Shell commented concerning proposed Sec.  250.911(f) 
that the requirement to submit the fabrication CVA reports immediately 
after completion of the fabrication is not really defined. They 
recommend that the requirement be revised to within 90 days of the 
completion of fabrication, but at least prior to facility installation.
    MMS agrees with OOC and Shell, and amended final Sec.  250.917(c) 
to specify that the CVA must submit the fabrication report within 90 
days of the completion of fabrication, but before installation begins.
    OOC and Shell also commented concerning proposed Sec.  250.912(e) 
that the requirement to submit the installation CVA reports within 2 
weeks of completion of the installation is too short a period. They 
recommended that the requirement be revised to within 30 days of the 
completion of the facility installation.
    MMS agrees, and amended final Sec.  250.918(c) accordingly.

Issue No. 7: MMS Should Write Clear and Comprehensive Regulations That 
Do Not Require Later Notices to Lessees and Operators (NTLs) To Explain 
or Interpret Regulations to Industry

    In its cover letter to MMS concerning the proposed rule, OOC 
commented:

    Further, we have heard comment by MMS that either in conjunction 
or following this rulemaking effort, MMS is considering issuing a 
Notice to Lessees (NTL) explaining the interpretation of the 
regulation. We believe that the regulation should be written in a 
clear, comprehensive fashion such that a NTL, if needed at all, 
would only cover limited areas. Appropriate areas to be included in 
a NTL would be such specifics as a time frame for conducting 
inspection under API RP 2A for existing platforms and a list of 
acceptable CVAs.

    MMS agrees. The agency has written this rule to be as comprehensive 
and clear as possible to minimize the chances that an NTL will be 
required. If it is found that an NTL is needed, MMS agrees it should 
only address limited, site-specific areas, and provide guidance on how 
to implement the existing regulation.

Issue No. 8: Floating Platforms Designed According to ``Class'' Should 
Not Need Specific Approval of the MMS Regional Supervisor

    Concerning proposed Sec.  250.901(b), both OOC and Shell stated:

    If an operator chooses to Class his floating platform, the 
systems covered by Class should be allowed to be designed to Class 
rules without seeking specific approval from the Regional 
Supervisor.

    MMS recognizes that the decision to design a platform according to 
``Class'' requirements provides a level of safety in verifying the 
structural stability of the platform. However, since this decision is 
optional and there is no requirement to maintain the Class of a 
platform, MMS must ensure that all OCS platforms meet MMS regulations. 
Therefore, all OCS platforms, including those that the lessee or 
operator chooses to design according to Class requirements, will 
continue to be specifically approved by the MMS Regional Supervisor 
under current regulations.
    Concerning proposed Sec.  250.902(j), now Sec.  250.905(j) in this 
final rule, Shell commented:

    The Certification required in (j) `The design of this structure 
has been certified by a recognized classification society * * *.' is 
stated as if the design at the time the application has been made 
has already been reviewed and approved. At the time the application 
is made, the design of a floating structure will NOT have been 
certified by a recognized classification society. We recommend that 
you restate the Certification to `The design of this structure will 
be certified * * *'.

    MMS cannot agree with the requested word change. Because of the 
schedule on some projects, MMS receives applications for platforms 
prior to the design being completed. However, these applications must 
include evidence that the design is in the process of being certified. 
Prior to installation, a final certified design must be submitted for 
approval by the MMS Regional Supervisor.
    Concerning proposed Sec.  250.903(a), Sec.  250.910(a) in the final 
rule, OOC and Shell commented:

    If an operator chooses to Class the structure, the systems 
covered by Class should not be subject to the Verification program, 
rather the operator should be required to submit a Class certificate 
once it is issued following the installation of the structure.

    In order for MMS to agree with the OOC and Shell proposal, MMS 
would have to agree to defer to the procedures used to Class each 
floating platform, and MMS would also have to require that the Class 
for each floating platform be maintained and renewed for the life of 
the platform. As explained in its response to the first comment on this 
issue, MMS will not do that. The PVP is not an optional program in lieu 
of designing a platform according to Class requirements. This program 
has served MMS and industry well, and MMS intends to continue to 
maintain the program of third party verification for platform design, 
fabrication, and installation. Under the OCS Lands Act, MMS is 
obligated to oversee oil and gas exploration, development, and 
production operations on the OCS to ensure that they are conducted in a 
safe manner. The verification of production platforms is a part of that 
responsibility.

Issue No. 9: MMS Should Better Define What Is Meant by ``New'' Floating 
Platforms and ``Major Modifications''

    Newfield commented, ``Definitions of `new' and `major modification' 
are vague and require more precise definitions to prevent confusion and 
interpretation problems.''
    Also with respect to new facilities, OOC and Shell commented 
regarding Sec.  250.800(b) and Subpart I:

    1. How is `new' defined? It should be realized that in many 
cases there is a long lead time between the initial design of the 
platform, the facilities, mooring and risers and fabrication and 
installation. All floating platforms currently in either the late 
stages of design or being fabricated may not fully comply with all 
of the proposed regulations. This comment is applicable to other 
parts of the proposed regulation where `new' is utilized.
    2. How are fixed and floating platforms handled that are reused 
or relocated to a different block than where they were originally 
sited? Is the design grandfathered to the rules in place at the time 
the unit was designed, fabricated and originally installed or will 
it have to meet any new requirements that have been adopted since 
the initial installation? Is there a difference in the way fixed 
platforms are handled from floating platforms?

    From MMS's perspective, a ``new platform'' means a newly-
constructed platform at a certain location, or a used platform that is 
either moved to a new site or used for a new purpose. In the first 
situation, the platform is considered a ``newbuild.'' In the latter 
situation, it would be a used platform converted for a new use or at a 
new site. There is no ``grandfathering'' of prior

[[Page 41563]]

standards for relocated platforms. For either a newbuild or a 
relocated/new-use platform, the platform would have to meet MMS 
regulations as they exist at the time the platform design is reviewed 
(or re-reviewed) by MMS. For fixed platforms, all design, fabrication, 
and installation requirements would be governed by MMS regulations. 
Floating platforms would be governed by both MMS and USCG regulations, 
as described above in the Issue No. 2 discussion concerning the MOU 
between MMS and USCG.
    In the case of a used platform, the design is approved for the new 
use or site, and the used platform would have to meet the requirements 
of Section 15 of API RP 2A, which addresses the key aspects of reused 
platforms. Relocated facilities would have to meet all new 
requirements, and pass the inspection requirements listed in Section 15 
of API RP 2A. The Twenty-first Edition of API RP 2A was incorporated 
into MMS regulations under a separate rulemaking on April 21, 2003.
    Although API RP 2A addresses fixed structures, MMS would apply some 
of the principles and methodologies outlined in API RP 2A for reused 
facilities to floating platforms also. In addition, there are certain 
structural fatigue considerations related to floating platforms that 
are partly covered in other API standards, such as API RP 2FPS and API 
RP 2SK, and which would be applicable to reused floating facilities. 
Finally, a reused floating facility relocated to a new site would be 
treated as a new facility requiring an API RP 14J hazards analysis.
    Once the design for any fixed or floating platform is approved, MMS 
regulations at the time of the design approval will govern the 
fabrication and installation phases as well. In that sense, the subpart 
I regulations are grandfathered when the platform design is approved 
for a specific platform, use, and location. MMS has always followed 
this principle under subpart I.
    Concerning proposed Sec.  250.900(a), (Sec.  250.900(a) and (b) in 
this final rule), OOC commented:

    Although major modification is vaguely defined in 250.900(a)(2), 
industry is confused by the definition and it is not clear what MMS 
means by the definition. Either more precise definition is needed or 
examples need to be given. Is there a difference in major 
modification to a fixed platform versus a floating platform?

    OOC and Shell further commented concerning proposed Sec.  
250.903(c), (Sec.  250.909 in this final rule):

    What constitutes a major modification to a fixed or floating 
platform? Does it include such things as increased loading due to 
additional topsides equipment or loading from additional wells or 
risers?

    From MMS's perspective, a major modification would be any 
modification to a structure that affects loading by more than 10 
percent. This definition follows the principle that MMS has used over 
the years, as well as the guidance in API RP 2A, Section 17, 
``Assessment of Existing Platforms,'' Subsection 17.2.6, ``Definition 
of Significant.'' This definition states: ``Cumulative damage or 
cumulative changes from the design premise are considered to be 
significant if the total of the resulting decrease in capacity due to 
cumulative damage and the increase in loading to cumulative changes is 
greater than 10 percent.'' Although, the subsection is written to apply 
to either damage or structural changes, MMS believes this is a good 
principle to follow for all platforms. This is especially important for 
floating platforms, because of the stability issues that arise when 
additional loads are added to floating structures. Thus, when OOC and 
Shell ask whether a ``major modification'' could include ``increased 
loading due to additional topsides equipment or loading from additional 
wells or risers,'' the answer is ``yes.'' Also, repairs to a structure 
to correct damage could be seen as a major modification if they 
increase loading on the platform by 10 percent or more.
    MMS will evaluate proposed modifications on a case-by-case basis. 
Language has been added to both Sec.  250.900(b) and Sec.  250.910(c) 
in this final rule to clarify that a major modification includes any 
modification that increases loading on a platform by 10 percent or 
more, and requiring that lessees and operators consult with both MMS 
and USCG in seeking approval for a major modification to a floating 
platform.

Issue 10: The Application of American Petroleum Institute (API) 
Recommended Practice (RP) 14J, and API RP 2FPS to ``New'' Floating 
Production Platforms Needs Clarification

    Concerning proposed Sec.  250.803, ABS commented:

    We note the proposed incorporation of API RP 14J into the 
revised rules. In this regard, we note that much of 14J was written 
from the standpoint of use with fixed platforms. With respect to 
floating structures (such as spars and FPSO's) it is unclear whether 
the risk assessment methodologies and checklists accompanying the 
14J document will adequately cover the integration of vital process 
and marine systems (such as ballast control, stability, marine 
system integration, cargo transfer, etc.), where simultaneous 
operations and cross-overs are prevalent. The hazards assessment 
methodology proposed by MMS should therefore consider ways to ensure 
that strict adherence to 14J in carrying out a hazards analysis on a 
floating installation will address this vital marine/process system 
relationship.

    Concerning proposed Sec.  250.901, ABS commented:

    It is noted in the proposed rulemaking commentary that API RP 
2FPS is an umbrella document imposing no new requirements directly. 
Structural and production facility requirements are specifically 
referenced throughout Sec.  250. Prior to this rulemaking MMS had no 
specific rules for marine and other non-production related systems 
for floating production units, as are found in API RP 2FPS. A 
specific statement as to MMS intentions relative to these non-
production systems would be appropriate.

    MMS agrees with ABS that API RP 14J and API RP 2FPS may not by 
themselves completely address all aspects of floating facilities to be 
regulated under subpart I. Nevertheless, these two industry references 
serve very useful purposes. API RP 2FPS provides guidance on all of the 
associated marine systems, as well as drilling and production systems, 
and how they fit together and interact with each other. MMS knows of no 
other standard that performs this function. Though API RP 14J was 
initially developed to address hazards analysis approaches for drilling 
and production systems on fixed offshore platforms, these same systems 
will be installed on floating offshore platforms. Further, the hazards 
analysis approaches presented in Section 7 of API RP 14J will prove 
important in considering simultaneous operations and cross-over that 
will occur on floating offshore platforms. That is why MMS is 
incorporating these two documents by reference into our regulations, 
and intends to employ them, as appropriate, in our review of new 
floating production facilities.

Issue No. 11: The Application of American Petroleum Institute (API) 
Recommended Practice (RP) 2A to Fixed Production Platforms Needs 
Clarification

    ABS commented concerning proposed Sec.  250.901:

    The document adopts the API-RP2A-WSD. Is the API - RP2A - LRFD 
not acceptable at this time for any application? Some of the 
requirements in API - RP2A - LRFD, such as hydrostatic collapse of 
tubular members for deepwater applications, may be more reasonable 
than those in WSD. If acceptable, guidance in the regulations should 
specify load and resistance factors.

    Since the early 1980s, MMS has followed the policy currently 
outlined in Sec.  250.141 of our operating

[[Page 41564]]

regulations, whereby MMS promotes the use of technology or innovative 
practices that are not specifically mentioned or otherwise covered 
under our regulations. For example, Sec.  250.141 tells the lessee or 
operator that ``You may use alternate procedures or equipment after 
receiving approval as described in this section.'' The approval must be 
in writing from either the MMS District or Regional Supervisor. 
Paragraph (a) of Sec.  250.141 requires that ``Any alternate procedures 
or equipment that you propose to use must provide a level of safety and 
environmental protection that equals or surpasses current MMS 
requirements.'' Paragraph (c) of Sec.  250.141 requires that the lessee 
or operator submit information or provide an oral presentation to 
describe the site-specific applications, performance characteristics, 
and safety features of the proposed alternate procedures or equipment.
    Thus, if a lessee or operator believes that the load and resistance 
factors design (LRFD) version of API RP 2A is more appropriate for its 
proposed platform than the working stress design (WSD) version, the 
lessee or operator may submit its arguments to use the former under 
Sec.  250.141 of MMS operating regulations. As stated previously in 
this discussion, MMS has already incorporated the Twenty-First Edition 
of API RP 2A into our regulations under a separate rulemaking dated 
April 21, 2003.

Issue No. 12: MMS Should Publish a List of Acceptable CVAs for Various 
Types of Structures

    In their cover letter, OOC commented:

    * * *In lieu of submitting a qualification statement and 
obtaining approval for each CVA for each project, MMS should publish 
a list of acceptable CVAs for various types structures for which a 
qualification statement is not required. For example, ABS and DNV 
for spars and TLPs. If an operator wanted to use a CVA not on the 
``approved'' list, then a qualification statement would be required 
and the CVA would have to be approved.

    MMS does not agree with this recommendation. In 1979, when the PVP 
was first instituted, MMS' predecessor agency maintained a list of 
acceptable CVAs for various types of offshore platforms and for the 
various phases of the verification process, as proposed in OOC's 
comment. However, it soon became apparent that, as a result of the 
movement of personnel between companies and continuous changes in a 
company's workload, the qualifications of the companies on this list 
changed frequently. It was not possible to ensure that a specific 
company maintained the required expertise to remain on the CVA list on 
a long-term basis. Also, some companies discovered that being on such a 
list did not ensure that they would receive any work as a CVA. 
Therefore, MMS stopped maintaining a list of acceptable CVAs and began 
to allow OCS lessees to nominate their selection of a company or a 
person to act as their CVA on a case-by-case basis for each project and 
phase of the project. This approach was already implemented in our 
regulations and is continued in the new subpart I under Sec.  250.914.

Issue No. 13: There Should be More Guidance in Proposed Sec. Sec.  
250.902 and 250.903, Now Numbered as Final Sec. Sec.  250.905 and 
250.910, Concerning CVA Responsibilities for Review of (1) Drilling and 
Production Risers, and Riser Tensioning Systems; (2) Turrets and 
Turret-and-Hull Interfaces; (3) Foundations and Anchoring Systems; and 
(4) Mooring or Tethering Systems

    Concerning proposed Sec.  250.902, OOC commented:

    * * *We also note that no information has been requested to be 
submitted in the platform application on the drilling and production 
risers and tensioning systems for floating platforms even though 
these are proposed to be covered under the CVA program. What 
information are we required to provide to either MMS or the CVA on 
these elements?

    OOC made a similar comment regarding proposed Sec.  250.903(b), as 
follows:

    1. While it may be prudent to include drilling and production 
risers and riser tensioning systems in the CVA program for design, 
it is problematic to include these into the fabrication and 
installation CVA program. The risers and tensioning systems will be 
fabricated for wells as needed, they are not all fabricated at one 
time similar to platform (sic). We question the value returning to 
the CVA fabrication process each time a riser or tensioning system 
is fabricated. The risers and tensioning systems are installed on 
each well as it is drilled. We question the value of having the 
installation verified through the CVA program. If a conventional 
marine riser is utilized for drilling operations, it should be 
excluded from the CVA process.
    2. Since the structures listed as (1)(2)(3) and (4) are not 
mentioned in Sec.  250.902, it is not clear what information MMS 
expects to be provided in the application process or in the CVA 
process. Please clarify.

    Concerning proposed Sec.  250.910(b), (Sec.  250.916(b) in the 
final rule), OOC commented:

    The scope of work for the CVA design review of drilling and 
production risers and tensioning systems is not clear. MMS should 
provide additional guidance on the CVA duties for these elements.

    Concerning proposed Sec.  250.912(a), (Sec.  250.918(b) in the 
final rule), OOC commented:

    We note that there are no requirements for drilling and 
production risers and tensioning systems listed in the CVA duties. 
Although we believe that the installation of these systems should 
not be included in the CVA's duties, if MMS disagrees and includes 
them in the CVA process, then the CVA's duties should be specified.

    ABS submitted a similar comment concerning proposed Sec. Sec.  
250.911 and 250.912 (Sec. Sec.  250.917 and 250.918 in the final rule):

    * * * These sections refer to the applicable provisions of the 
documents in 250.901(a). As API RP 2RD and Spec 17J are specifically 
design oriented, clarification is required regarding MMS intentions 
relative to Fabrication and Installation CVA activities.

    As an initial matter, and with respect to these comments generally, 
when MMS requires that an item be reviewed by a CVA under the PVP, that 
item must be included with the lessee's platform application. As noted 
by the commentors, API RP 2RD and API Spec 17J are primarily oriented 
toward the design of risers and unbonded flexible pipe, respectively, 
and not the fabrication or installation of these risers or pipelines at 
an offshore platform. (API Spec 17J is discussed more completely in 
connection with the next issue.) Nevertheless, MMS has required a CVA 
review for design, fabrication, and installation of drilling and 
production risers, and riser tensioning systems for all floating 
platforms, as discussed below.
    Second, MMS has added language to the application table in Sec.  
250.905 to clarify that the following information required under Sec.  
250.910(b) is to be included in a lessee's platform application: (1) 
Drilling, production and pipeline risers, and riser tensioning systems; 
(2) turrets and turret-and-hull interfaces; (3) foundations, foundation 
pilings and templates, and anchoring systems; and (4) mooring or 
tethering systems. Additionally, language was added in Sec. Sec.  
250.916 through 250.918 to clarify that these four categories of 
information must be reviewed by a CVA for the three phases of design, 
fabrication, and installation.
    Third, each riser type and the tensioning system for that riser 
type is to be approved by a qualified CVA for the design phase, the 
initial fabrication phase, and the initial installation phase for that 
riser and riser tensioning system. After the first fabrication and 
first installation of a given type of riser and attendant riser 
tensioning system, MMS agrees that it is not necessary to

[[Page 41565]]

return to the CVA fabrication and installation process for each 
additional riser or riser tensioning system for that riser type. 
Language has been added to Sec. Sec.  250.917 and 250.918 to clarify 
this point.
    It is important to bear in mind, however, that each additional 
riser and riser tensioning system adds a significant load to a floating 
platform, so the overall platform must be designed to accommodate all 
the loads imposed by additional risers and riser tensioning systems. 
MMS will review plans for additional risers and riser tensioning 
systems to ensure that the overall platform design can accommodate the 
additional elements.
    Concerning proposed Sec. Sec.  250.911 and 250.912, (Sec. Sec.  
250.917 and 250.918 in the final rule), ABS further commented:

    * * * MMS is encouraged in the recognition of industry design, 
fabrication and installation requirements more specific than, but 
fulfilling compliance with the new proposed rules. This is to ensure 
harmonization of requirements for joint responsibility areas between 
MMS and USCG as well as with relevant third parties, such as 
classification societies, and reducing the risk of differing 
requirements for the same item by different parties.

    MMS recognizes the complexities of issuing permits for floating 
production facilities related to the overlapping responsibilities of 
MMS and USCG. These processes are, of necessity, further complicated by 
the third-party reviews of CVAs and classification societies. This will 
require continuous cooperation and refinement of coordination between 
MMS and USCG, as well as the various industry standards-setting 
organizations.

Issue No. 14: Concerning Installation of Unbonded Flexible Flowlines 
and Pipelines Under Sec. Sec.  250.803(b)(2)(iii), 250.1002(b)(4), and 
250.1007(a)(4), Respectively, It Is Unclear How MMS Will Handle the 
Independent Verification Agent (IVA) Reviews

    OOC and Shell commented concerning proposed Sec.  
250.803(b)(2)(iii):

    When does the third party review of unbonded flexible pipe 
flowlines have to be submitted to MMS? What is MMS going to do with 
the IVA review? Does the review have to be approved by MMS?

    OOC and Shell further commented concerning proposed Sec.  
250.1007(a)(4):

    It should be recognized that the third party review may not be 
available at the time the initial pipeline application is submitted. 
This requirement should be reworded to say that the third party 
review must be submitted prior to the pipeline application being 
approved.

    Similarly, ABS submitted the following comment concerning proposed 
Sec. Sec.  250.803(b)(2)(iii), 250.1002(b)(4), and 250.1007(a)(4):

    The Independent Verification Agent (IVA) per API SPEC 17J is 
noted in the Introductory supplementary information of the notice of 
proposed Rulemaking as being equivalent to the Certified 
Verification Agent (CVA) per MMS rules. However, this equivalency is 
not specifically addressed within the above cited proposed rule 
sections. Such a clarification is suggested for clarity.

    In light of these comments, MMS has reconsidered the requirements 
of API Spec 17J. The IVA review requirements in that standard are 
intended to pertain only to the design and manufacturing process of 
unbonded flexible pipe, not the actual installation of the pipe on 
location. In this context, the IVA described in API Spec 17J does not 
serve the same role that the CVA serves in subpart I of our 
regulations. Therefore, Sec. Sec.  250.803(b)(2)(iii), 250.1002(b)(4), 
and 250.1007(a)(4) have been modified to require that the lessee or 
operator installing flowlines or pipelines of unbonded flexible pipe 
(1) Review the Design Methodology Verification Report, and the IVA's 
certificate for the design methodology contained in that report, to 
ensure that the manufacturer has complied with the requirements of API 
Spec 17J; (2) determine that the flexible pipe is suitable for its 
intended purpose on the lease or pipeline right-of-way; (3) submit to 
the MMS District or Regional Supervisor the manufacturer's design 
specifications for the pipe; and (4) submit to the District or Regional 
Supervisor a statement certifying that the pipe it has chosen is 
suitable for its intended use, and that the manufacturer has complied 
with the IVA requirements of API Spec 17J.

Issue No. 15: The Requirements for In-Service Inspection Plans (ISIPs) 
Need To Be Clarified, Particularly Concerning Floating Platforms and 
USCG Responsibility for ISIPs for Floating Platforms.

    OOC provided the following comments concerning proposed Sec.  
250.902 (Sec.  250.905 in the final rule):

    Document (i) requires that an in-service inspection plan be 
submitted for both fixed and floating platforms with the 
application. In the MOU between the USCG and the MMS, USCG has been 
given sole jurisdiction of structural inspection requirements for 
floating platforms, with the USCG copying MMS on approvals and 
compliance records. Industry is confused over the rationale for MMS 
to adopt In-service Inspection Plan (ISIP) requirements for floating 
platforms. MMS should coordinate any requirements for ISIP review 
and inspection oversight with the USCG, to eliminate a duplicate or 
parallel program. We also question the timing of the submittal of 
the inspection plan. Since the first inspection is normally not due 
for at least a year after installation, we recommend that any ISIP 
that is required to be submitted not be submitted with the platform 
application, but within 1 year after installation. Clarification is 
also needed on the in-service inspection agency jurisdiction for 
mooring and station keeping systems. It is also unclear what 
information the MMS expects to see in an ISIP for either a fixed or 
floating platform. Also, since the ISIP has to be submitted with the 
platform application, this suggests that each platform has to have 
an individual inspection plan. It would be less burdensome on both 
industry and MMS to develop a generic inspection, at least for fixed 
platforms, that covers the different types of platforms that an 
operator has with perhaps a table covering the individual platforms.

    Shell provided similar comments regarding proposed Sec.  250.902 
(final Sec.  250.905).
    OOC provided the following comment concerning proposed Sec.  
250.916(a) (final Sec.  250.919(a)):

    1. For floating facilities the In-Service Inspection Program 
(ISIP) duplicates the vessel inspection program already required and 
being done by the USCG. MMS should coordinate any requirements for 
ISIP review and inspection oversight with the USCG, to eliminate 
duplicate or parallel programs.
    2. Since the proposed regulation calls for submitting an 
inspection with a platform application, does MMS envision that 
inspection plans be generated for existing platforms? If so, do they 
have to be submitted to MMS for review or approval? Does each 
facility have to have its own plan? Can one plan cover all of an 
operator's structures or does each structure have to have its own 
plan?

    Shell provided similar comments regarding proposed Sec.  250.916 
(final Sec.  250.919), paragraphs (a) and (b).
    MMS disagrees with the claim that the requirement for ISIPs is a 
new and unjustified requirement. ISIPs are required under our current 
subpart I regulations, so any existing platform not covered by an ISIP 
would not be in compliance with our regulations.
    MMS first implemented the requirement for a periodic structural 
inspection of all fixed platforms installed on the OCS in April 1988, 
after it was proposed by the Marine Board of the National Academy of 
Sciences. Oil and gas industry representatives participated on the 
Marine Board when it made the recommendation.
    The MMS ISIP requirement and the API standards provide starting 
points for developing ISIPs for fixed and floating offshore platforms. 
It should be expected that an ISIP for a given facility would have to 
be modified if

[[Page 41566]]

subsequent experience indicates that it is not adequately covering a 
certain aspect affecting the stability or safety of the platform or its 
associated structures.
    MMS disagrees that an ISIP should be provided within 12 months 
after the installation of an offshore facility, instead of with the 
platform application. Periodic inspection issues affect the design of 
an offshore facility, and therefore must be considered during the 
design of an offshore facility. Periodic inspection issues also must be 
considered during the initial review by the regulatory agencies. The 
original designers of a platform are usually best qualified to design 
the ISIP for that platform. Therefore, MMS encourages lessees and 
operators to at least consult with their original designers in the 
development of an ISIP for a platform.
    In response to OOC's comment that it is unclear what information 
MMS expects to see in an ISIP for either a fixed or floating platform, 
MMS expects the ISIP to reference all relevant API or other industry 
standards. OOC's observation that it appears that MMS expects each 
platform to have an individual inspection plan is correct. Each 
platform should have its own ISIP. However, if a lessee or operator has 
a number of platforms that are all of the same type, it is acceptable 
to have one generic ISIP covering all those platforms. The generic ISIP 
would have to be modified to address the unique environmental 
conditions affecting each specific platform. Also, for each platform 
having significant structural features distinguishing it from the 
generic type, the generic ISIP would have to be tailored to accommodate 
the significant distinguishing structural features of that platform.
    MMS also disagrees that the USCG has sole jurisdiction for the 
structural inspection requirements for floating platforms. The USCG has 
the lead responsibility for the floating facility hull. However, USCG 
does not have lead responsibility for the turret, turret/hull 
interface; the risers and their tensioning systems and interface with 
the hull; the foundations and anchoring systems; or the mooring or 
tethering systems. MMS has the lead responsibility for these systems, 
any or all of which could adversely affect the safety and stability of 
the hull of a floating facility. Since the hull and interconnected MMS-
regulated systems are so intertwined, to be relevant and complete an 
ISIP should address all the systems within the regulatory 
responsibility of both MMS and USCG.
    MMS and USCG currently meet regularly to discuss their concerns 
with various aspects of each platform submission, and to work out 
regulatory differences prior to responding to the submitting companies. 
This process will continue, to ensure that submitting companies will 
not be given conflicting instructions. Because MMS and USCG hold 
ongoing discussions concerning their respective responsibilities for 
offshore floating platforms, the agencies may, from time to time, amend 
their MOU regarding oil, gas, and mineral exploration and production 
operations on the OCS.

Issue No. 16: For Platforms Subject to the Platform Verification 
Program, MMS Should Provide More Clarity Concerning Which Documents Go 
to MMS and Which Go to the CVA

    In its cover letter, OOC commented:

    It is also unclear why MMS needs to get a copy of many of the 
items that are submitted directly by the operator or design firm to 
the CVA for review. For example, why does MMS need to receive 
abstracts of the computer programs used for design when the same 
information must be given to the CVA? It appears to be redundant for 
MMS and the CVA to review the same documents. Since a number of 
floating platforms have now been permitted, we recommend that MMS 
consider revising the structure application and CVA plan to better 
reflect the actual way floating platform projects are sequenced and 
to consider what information MMS needs to review and what needs to 
be given directly to the CVA * * *.

    Concerning proposed Sec.  250.902 (final Sec.  250.905), OOC and 
Shell commented:

    For platforms subject to the Platform Verification Process, the 
rationale for submitting a full application to MMS, including a 
complete set of structural drawings, etc., is unclear since the 
information will also be provided to the certification agency to 
verify the design. It would appear to be more appropriate to submit 
(a),(b),(c) and (j) to MMS with the rest of the information 
submitted to the CVA. In many instances all of the information 
required is not available at the time the application needs to be 
made for a floating platform in order to kick off the CVA program.

    From a regulatory perspective, it is important to remember that the 
CVA process was initiated because MMS does not maintain an engineering 
staff large enough to comprehensively review all structural engineering 
designs for platforms on the OCS. Thus, a CVA helps ensure that all 
regulatory requirements are met. However, because of our custodial 
responsibility for all information related to the design and structural 
integrity of offshore platforms, it is essential that MMS receive all 
the same documents and correspondence that the lessee or operator 
provides to its CVA concerning the design, fabrication, and 
installation of a fixed or floating platform. This includes the 
computer programs used for design that OOC referred to in its cover 
letter. For MMS to stay current with the industry it regulates, we must 
stay abreast of the various types of software that the industry uses on 
a routine basis.
    Concerning the observation by OOC and Shell that sometimes all 
required information is not available at the time the application for a 
floating platform needs to be made, MMS understands that design, 
fabrication, and installation sequences do not always follow a set 
pattern. MMS is always willing to work with lessees and operators to 
accept partial submittals of information, as they become available, to 
complete what is a necessarily complex permitting process.
    Concerning proposed Sec.  250.904(b), (Sec.  250.911(c) in the 
final rule), OOC commented that MMS may need to provide more guidance 
to the CVA to ensure that they are only verifying the operator's 
proposed design to ensure that it meets the required regulations, not 
conducting a complete design analysis.
    Although MMS agrees with OOC's premise that the CVA primarily 
functions to ensure that the lessee's or operator's design, 
fabrication, or installation meets regulatory requirements, it is 
important to remember that oftentimes the offshore industry is trying 
out new technology or innovative practices. For innovative proposals 
which could involve novel components or structures, MMS will require 
the lessee's CVA to conduct a complete design analysis.

Issue No. 17: Further Clarification Is Needed Concerning the Structural 
Fatigue Requirements in Proposed Sec. Sec.  250.913 and 250.914 (Final 
Sec. Sec.  250.908 and 250.903(b))

    Concerning proposed Sec.  250.913, OOC commented:

    The table does not appear to take into account the minimum 
requirements in API RP 2RD and 2SK. We recommend that the table be 
amended to meet the minimum requirements required in the documents 
incorporated by reference unless MMS is intending to relax those 
requirements. While we recognize that the table only contains 
absolute minimum requirements, we note that Class society 
requirements have a higher minimum threshold that must be met for 
Classed structures.

    MMS agrees with OOC's comment concerning the minimum requirements 
contained in the industry standards that are included as documents 
incorporated by reference in Sec.  250.901. Section

[[Page 41567]]

250.908 of the final rule has been rewritten to provide clarity.
    Also concerning proposed Sec.  250.913 (Sec.  250.908 in the final 
rule), ABS commented:

    The current practice on fatigue safety factors are based on API 
RP 2T considering repairability, inspectability and criticality 
(redundancy) of the members and joints. The API RP 2T fatigue 
requirements are widely used in the site specific floating 
structures (TLPs, column-stabilized units, spars, etc.). The 
recommended fatigue safety factors (2 and 3) consider only one 
(redundancy) of these three factors. For the deck structure, which 
is above the water line, these safety factors are appropriate 
because it is accessible for inspections and repairs. However, for 
the hull structure, which is always below the water line, the 
recommended fatigue safety factors may not be appropriate because 
good quality inspections and repairs will be difficult to carry out 
in some areas of the hull. The Rules should also indicate that the 
other two factors need to be considered if applicable. The following 
are the safety factors normally used for the hull structure of a 
site-specific floating structure in current practice.

----------------------------------------------------------------------------------------------------------------
                                                                                                       Factor of
               Criticality                          Inspection                      Repair               safety
----------------------------------------------------------------------------------------------------------------
Critical.................................  Easily inspectable..........  Field Repair................          5
Critical.................................  Difficult or Non-inspectable  Difficult or Non-repairable.         10
Non-Critical.............................  Easily inspectable..........  Field Repair................          3
Non-Critical.............................  Difficult or Non-inspectable  Difficult or Non-repairable.          5
----------------------------------------------------------------------------------------------------------------

    Requirements for the fabrication, installation, and inspection of 
the hull of floating structures, and the appropriate safety factors to 
use, are under the jurisdiction of the USCG. The structural fatigue 
safety factors listed in proposed Sec.  250.913 (final Sec.  250.908) 
refer to fixed platforms. For fixed platforms, which have a long 
history of proven performance, MMS prefers to rely on the safety 
factors recommended by the referenced documents in Sec.  250.901. The 
safety factors in those documents are based on industry consensus, and 
may be re-evaluated as industry gains even more experience. They can be 
changed later by industry consensus, and those changes in turn 
incorporated by MMS.
    Concerning proposed Sec.  250.914 (now Sec.  250.903(b)), OOC and 
Shell commented that it is not clear where the records on the origin 
and material test results are to be kept on all primary structural 
materials covered by this section.
    The records on the primary structural materials should be kept at 
the same location that the lessee or operator specifies in item (j) of 
the table in final Sec.  250.905. The regulatory language of final 
Sec.  250.903 has been modified to make this clear.

Issue No. 18. The Proposed Rule Provides Inadequate Guidance on the Use 
of Shallow Hazards and Geological Surveys in Siting Platforms

    ABS submitted the following comment concerning proposed Sec.  
250.915 (Sec.  250.907 in the final rule):

    4. It would be helpful for the MMS to provide guidance as to the 
acceptance criteria for faults such as the minimum distance from the 
faults to the foundation and what type of fault studies are 
recommended. This issue has not been addressed in any of the 
referenced documents listed in Sec.  250.901. Faults have been 
encountered in deepwater applications.
    5. It will be useful for the offshore industry if MMS's policy 
on the required pile capacity at first oil is specified in the CFRs.

    MMS reviewed the requirements for shallow hazards, geologic, and 
subsurface surveys in our former subpart I, and compared them to the 
requirements already incorporated in the twenty-first edition of API RP 
2A and the API documents to be incorporated by reference by this rule. 
Based on this comparison, MMS believes that it was unwise to remove so 
many of our survey requirements in the proposed rule. However, MMS 
believes that API RP 2A and the other API documents more than 
adequately address many of the subsurface issues that arise in 
designing various types of foundations and pilings. Accordingly, MMS 
has restored an abridged version of our former requirements to the 
final rule. MMS has inserted the abridged hazard, geologic, and 
subsurface survey requirements into a new Sec.  250.906 in the final 
rule.
    Section 250.915 in the proposed rule dealt with the requirement for 
a minimum 500-foot interval between a soil boring and a foundation 
piling. The sections in the final rule have been renumbered and 
rearranged so that the proposed Sec.  250.915 is now final Sec.  
250.907.
    In answer to ABS' first question concerning ``acceptance criteria 
for faults such as the minimum distance from the faults to the 
foundation and what type of fault studies are recommended,'' MMS 
believes that such judgments have to be made on a case-by-case basis 
depending on the design of the platform and the nature of the sediments 
into which its foundations or anchors are to be set. The abridged 
survey requirements in final Sec.  250.906 will enable the lessee or 
operator to make such determinations for its proposed platform.
    Concerning ABS's second request for us to specify ``MMS's policy on 
the required pile capacity at first oil,'' MMS believes that judgments 
on pile capacity again will have to be made case-by-case, based on the 
results of the shallow hazard, geologic, and subsurface surveys 
required by Sec.  250.906 of this final rule.

Issue No. 19: Respondents Disagree With the Proposed Sec.  250.915(a) 
Requirement (Now Sec.  250.907(a)) for Fixed or Bottom-Founded 
Platforms and Tension Leg Platforms That the Maximum Distance From a 
Foundation Pile to a Soil Boring Must Not Exceed 500 Feet

    OOC and Shell commented on proposed Sec.  250.915(a) (now Sec.  
250.907(a) in this rule) as follows:

    1. Spatial variability of soil properties on the continental 
shelf is much more of an issue than for deepwater sites. For jackets 
on the shelf, maximum distance between borings of 500 ft. is 
reasonable for deterministic designs with conventional safety 
factors. However, it is possible to have cases where multiple 
borings are spaced farther apart, but the uncertainty at the 
platform site may be explicitly quantified and specific safety 
factors developed accordingly.
    2. In lieu of the prescriptive requirement as proposed, the 
wording from ISO/DIS 19901-4 could be adopted:
    Geotechnical and Foundations Design Considerations. Results of 
previous integrated geoscience studies and experience at the site 
may enable the design and installation of additional structures 
without additional investigation. The onsite studies should extend 
throughout the depth and aerial extent of soils that will effect or 
be affected by installation of the foundation elements. The number 
and depth of borings and extent of soil testing will depend on the 
soil variability in the vicinity of the site, environmental design 
conditions (e.g. earthquake loading and slope instability) to be 
considered in the foundation design, the structure type and 
geometry, and the definition of geological hazards and constraints.

[[Page 41568]]

    3. For TLPs in deepwater, the industry practice is to conduct an 
integrated geotechnical/geology study of the site to assess spatial 
variability of soil stratigraphy and physical properties. Given the 
same depositional environment and geologic processes, practice has 
shown at several prominent deepwater basins that borings up to 10 
miles apart do not produce appreciably different pile sizes 
considering the same load. Also, the uncertainty in soil properties 
at the platform site may be explicitly quantified and specific 
safety factors developed accordingly.

    ABS submitted the following comment concerning proposed Sec.  
250.915 (final Sec.  250.907):

    * * * It will be very helpful to the offshore industry to 
clarify requirements as to the maximum distance of the soil boring 
from the foundation piles and number of borings. It would also be 
helpful to clarify if the borings can be replaced by other means of 
taking soil samples such as CPT or by a combination of geotechnical 
investigation and geophysical survey.

    MMS does not agree with OOC, Shell, and ABS. None of their 
proposals is as stringent as what MMS has proposed, i.e., site-specific 
borings within 500 feet of the proposed foundation pile. In the 
deepwater areas of the OCS, particularly in the GOM, there are slope 
and abyssal areas that are much more geologically active than the 
relatively shallow and familiar areas of the OCS. There are highly 
active slumping and faulting zones in deepwater areas that exhibit 
stratigraphic shallow water flows and mud volcanoes. MMS does not 
believe that floating production systems in these areas should be 
anchored without site-specific soil boring information.
    The policy currently outlined in Sec.  250.141 of our regulations 
promotes the use of alternative technology or innovative practices that 
are not specified or otherwise covered under our regulations. Such 
technologies and practices may be tried on a case-by-case basis, so 
long as they ``provide a level of safety and environmental protection 
that equals or surpasses current MMS requirements.''
    Thus, if a lessee or operator believes that for a proposed platform 
on a specific site it can use alternate means to assure secure 
foundations for the facility or its anchoring systems, it can present 
its evidence to the MMS Regional Supervisor under the provisions of 
Sec.  250.141.

Issue No. 20: Respondents Disagree With the Proposed Sec.  250.915(b) 
(Final Sec.  250.907(b)) Requirement That for Deepwater Floating 
Platforms Utilizing Catenary or Taut-Leg Moorings, Borings Must Be 
Taken at the Most Heavily Loaded Anchor Location, at Anchor Points 
Approximately 120 and 240 Degrees Around the Anchor Pattern From That 
Boring, and as Necessary to Establish a Suitable Soil Profile

    Concerning proposed Sec.  250.915(b), OOC and Shell commented as 
follows:

    Recognizing that deepwater developments with moored floaters and 
many subsea wells may cover a very large lateral extent (with the 
layout in a constant state of flux), an alternative site 
investigation strategy would be to base geotechnical data collection 
locations on the prevailing geology rather than specific facility 
locations. An integrated geotechnical/geology study of the 
development area is required for this methodology `` i.e., 
stratigraphy must be known at any specific foundation location and 
uncertainties quantified. Specific safety factors may be developed 
accordingly.

    OOC further noted, ``This section is prescriptive in nature and we 
recommend that a performance based requirement be adopted.''
    Again, MMS disagrees with OOC and Shell for the same reasons as 
discussed in the preceding issue concerning the maximum distance from a 
foundation pile to a soil boring. If a lessee or operator believes that 
for a proposed platform on a specific site it should use a different 
boring pattern, or alternate means to assure a secure anchoring pattern 
for a floating facility, it can present its arguments for a different 
boring pattern, or alternate method to the MMS Regional Supervisor 
under the provisions of Sec.  250.141.

Issue No. 21: It Is Not Clear Where the Records Required by Proposed 
Sec.  250.918 (Final Sec.  250.903) Must Be Kept

    OOC and Shell maintained that it is not clear where the records 
should be maintained with respect to the proposed Sec.  250.918 
requirements (now in Sec.  250.903) to keep as-built drawings, design 
assumptions and analyses, summary of fabrication and installation 
nondestructive examination records, and inspection results from the 
proposed Sec.  250.916 inspections (now in Sec.  250.919). Again, these 
records should be kept at the same location that the lessee or operator 
specifies in item (j) of the table in final Sec.  250.905. The 
regulatory language in final Sec.  250.903 has been modified to make 
this clear.

Issue 22: Several of the Industry Standards To Be Incorporated Into MMS 
Regulations at Sec.  250.901(a) Are in Conflict With Each Other, and 
MMS Should Stay Involved in the Updating of Industry Standards 
Incorporated by Reference

    OOC submitted the following comments:

    Also we recognize that these industry documents are in many 
cases written as ``stand alone'' documents and that conflicts 
between documents may occur. For example, while reviewing API RP 510 
to determine if it was appropriate to incorporate by reference by 
MMS, it was discovered that in several places it conflicted with API 
RP 14C. Industry, due to the high level of activity in deepwater and 
the limited staff available, has not conducted an exhaustive review 
to determine if conflicts occur between the proposed documents to be 
incorporated and other documents incorporated by reference.
* * *Industry cautions that they have not made an exhaustive review 
of all of the standards to ensure that there are no conflicts 
between the standards. If there are conflicts, these will be 
identified as these standards and codes are applied in conjunction 
with one another.
* * * A number of these recommended practices and standards are in 
the process of being revised to address deepwater facility 
requirements. MMS should stay up-to-date, and where possible 
participate, in the revision of these recommended practices and 
standards, so that new additions of the recommended practices or 
standards can be readily incorporated into the MMS regulations. For 
example, industry notes that there is confusion within API RP 2A, 
21st edition that needs clarification. In at least three sections 
(life safety exposure, consequences of failures, inspection levels) 
of the RP, platforms are divided into Level 1, Level 2 and Level 3 
categories; however, the definitions for Level 1, 2 and 3 are 
different. Therefore, when a platform is generally referred to as a 
Level 1 platform or a Level 3 platform, confusion is created on what 
that means. As API revises the documents to element [sic] the 
confusion, MMS should be involved so they can adopt the changes.

    MMS agrees that the best method for having a working knowledge of 
potential revisions and additions to industry standards is to 
participate in the meetings of the standard setting committees. MMS has 
assigned technical personnel as representatives and alternates to 
various API, International Standards Organization (ISO), American 
Concrete Institute, American Society of Mechanical Engineers, American 
Society for Testing and Materials, American Welding Society, Institute 
of Electronic and Electrical Engineers, National Association of 
Corrosion Engineers, and International Association of Oil and Gas 
Producers committees. MMS also

[[Page 41569]]

monitors the work of other industry standards associations and 
committees.
    MMS agrees that there may be conflicts between the specific 
requirements of some of the industry standards incorporated by 
reference into MMS regulations. Whenever these conflicts are found, MMS 
provides interim clarifications in Notices to Lessees and Operators 
(NTLs). We post these NTLs on the MMS web page. As necessary, MMS 
subsequently makes clarifying revisions to its regulations. Through use 
of these mechanisms, MMS and industry can work through the inevitable 
conflicts that will arise either through contradictory industry 
standards or contradictory Federal standards.

Issue 23: MMS Should Consider Incorporating Several Additional Industry 
Standards Into the MMS Regulations at Sec.  250.901(a)

    Both OOC and Shell recommended that MMS consider adopting API RP 
2I, ``In-Service Inspection of Mooring Hardware for Floating Drilling 
Units.'' OOC further commented:

    In many cases, all or portions of a floating production are 
fabricated outside of the United States and welding standards that 
MMS has deemed for as [sic] equivalent (such as Euronorm) to AWS 
standards for individual projects are used. MMS should either 
consider incorporating by reference these equivalent standards or 
should publish a list of welding standards that they have deemed to 
be equivalent to AWS standards in lieu of each project having to 
obtain approval for utilizing an alternate welding standard.

    MMS agrees that API RP 2I, second edition, would be a valuable 
industry standard to consider for incorporation by reference into 30 
CFR part 250, subparts A and I. API RP 2I is specifically written to 
address the inspection, and potential failure modes, of mooring chain 
and wire rope for MODUs, which frequently move from location to 
location. Moreover, the information provided in API RP 2I on failure 
modes, inspection methods, and repair methods also could be useful in 
the development and implementation of an ISIP plan (Sec.  250.917) for 
other types of offshore floating facilities that remain on station for 
longer periods of time. Based on OOC's and Shell's recommendation, MMS 
reviewed API RP 2I, ``In-Service Inspection of Mooring Hardware for 
Floating Drilling Units,'' and agrees that it should be considered for 
incorporation by reference into 30 CFR Part 250. However, because MMS 
did not initially propose that API RP 2I be incorporated by reference 
during the proposed rulemaking process, we have decided not to 
incorporate it into the final rule. It will be proposed in a subsequent 
rulemaking to provide the regulated community an opportunity to comment 
on its incorporation into 30 CFR Part 250.
    As additional pertinent industry standards are identified or 
developed, MMS will occasionally revise its regulations to incorporate 
certain standards into its regulations in conformance with the 
Administrative Procedure Act. In those instances in which offshore 
facilities, both floating and fixed, are fabricated outside of the 
United States, foreign industry standards must receive prior approval 
in accordance with 30 CFR 250.901(b), which states, ``* * * You may 
also use alternative codes, rules, or standards, as approved by the 
Regional Supervisor, under conditions enumerated in Sec.  250.141, 
paragraphs (a), (b), and (c).'' MMS has not ruled out the incorporation 
by reference of foreign or international standards into its 
regulations. During the past 2 years MMS has incorporated by reference 
one ISO standard into our regulations.

Derivation Table

    The following derivation table shows where the requirements 
originate from in the final 30 CFR part 250, subpart I, regulations.

------------------------------------------------------------------------
            New section                  Previous regulation section
------------------------------------------------------------------------
Sec.   250.900 What general          Sec.   250.900; New requirement.
 requirements apply to all
 platforms?.
Sec.   250.901 What industry         Sec.   250.900(g); Sec.
 standards must your platform meet?.  250.907(b), (c), (d); Sec.
                                      250.908 (b), (c), (d), (e); New
                                      requirements.
Sec.   250.902 What are the          Sec.   250.913 (Subpart Q since May
 requirements for platform removal    17, 2002)
 and location clearance?.
Sec.   250.903 What records must I   Sec.   250.914
 keep?.
Sec.   250.904 What is the Platform  New
 Approval Program?.
Sec.   250.905 How do I get          Sec.   250.901(a), (b)
 approval for the installation,
 modification, or repair of my
 platform?.
Sec.   250.906 What must I do to     Sec.   250.90(b), (c), (d), (e)
 obtain approval for the proposed
 site of my platform?.
Sec.   250.907 Where must I locate   New Requirements.
 foundation boreholes?.
Sec.   250.908 What are the minimum  Sec.   250.907(c)
 structural fatigue design
 requirements?.
Sec.   250.909 What is the Platform  New.
 Verification Program (PVP)?.
Sec.   250.910 Which of my           Sec.   250.902; New requirements.
 facilities are subject to the PVP?.
Sec.   250.911 If my platform is     Sec.   250.902; New requirements.
 subject to the PVP, what must I
 do?.
Sec.   250.912 What plans must I     Sec.   250.902; New requirements.
 submit under the PVP?.
Sec.   250.913 When must I resubmit  Sec.   250.902; New requirements.
 PVP plans?.
Sec.   250.914 How do I nominate a   Sec.   250.902; Sec.   250.903(b)
 CVA?.
Sec.   250.915 What are the CVA's    Sec.   250.903(a)
 primary responsibilities?.
Sec.   250.916 What are the CVA's    Sec.   250.903(a)(1)
 primary duties during the design
 phase?.
Sec.   250.917 What are the CVA's    Sec.   250.903(a)(2)
 primary duties during the
 fabrication phase?.
Sec.   250.918 What are the CVA's    Sec.   250.903(a)(3)
 primary duties during the
 installation phase?.
Sec.   250.919 What in-service       Sec.   250.912(a),(b); New
 inspection requirements must I       requirements.
 meet?.
Sec.   250.920 What are the MMS      New requirements.
 requirements for the assessment of
 platforms?.
Sec.   250.921 How do I analyze my   New requirements.
 platform for cumulative fatigue?.
------------------------------------------------------------------------


[[Page 41570]]

Procedural Matters

Regulatory Planning and Review (Executive Order 12866)

    This document is not a significant rule and is not subject to 
review by OMB under Executive Order 12866.
    (1) This rule will not have an annual effect on the economy of $100 
million or more or adversely affect in a material way the economy, a 
sector of the economy, productivity, competition, jobs, the 
environment, public health or safety, or State, local, or tribal 
governments or communities. The overall effect of this rule will not 
create an adverse effect upon the ability of the United States offshore 
oil and gas industry to compete in the world marketplace, nor will the 
proposal adversely affect investment or employment factors locally. The 
economic analysis prepared for this rule indicates that the estimated 
regulatory costs would be about $3 million for a ``generic'' floating 
platform having 10 production risers, 2 pipeline risers, a mooring 
system, and 80 miles of pipelines. This represents less than 1 percent 
of the total cost of the facility. Assuming that plans for 6 such 
facilities were submitted for approval in any given year, the total 
annual regulatory cost to the offshore oil and gas industry would be 
about $18 million [$3,000,000 x 6 = $18 million]. The economic analysis 
for this rule is available from the Department of the Interior; 
Minerals Management Service; Engineering & Operations Division; Mail 
Stop 4020; 381 Elden Street; Herndon, Virginia 20170-4817; Attention: 
William Hauser.
    (2) This rule will not create inconsistencies with other agencies' 
actions. This rule does not change the relationships of the OCS oil and 
gas leasing program with other agencies' actions. These relationships 
are all encompassed in agreements and memorandums of understanding that 
will not change with this rule.
    (3) This rule does not alter the budgetary effects or entitlements, 
grants, user fees, or loan programs or the rights or obligations of 
their recipients.
    (4) This rule does not raise novel legal or policy issues. There 
are many precedents for regulating offshore production platforms and 
pipelines to promote environmental protection and human safety under 
the OCS Lands Act. While this final rule contains many new regulatory 
requirements for lessees and operators seeking to build new floating 
production facilities, the incorporation of these standards does not 
represent a significant change to industry practices because most of 
these standards are already being utilized by industry.

Regulatory Flexibility (RF) Act

    The DOI certifies that this rule will not have a significant 
economic effect on a substantial number of small entities under the RF 
Act (5 U.S.C. 601 et seq.). The economic analysis prepared for this 
rule concluded that not more than two lessees classified as small 
entities would submit plans for deepwater floating platforms in any 
given year. Most likely, these lessees would be involved as partners in 
a single application for a floating platform. To the extent that these 
lessees participate in such joint ventures, the costs imposed by the 
proposed rule on individual operators would be reduced significantly. 
Therefore, MMS concludes that the rule would not have a significant 
economic impact on a substantial number of small entities.
    For the purposes of this section a ``small entity'' is considered 
to be an individual, limited partnership, or small company, considered 
to be at ``arm's length'' from the control of any parent companies, 
with fewer than 500 employees. Mid-size and large corporations and 
partnerships under their direct control have access to lines of credit 
and internal corporate cash flows that are not available to the ``small 
entity.'' Some of the operators MMS regulates under the OCS oil and gas 
leasing program would be considered small entities. They are generally 
represented by the North American Industry Classification System Code 
211111, which represents crude petroleum and natural gas extractors.
    Of the 98 lessees that have deepwater leases, as many as 26 may be 
considered to be small. These 26 lessees represent about 33 percent of 
all small operators on the OCS. Of the 26, only 2 hold 100-percent 
interest in their deepwater leases. These two lessees have annual 
revenues such that they would have little difficulty in meeting the 
requirements of the proposed rule. In all other cases, the small 
lessees have reduced their deepwater economic risks by being in 
partnership with other lessees. Sixteen of these lessees hold less than 
50 percent interest in their deepwater leases.
    Your comments are important. The Small Business and Agriculture 
Regulatory Enforcement Ombudsman and 10 Regional Fairness Boards were 
established to receive comments from small business about Federal 
agency enforcement actions. The Ombudsman will annually evaluate the 
enforcement activities and rate each agency's responsiveness to small 
business. If you wish to comment on the enforcement actions of MMS, 
call toll-free at (888) 734-3247.

Small Business Regulatory Enforcement Fairness Act (SBREFA)

    This rule is not a major rule under SBREFA (5 U.S.C. 804(2)). This 
rule:
    (a) Does not have an annual effect on the economy of $100 million 
or more.
    (b) Will not cause a major increase in costs or prices for 
consumers, individual industries, Federal, State, or local government 
agencies, or geographic regions.
    (c) Does not have significant adverse effects on competition, 
employment, investment, productivity, innovation, or the ability of 
United States-based enterprises to compete with foreign-based 
enterprises. (Of the 98 lessees who hold leases in deepwater and, 
therefore, could be affected by the proposed rule, 19 are foreign 
multinational corporations.)
    The economic analysis prepared for this rule concluded that not 
more than two small lessees would submit plans for deepwater floating 
platforms in any given year. Most likely, these lessees' involvement 
would be as partners in a single application for a floating platform. 
To the extent that these lessees participate in such joint ventures, 
the costs imposed by the rule on individual operators would be reduced 
significantly. Therefore, MMS concludes that the rule would not have a 
significant economic impact on a substantial number of small entities.

Paperwork Reduction Act (PRA) of 1995

    This rule contains a collection of information that MMS submitted 
to OMB as part of the proposed rulemaking process for review and 
approval under Sec.  3507(d) of the PRA. OMB approved the information 
collection for a total of 37,194 burden hours (OMB control number 1010-
0149). The title of the collection of information for this rule is ``30 
CFR 250, Subparts J, H, and I, Fixed and Floating Platforms and 
Structures.''
    As the information collection requirements in the final rule remain 
unchanged from the proposed rule, a resubmission to OMB for approval of 
the burden normally would not be required prior to publishing these 
final regulations. However, during the period between proposed and 
final rules, the OMB approval of the burden for the proposed collection 
of information was due to expire (March 31, 2005). Also during this 
interim period, the information collection burden for the current 
subpart I regulations (1010-0058) came up for renewal. As required by 
the Paperwork Reduction Act, to renew the current subpart I information

[[Page 41571]]

collection burden, we consulted with several respondents and revised 
the burden estimates and number of responses.
    Where applicable, we incorporated these updated burden adjustments 
in the request that we submitted to OMB to renew the information 
collection burden for the proposed rulemaking (1010-0149). OMB approved 
that renewal for a total of 48,500 hours, with a current expiration 
date of March 31, 2008. However, MMS estimates that this final 
rulemaking will only increase the individual hour burdens approved for 
the current regulations in subpart H (1010-0059), subpart I (1010-
0058), and subpart J (1010-0050), by: 3,300 hours for subpart H; 5,160 
hours for subpart I; 2,700 hours for subpart J; 11,160 total burden 
hour increase.
    The revisions to subpart A of 30 CFR part 250 in this final rule do 
not affect the information collection aspects of those regulations. 
These are currently approved under OMB control numbers 1010-0114.
    Potential respondents are approximately 130 Federal OCS lessees and 
operators and CVAs or other third-party reviewers of fixed and floating 
platforms. Responses are mandatory. The frequency of response varies by 
section, but is primarily on occasion or annual. The IC does not 
include questions of a sensitive nature. MMS will protect information 
considered proprietary according to 30 CFR 250.196, ``Data and 
information to be made available to the public,'' and 30 CFR part 252, 
``OCS Oil and Gas Information Program.''
    MMS will use the information collected and records maintained under 
subpart I to determine the structural integrity of all fixed and 
floating platforms and to ensure that such integrity will be maintained 
throughout the useful life of these structures. The information is 
necessary to determine that platforms and structures are sound and safe 
for their intended purpose and the safety of personnel and pollution 
prevention. MMS will use the information collected under subparts H and 
J to ensure proper construction of production safety systems and 
pipelines.
    When the final regulations take effect, the new information 
collection burdens for subparts H and I will be incorporated with their 
respective collections of information for those current regulations. 
OMB control number 1010-0149 will supersede 1010-0058 and become the 
new control number for the information collection burdens in subpart I. 
Its title will be changed to delete the references to subparts H and J.
    The rule eliminates the notice requirement currently in Sec.  
250.901(e) on transporting the platform to the installation site, and 
the departure request in Sec.  250.912(a) on platform inspection 
intervals. This reporting change results in a decrease of 570 annual 
burden hours.
    The following chart details the IC burden for the approved 
requirements in subparts H and J and all of the requirements in subpart 
I. In the writing of the final rule, burdens have been reassigned to 
new section citations. However, as noted earlier, the burdens 
themselves have remained unchanged from the proposed rule. The new 
citations as well as the citations from the proposed rule are noted 
below.

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                       Hour burden
                                                       Reporting or recordkeeping     per response/                                            Annual
                  Rule sections                               requirement                record           Annual number of  responses          burden
                                                                                         (hours)                                                hours
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                               New Subpart H Requirements
--------------------------------------------------------------------------------------------------------------------------------------------------------
800(b)...........................................  NEW: Submit CVA documentation                50  60 submissions........................         3,000
                                                    under API RP 2RD..
803(b)(2)(iii)...................................  NEW: Submit CVA documentation                50  6 submissions.........................           300
                                                    under API RP 17J..
--------------------------------------------------
                                                                        Subpart I
--------------------------------------------------------------------------------------------------------------------------------------------------------
900(a), (b); 901(b); 903; 905; 906; 907; 909;      Submit application to install new            30  331 applications......................         9,930
 901(c), (d); 912; 913.                             platform or floating production
                                                    facility or significant changes
                                                    to approved applications,
                                                    including use of alternative
                                                    codes, rules, or standards; and
                                                    Platform Verification Program
                                                    plan for design, fabrication and
                                                    installation of new, fixed,
                                                    bottom-founded, pile-supported,
                                                    or concrete-gravity platforms
                                                    and new floating platforms.
                                                    Consult as required with MMS and/
                                                    or USCG. Re/Submit application
                                                    for major modification(s)/
                                                    repair(s) to any platform and
                                                    related requirements.
900(b)(5)........................................  Submit application for conversion            24  30 applications.......................           720
                                                    of the use of an existing mobile
                                                    offshore drilling unit..
900(c)...........................................  Notify MMS/USCG within 24 hours              16  9 notices/requests....................           144
                                                    of damage and emergency repairs
                                                    and request approval of repairs..
901(a)(6), (a)(7), (a)(8)........................  NEW: Submit CVA documentation               100  6 submissions.........................           600
                                                    under API RP 2RD, API RP 2SK,
                                                    and API RP 2SM..
901(a)(10).......................................  NEW: Submit hazards analysis                600  6 submissions.........................         3,600
                                                    documentation under API RP 14J..
903 *............................................  Record original and relevant                100  136 lessees...........................        13,600
                                                    material test results of all
                                                    primary structural materials;
                                                    retain records during all stages
                                                    of construction. Compile,
                                                    retain, and make available to
                                                    MMS for the functional life of
                                                    platform, the as-built drawings,
                                                    design assumptions/analyses,
                                                    summary of nondestructive
                                                    examination records, and
                                                    inspection results..
911(c), (d), (f); 917............................  Submit interim and final CVA                100  6 submissions.........................           600
                                                    reports and recommendations on
                                                    fabrication phase, including
                                                    notice of fabrication procedure
                                                    changes or design specification
                                                    modifications..

[[Page 41572]]

 
914..............................................  Submit nomination and                        16  21 nominations........................           336
                                                    qualification statement for CVA..
916..............................................  Submit interim and final CVA                200  31 reports............................         6,200
                                                    reports and recommendations on
                                                    design phase..
918..............................................  Submit interim and final CVA                 60  6 submissions.........................           360
                                                    reports and recommendations on
                                                    installation phase..
919..............................................  Develop in-service inspection            GOM 45  130 lessees...........................         5,850
                                                    plan and submit annual (November       POCS 80  6 operators...........................           480
                                                    1 of each year) report on
                                                    inspection of platforms or
                                                    floating production facilities,
                                                    including summary of testing
                                                    results..
900 thru 921.....................................  General departure and alternative             8  10 requests...........................            80
                                                    compliance requests not
                                                    specifically covered elsewhere
                                                    in Subpart I regulations..
--------------------------------------------------
                                                               New Subpart J Requirements
--------------------------------------------------------------------------------------------------------------------------------------------------------
1002(b)(5).......................................  NEW: Submit CVA documentation                75  12 submissions........................           900
                                                    under API RP 2RD..
1007(4)(iii), (iv)...............................  NEW: Submit CVA documentation               150  12 submissions........................         1,800
                                                    under API RP 17J..
    Total Hour Burden............................  .................................  ............  818...................................       48,500
--------------------------------------------------------------------------------------------------------------------------------------------------------
* The records required to be retained are such that respondents would keep them as usual and customary business practice. The burden would be to make
  them available to MMS for review.

    A Federal agency may not conduct or sponsor, and a person is not 
required to respond to, a collection of information unless it displays 
a currently valid OMB control number. The public may comment, at any 
time, on the accuracy of the information collection burden in this rule 
and may submit any comments to the Department of the Interior; Minerals 
Management Service; Attention: Rules Processing Team; Mail Stop 4024; 
381 Elden Street; Herndon, Virginia 20170-4817. If you wish to email 
your comments to MMS, the address is: [email protected]. You may 
also submit comments on the burdens through https://ocsconnect.mms.gov.

Federalism (Executive Order 13132)

    According to Executive Order 13132, this rule does not have 
federalism implications. This rule would not substantially or directly 
affect the relationship between the Federal and State governments, 
because it deals strictly with technical standards that the offshore 
oil and gas industry must use in designing, fabricating, and installing 
floating offshore facilities. This rule would not impose costs on 
States or localities, nor would it require any action on the part of 
States or localities.

Takings Implications Assessment (Executive Order 12630)

    According to Executive Order 12630, the rule does not have 
significant takings implications. A Takings Implication Assessment is 
not required. Based on our Paperwork Burden analysis and our economic 
analysis for this rule, the annual incremental cost of complying with 
this regulation for approximately 98 businesses will be about $37,194 
per business, per year. This incremental cost will be absorbed by an 
industry sector where (1) operating costs just for a contract drilling 
unit to drill a single well can exceed $1,750,000 per week, and (2) the 
cost of a deepwater platform can exceed $1 billion. MMS does not 
believe that paying this cost will result in any takings. Thus, the DOI 
does not need to prepare a Takings Implication Assessment under 
Executive Order 12630, Governmental Actions and Interference with 
Constitutionally Protected Property Rights. The rule would not take 
away or restrict a lessee's right to develop an OCS oil and gas lease 
according to the lease terms.

Energy Supply, Distribution, or Use (Executive Order 13211)

    This rule is not a significant rule and is not subject to review by 
OMB under Executive Order 13211. The rule does not have a significant 
effect on energy supply, distribution, or use, because it would 
streamline the regulatory review process and thereby enhance the 
development and production of energy resources from deepwater areas of 
the OCS. It would do this by specifying a single body of approved 
industry standards so that lessees would know in advance which design 
criteria are acceptable to MMS for deepwater production operations. The 
rule would also simplify MMS engineers' efforts in reviewing each new 
project to ensure structural integrity, operational and human safety, 
and environmental protection. This would be beneficial for increasing 
energy resources and would provide more certainty to OCS lessees who 
assume the high financial risks of developing deepwater areas.

Civil Justice Reform (Executive Order 12988)

    According to Executive Order 12988, the Office of the Solicitor has 
determined that this rule does not unduly burden the judicial system 
and meets the requirements of Sections 3(a) and 3(b)(2) of the Order.

National Environmental Policy Act (NEPA)

    This rule does not constitute a major Federal action significantly 
affecting the quality of the human environment. MMS has analyzed this 
rule under the criteria of the NEPA and 516 Departmental Manual 6, 
Appendix 10.4C(1). MMS completed a Categorical Exclusion Review for 
this action on November 20, 2000, and concluded that ``the rulemaking 
does not represent an exception to the established criteria for 
categorical exclusion; therefore, preparation of an environmental 
analysis or environmental impact statement will not be required.''

Unfunded Mandate Reform Act (UMRA) of 1995

    This rule does not impose an unfunded mandate on State, local, or 
tribal governments or the private sector of more than $100 million per 
year. The rule does not have a significant or unique effect on State, 
local or tribal governments or the private sector. A statement 
containing the information

[[Page 41573]]

required by the UMRA (2 U.S.C. 1531 et seq.) is not required.

Consultation and Coordination With Indian Tribal Governments (Executive 
Order 13175)

    In accordance with Executive Order 13175, this rule does not have 
tribal implications that impose substantial direct compliance costs on 
Indian tribal governments.

List of Subjects in 30 CFR Part 250

    Continental shelf, Environmental impact statements, Environmental 
protection, Government contracts, Incorporation by reference, 
Investigations, Mineral royalties, Oil and gas development and 
production, Oil and gas exploration, Oil and gas reserves, Penalties, 
Pipelines, Public lands--mineral resources, Public lands--rights-of-
way, Reporting and recordkeeping requirements, Sulphur development and 
production, Sulphur exploration, Surety bonds.

    Dated: June 22, 2005.
Chad Calvert,
Acting Assistant Secretary--Land and Minerals Management.

0
For the reasons stated in the preamble, the MMS amends 30 CFR part 250 
as follows:

PART 250--OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER 
CONTINENTAL SHELF

0
1. The authority citation for part 250 continues to read as follows:

    Authority: 43 U.S.C. 1331, et seq.


0
2. In Sec.  250.105, the definition for ``Facility'' is revised to read 
as follows:


Sec.  250.105  Definitions.

* * * * *
    Facility means:
    (1) As used in Sec.  250.130, all installations permanently or 
temporarily attached to the seabed on the OCS (including manmade 
islands and bottom-sitting structures). They include mobile offshore 
drilling units (MODUs) or other vessels engaged in drilling or downhole 
operations, used for oil, gas or sulphur drilling, production, or 
related activities. They include all floating production systems 
(FPSs), variously described as column-stabilized-units (CSUs); floating 
production, storage and offloading facilities (FPSOs); tension-leg 
platforms (TLPs); spars, etc. They also include facilities for product 
measurement and royalty determination (e.g. lease Automatic Custody 
Transfer Units, gas meters) of OCS production on installations not on 
the OCS. Any group of OCS installations interconnected with walkways, 
or any group of installations that includes a central or primary 
installation with processing equipment and one or more satellite or 
secondary installations is a single facility. The Regional Supervisor 
may decide that the complexity of the individual installations 
justifies their classification as separate facilities.
    (2) As used in Sec.  250.303, means all installations or devices 
permanently or temporarily attached to the seabed. They include mobile 
offshore drilling units (MODUs), even while operating in the ``tender 
assist'' mode (i.e. with skid-off drilling units) or other vessels 
engaged in drilling or downhole operations. They are used for 
exploration, development, and production activities for oil, gas, or 
sulphur and emit or have the potential to emit any air pollutant from 
one or more sources. They include all floating production systems 
(FPSs), including column-stabilized-units (CSUs); floating production, 
storage and offloading facilities (FPSOs); tension-leg platforms 
(TLPs); spars, etc. During production, multiple installations or 
devices are a single facility if the installations or devices are at a 
single site. Any vessel used to transfer production from an offshore 
facility is part of the facility while it is physically attached to the 
facility.
    (3) As used in Sec.  250.490(b), means a vessel, a structure, or an 
artificial island used for drilling, well completion, well-workover, or 
production operations.
    (4) As used in Sec. Sec.  250.900 through 250.921, means all 
installations or devices permanently or temporarily attached to the 
seabed. They are used for exploration, development, and production 
activities for oil, gas, or sulphur and emit or have the potential to 
emit any air pollutant from one or more sources. They include all 
floating production systems (FPSs), including column-stabilized-units 
(CSUs); floating production, storage and offloading facilities (FPSOs); 
tension-leg platforms (TLPs); spars, etc. During production, multiple 
installations or devices are a single facility if the installations or 
devices are at a single site. Any vessel used to transfer production 
from an offshore facility is part of the facility while it is 
physically attached to the facility.
* * * * *

0
3. In Sec.  250.198, in the table in paragraph (e), the following 
changes are made:
0
A. Add entries in alphanumerical order for API RP 2FPS, API RP 2RD, API 
RP 2SK, API RP 2SM, API RP 2T, API RP 14J, API Spec 17J, and AWS 
D3.6M:1999 as set forth below;
0
B. Revise entries for ACI Standard 318-95, ACI 357R-84, AISC Standard 
Specification for Structural Steel Buildings, API RP 2A-WSD, ASTM 
Standard C 33-99a, ASTM Standard C 94/C 94M-99, ASTM Standard C 150-99, 
ASTM Standard C 330-99, ASTM Standard C 595-98, AWS D1.1-96, AWS D1.4-
79, NACE Standard MR0175-99 and NACE Standard RP 01-76-94.


Sec.  250.198  Documents incorporated by reference.

* * * * *
    (e) * * *

------------------------------------------------------------------------
         Title of documents              Incorporated by reference at
------------------------------------------------------------------------
ACI Standard 318-95, Building Code   Sec.   250.901(a)(1)
 Requirements for Reinforced
 Concrete, plus Commentary on
 Building Code Requirements for
 Reinforced Concrete (ACI 318R-95).
ACI 357R-84, Guide for the Design    Sec.   250.901(a)(2)
 and Construction of Fixed Offshore
 Concrete Structures, 1984.
AISC Standard Specification for      Sec.   250.901(a)(3)
 Structural Steel Buildings,
 Allowable Stress Design and
 Plastic Design, June 1, 1989, with
 Commentary.
 
                              * * * * * * *
API RP 2A-WSD, Recommended Practice  Sec.   250.901(a)(4); Sec.
 for Planning, Designing, and         250.908(a); Sec.
 Constructing Fixed Offshore          250.920(a)(b)(c)(e)
 Platforms--Working Stress Design;
 Twenty-first Edition, December
 2000, API Order No. G2AWSD.
 

[[Page 41574]]

 
                              * * * * * * *
API RP 2FPS, Recommended Practice    Sec.   250.901(a)(5)
 for Planning, Designing, and
 Constructing Floating Production
 Systems, First Edition, March
 2001, API Order No. G2FPS1.
API RP 2RD, Design of Risers for     Sec.   250.800(b); Sec.
 Floating Production Systems (FPSs)   250.901(a)(6); Sec.
 and Tension-Leg Platforms (TLPs),    250.1002(b)(5)
 First Edition, June 1998, API
 Order No. G02RD1.
API RP 2SK, Recommended Practice     Sec.   250.800(b); Sec.
 for Design and Analysis of           250.901(a)(7)
 Stationkeeping Systems for
 Floating Structures, Second
 Edition, December 1996, Effective
 Date: March 1, 1997, API Order No.
 G02SK2.
API RP 2SM, Recommended Practice     Sec.   250.901(a)(8)
 for Design, Manufacture,
 Installation, and Maintenance of
 Synthetic Fiber Ropes for Offshore
 Mooring, First Edition, March
 2001, API Order No. G02SM1.
API RP 2T, Planning, Designing and   Sec.   250.901(a)(9)
 Constructing Tension Leg
 Platforms, Second Edition, August
 1997, API Order No. G02T02.
 
                              * * * * * * *
API RP 14J, Recommended Practice     Sec.   250.800(b); Sec.
 for Design and Hazards Analysis      250.901(a)(10)
 for Offshore Production
 Facilities, Second Edition, May
 2001, API Order No. G14J02.
 
                              * * * * * * *
API Spec 17J, Specification for      Sec.   250.803(b)(2)(iii); Sec.
 Unbonded Flexible Pipe, Second       250.1002(b)(4); Sec.
 Edition, November 1999, including    250.1007(a)(4)
 errata (May 25, 2001) and Addendum
 1 (June 2003), Effective Date:
 December 2002, API Order No.
 G17J02.
 
                              * * * * * * *
ASTM Standard C 33-99a, Standard     Sec.   250.901(a)(11)
 Specification for Concrete
 Aggregates.
ASTM Standard C 94/C 94M-99,         Sec.   250.901(a)(12)
 Standard Specification for Ready-
 Mixed Concrete.
ASTM Standard C 150-99, Standard     Sec.   250.901(a)(13)
 Specification for Portland Cement.
ASTM Standard C 330-99, Standard     Sec.   250.901(a)(14)
 Specification for Lightweight
 Aggregates for Structural Concrete.
ASTM Standard C 595-98, Standard     Sec.   250.901(a)(15)
 Specification for Blended
 Hydraulic Cements.
AWS D1.1-96, Structural Welding      Sec.   250.901(a)(16)
 Code--Steel, 1996, including
 Commentary.
AWS D1.4-79, Structural Welding      Sec.   250.901(a)(17)
 Code--Reinforcing Steel, 1979.
AWS D3.6M:1999, Specification for    Sec.   250.901(a)(18)
 Underwater Welding.
NACE Standard MR0175-99, Sulfide     Sec.   250.901(a)(19)
 Stress Cracking Resistant Metallic
 Materials for Oilfield Equipment,
 Revised January 1999, NACE Item
 No. 21302.
NACE Standard RP 01-76-94, Standard  Sec.   250.901(a)(20)
 Recommended Practice, Corrosion
 Control of Steel Fixed Offshore
 Platforms Associated with
 Petroleum Production.
------------------------------------------------------------------------


0
4. In Sec.  250.199, in paragraph (e), the heading of the first column, 
and the first column in paragraph (e)(8) are revised to read as 
follows:


Sec.  250.199  Paperwork Reduction Act statements--information 
collection.

* * * * *
    (e) * * *

------------------------------------------------------------------------
   30 CFR 250 subpart/title (OMB      Reasons for collecting information
          control number)                        and how used
------------------------------------------------------------------------
 
                              * * * * * * *
(8) Subpart I, Platforms and
 Structures (1010-0149).
 
                              * * * * * * *
------------------------------------------------------------------------


0
5. In Sec.  250.800, the existing text is redesignated as paragraph 
(a), and a new paragraph (b) is added to read as follows:


Sec.  250.800  General requirements.

* * * * *
    (b) For all new floating production systems (FPSs) (e.g., column-
stabilized-units (CSUs); floating production, storage and offloading 
facilities (FPSOs); tension-leg platforms (TLPs); spars, etc.), you 
must do all of the following:
    (1) Comply with API RP 14J (incorporated by reference as specified 
in 30 CFR 250.198);
    (2) Meet the drilling and production riser standards of API RP 2RD 
(incorporated by reference as specified in 30 CFR 250.198);
    (3) Design all stationkeeping systems for floating facilities to 
meet the standards of API RP 2SK (incorporated by reference as 
specified in 30 CFR

[[Page 41575]]

250.198), as well as relevant U.S. Coast Guard regulations; and
    (4) Design stationkeeping systems for floating facilities to meet 
structural requirements in subpart I, Sec. Sec.  250.900 through 
250.921 of this part.

0
6. In Sec.  250.803, paragraph (a) is revised and paragraph (b)(2)(iii) 
is added to read as follows:


Sec.  250.803  Additional production system requirements.

    (a) For all production platforms, you must comply with the 
following production safety system requirements, in addition to the 
requirements of Sec.  250.802 of this subpart and the requirements of 
API RP 14C (incorporated by reference as specified in 30 CFR 250.198).
    (b) * * *
    (2) * * *
    (iii) If you are installing flowlines constructed of unbonded 
flexible pipe on a floating platform, you must:
    (A) Review the manufacturer's Design Methodology Verification 
Report and the independent verification agent's (IVA's) certificate for 
the design methodology contained in that report to ensure that the 
manufacturer has complied with the requirements of API Spec 17J 
(incorporated by reference as specified in 30 CFR 250.198);
    (B) Determine that the unbonded flexible pipe is suitable for its 
intended purpose on the lease or pipeline right-of-way;
    (C) Submit to the MMS District Supervisor the manufacturer's design 
specifications for the unbonded flexible pipe; and
    (D) Submit to the MMS District Supervisor a statement certifying 
that the pipe is suitable for its intended use and that the 
manufacturer has complied with the IVA requirements of API Spec 17J 
(incorporated by reference as specified in 30 CFR 250.198).
* * * * *

0
7. Subpart I is revised to read as follows:
Subpart I--Platforms and Structures

General Requirements for Platforms

Sec.
250.900 What general requirements apply to all platforms?
250.901 What industry standards must your platform meet?
250.902 What are the requirements for platform removal and location 
clearance?
250.903 What records must I keep?

Platform Approval Program

250.904 What is the Platform Approval Program?
250.905 How do I get approval for the installation, modification, or 
repair of my platform?
250.906 What must I do to obtain approval for the proposed site of 
my platform?
250.907 Where must I locate foundation boreholes?
250.908 What are the minimum structural fatigue design requirements?

Platform Verification Program

250.909 What is the Platform Verification Program?
250.910 Which of my facilities are subject to the Platform 
Verification Program?
250.911 If my platform is subject to the Platform Verification 
Program, what must I do?
250.912 What plans must I submit under the Platform Verification 
Program?
250.913 When must I resubmit Platform Verification Program plans?
250.914 How do I nominate a CVA?
250.915 What are the CVA's primary responsibilities?
250.916 What are the CVA's primary duties during the design phase?
250.917 What are the CVA's primary duties during the fabrication 
phase?
250.918 What are the CVA's primary duties during the installation 
phase?

Inspection, Maintenance, and Assessment of Platforms

250.919 What in-service inspection requirements must I meet?
250.920 What are the MMS requirements for assessment of platforms?
250.921 How do I analyze my platform for cumulative fatigue?

Subpart I--Platforms and Structures

General Requirements for Platforms


Sec.  250.900  What general requirements apply to all platforms?

    (a) You design, fabricate, install, use, maintain, inspect, and 
assess all platforms and related structures on the Outer Continental 
Shelf (OCS) so as to ensure their structural integrity for the safe 
conduct of drilling, workover, and production operations. In doing 
this, you must consider the specific environmental conditions at the 
platform location.
    (b) You must also submit an application under Sec.  250.905 of this 
subpart and obtain the approval of the Regional Supervisor before 
performing any of the activities described in the following table:

----------------------------------------------------------------------------------------------------------------
  Activity requiring application and approval                 Conditions for conducting the activity
----------------------------------------------------------------------------------------------------------------
(1) Install a platform. This includes placing a  (i) You must adhere to the requirements of this subpart,
 newly constructed platform at a location or      including the industry standards in Sec.   250.901.
 moving an existing platform to a new site.      (ii) If you are installing a floating platform, you must also
                                                  adhere to U.S. Coast Guard (USCG) regulations for the
                                                  fabrication, installation, and inspection of floating OCS
                                                  facilities.
(2) Major modficatiion to any platform. This     (i) You must adhere to the requirements of this subpart,
 including any structural changes that            including the industry standards in Sec.   250.901.
 materially alter the approval plan or cause a   (ii) Before you make a major modification to a floating
 major deviation from approved operations and     platform, you must obtain approval from both the MMS and the
 any modification that increases loading on a     USCG for the modification.
 platform by 10 percent or more.
(3) Major repair of damage to any platform.      (i) You must adhere to the requirements of this subpart,
 This includes any corrective operations          including the industry standards in Sec.   250.901.
 involving structural members affecting the      (ii) Before you make a major repair to a floating platform, you
 structural integrity of a portion or all of      must obtain approval from both the MMS and the USCG for the
 the platform.                                    repair.
(4) Convert an existing platform at the current  (i) The Regional Supervisor will determine on a case-by-case
 location for a new purpose.                      basis the requirements for an application for conversion of an
                                                  existing platform at the current location.
                                                 (ii) At a minimum, your application must include: the converted
                                                  platform's intended use; and a demonstration of the adequacy
                                                  of the design and structural condition of the converted
                                                  platform.
                                                 (iii) If a floating platform, you must also adhere to USCG
                                                  regulations for the fabrication, installation, and inspection
                                                  of floating OCS facilities.

[[Page 41576]]

 
(5) Convert an existing mobile offshore          (i) The Regional Supervisor will determine on a case-by-case
 drilling unit (MODU) for a new purpose.          basis the requirements for an application for conversion of an
                                                  existing MODU.
                                                 (ii) At a minimum, your application must include: the converted
                                                  MODU's intended location and use; a demonstration of the
                                                  adequacy of the design and structural condition of the
                                                  converted MODU; and a demonstration that the level of safety
                                                  for the converted MODU is at least equal to that of re-used
                                                  platforms.
                                                 (iii) You must also adhere to USCG regulations for the
                                                  fabrication, installation, and inspection of floating OCS
                                                  facilities.
----------------------------------------------------------------------------------------------------------------

    (c) Under emergency conditions, you may make repairs to primary 
structural elements to restore an existing permitted condition without 
an application or prior approval. You must notify the Regional 
Supervisor of the damage that occurred within 24 hours, and you must 
notify the Regional Supervisor of the repairs that were made within 24 
hours of completing the repairs. If you make emergency repairs on a 
floating platform, you must also notify the USCG.
    (d) You must determine if your new platform or major modification 
to an existing platform is subject to the Platform Verification Program 
(PVP). Section 250.910 of this subpart fully describes the facilities 
that are subject to the PVP. If you determine that your platform is 
subject to the PVP, you must follow the requirements of Sec. Sec.  
250.909-250.918 of this subpart.
    (e) MMS will cancel your approved platform installation permits one 
year after the approval is granted if the platform is not installed. If 
MMS cancels your permit approval, you must resubmit your application.


Sec.  250.901  What industry standards must your platform meet?

    (a) In addition to the other requirements of this subpart, your 
plans for platform design, analysis, fabrication, installation, use, 
maintenance, inspection and assessment must, as appropriate, conform 
to:
    (1) American Concrete Institute (ACI) Standard 318, Building Code 
Requirements for Reinforced Concrete, plus Commentary, (incorporated by 
reference as specified in Sec.  250.198);
    (2) ACI 357R, Guide for the Design and Construction of Fixed 
Offshore Concrete Structures, (incorporated by reference as specified 
in Sec.  250.198);
    (3) American Institute of Steel Construction (AISC) Standard 
Specification for Structural Steel Buildings, Allowable Stress Design 
and Plastic Design, with Commentary, (incorporated by reference as 
specified in Sec.  250.198);
    (4) American Petroleum Institute (API) Recommended Practice (RP) 
2A--WSD, Recommended Practice for Planning, Designing, and Constructing 
Fixed Offshore Platforms-Working Stress Design, (incorporated by 
reference as specified in Sec.  250.198);
    (5) API RP 2FPS, Recommended Practice for Planning, Designing, and 
Constructing Floating Production Systems, (incorporated by reference as 
specified in Sec.  250.198);
    (6) API RP 2RD, Design of Risers for Floating Production Systems 
(FPSs) and Tension-Leg Platforms (TLPs), (incorporated by reference as 
specified in Sec.  250.198);
    (7) API RP 2SK, Recommended Practice for Design and Analysis of 
Station Keeping Systems for Floating Structures, (incorporated by 
reference as specified in Sec.  250.198);
    (8) API RP 2SM, Recommended Practice for Design, Manufacture, 
Installation, and Maintenance of Synthetic Fiber Ropes for Offshore 
Mooring, (incorporated by reference as specified in Sec.  250.198);
    (9) API RP 2T, Recommended Practice for Planning, Designing and 
Constructing Tension Leg Platforms, (incorporated by reference as 
specified in Sec.  250.198);
    (10) API RP 14J, Recommended Practice for Design and Hazards 
Analysis for Offshore Production Facilities, (incorporated by reference 
as specified in Sec.  250.198);
    (11) American Society for Testing and Materials (ASTM) Standard C 
33-99a, Standard Specification for Concrete Aggregates, (incorporated 
by reference as specified in Sec.  250.198);
    (12) ASTM Standard C 94/C 94M-99, Standard Specification for Ready-
Mixed Concrete, (incorporated by reference as specified in Sec.  
250.198);
    (13) ASTM Standard C 150-99, Standard Specification for Portland 
Cement, (incorporated by reference as specified in Sec.  250.198);
    (14) ASTM Standard C 330-99, Standard Specification for Lightweight 
Aggregates for Structural Concrete, (incorporated by reference as 
specified in Sec.  250.198);
    (15) ASTM Standard C 595-98, Standard Specification for Blended 
Hydraulic Cements, (incorporated by reference as specified in Sec.  
250.198);
    (16) AWS D1.1, Structural Welding Code--Steel, including 
Commentary, (incorporated by reference as specified in Sec.  250.198);
    (17) AWS D1.4, Structural Welding Code--Reinforcing Steel, 
(incorporated by reference as specified in Sec.  250.198);
    (18) AWS D3.6M, Specification for Underwater Welding, (incorporated 
by reference as specified in Sec.  250.198);
    (19) NACE Standard MR0175, Sulfide Stress Cracking Resistant 
Metallic Materials for Oilfield Equipment, (incorporated by reference 
as specified in Sec.  250.198);
    (20) NACE Standard RP 01-76-94, Standard RP, Corrosion Control of 
Steel Fixed Offshore Platforms Associated with Petroleum Production, 
(incorporated by reference as specified in Sec.  250.198).
    (b) You must follow the requirements contained in the documents 
listed under paragraph (a) of this section insofar as they do not 
conflict with other provisions of 30 CFR Part 250. You may use 
applicable provisions of these documents, as approved by the Regional 
Supervisor, for the design, fabrication, and installation of platforms 
such as spars, since standards specifically written for such structures 
do not exist. You may also use alternative codes, rules, or standards, 
as approved by the Regional Supervisor, under the conditions enumerated 
in Sec.  250.141.
    (c) For information on the standards mentioned in this section, and 
where they may be obtained, see Sec.  250.198 of this part.
    (d) The following chart summarizes the applicability of the 
industry standards listed in this section for fixed and floating 
platforms:

----------------------------------------------------------------------------------------------------------------
            Industry standard                                       Applicable to . . .
----------------------------------------------------------------------------------------------------------------
ACI Standard 318, Building Code           Fixed and floating platform, as appropriate.
 Requirements for Reinforced Concrete,
 Plus Commentary;.

[[Page 41577]]

 
AISC Standard Specification for
 Structural Steel Buildings, Allowable
 Stress Design and Plastic Design;.
ASTM Standard C33-99a, Standard
 Specification for Concrete Aggregates;.
ASTM Standard C94/C94M-99, Standard
 Specification for Ready-Mixed Concrete;.
ASTM Standard C150-99, Standard
 Specification for Portland Cement;.
ASTM Standard C330-99, Standard
 Specification for Lightweight
 Aggregates for Structural Concrete;.
ASTM Standard C 595-98, Standard
 Specification for Blended Hydraulic
 Cements;.
AWS D1.1, Structural Welding Code--
 Steel;.
AWS D1.4, Structural Welding Code--
 Reinforcing Steel;.
AWS D3.6M, Specification for Underwater
 Welding;.
NACE Standard RP 01-76-94, Standard
 Recommended Practice (RP), Corrosion
 Control of Steel Fixed Offshore
 Platforms Associated with Petroleum
 Production;.
API RP 2A--WSD, RP for Planning,
 Designing, and Constructing Fixed
 Offshore Platforms--Working Stress
 Design;.
ACI357R, Guide for the Design and         Fixed platforms.
 Construction of Fixed Offshore Concrete
 Structures;.
API RP 14J, RP for Design and Hazards     Floating platforms.
 Analysis for Offshore Production
 Facilities;.
API RP 2FPS, RP for Planning, Designing,
 and Constructing, Floating Production
 Systems;.
API RP 2RD, Design of Risers for
 Floating Production Systems (FPSs) and
 Tension-Leg Platforms (TLPs);.
API RP 2SK, RP for Design and Analysis
 of Station Keeping Systems for Floating
 Structures;.
API RP 2T, RP for Planning, Designing,
 and Constructing Tension Leg Platforms;.
API RP 2SM, RP for Design, Manufacture,
 Installation, and Maintenance of
 Synthetic Fiber Ropes for Offshore
 Mooring.
----------------------------------------------------------------------------------------------------------------

Sec.  250.902  What are the requirements for platform removal and 
location clearance?

    You must remove all structures according to Sec. Sec.  250.1725 
through 250.1730 of Subpart Q--Decommissioning Activities of this part.


Sec.  250.903  What records must I keep?

    (a) You must compile, retain, and make available to MMS 
representatives for the functional life of all platforms:
    (1) The as-built drawings;
    (2) The design assumptions and analyses;
    (3) A summary of the fabrication and installation nondestructive 
examination records;
    (4) The inspection results from the inspections required by Sec.  
250.919 of this subpart; and
    (5) Records of repairs not covered in the inspection report 
submitted under Sec.  250.919(b).
    (b) You must record and retain the original material test results 
of all primary structural materials during all stages of construction. 
Primary material is material that, should it fail, would lead to a 
significant reduction in platform safety, structural reliability, or 
operating capabilities. Items such as steel brackets, deck stiffeners 
and secondary braces or beams would not generally be considered primary 
structural members (or materials).
    (c) You must provide MMS with the location of these records in the 
certification statement of your application for platform approval as 
required in Sec.  250.905(j).

Platform Approval Program


Sec.  250.904  What is the Platform Approval Program?

    (a) The Platform Approval Program is the MMS basic approval process 
for platforms on the OCS. The requirements of the Platform Approval 
Program are described in Sec. Sec.  250.904 through 250.908 of this 
subpart. Completing these requirements will satisfy MMS criteria for 
approval of fixed platforms of a proven design that will be placed in 
the shallow water areas (<= 400 ft.) of the Gulf of Mexico OCS.
    (b) The requirements of the Platform Approval Program must be met 
by all platforms on the OCS. Additionally, if you want approval for a 
floating platform; a platform of unique design; or a platform being 
installed in deepwater (> 400 ft.) or a frontier area, you must also 
meet the requirements of the Platform Verification Program. The 
requirements of the Platform Verification Program are described in 
Sec. Sec.  250.909 through 250.918 of this subpart.


Sec.  250.905  How do I get approval for the installation, 
modification, or repair of my platform?

    The Platform Approval Program requires that you submit the 
environmental and structural information in the following table for 
your proposed project.

----------------------------------------------------------------------------------------------------------------
         Required documents                           Required contents                    Other requirements
----------------------------------------------------------------------------------------------------------------
(a) Application cover letter........  Proposed structure designation, lease number,     You must submit three
                                       area, name, and block number, and the type of     copies. If, your
                                       facility your facility (e.g., drilling,           facility is subject to
                                       production, quarters). The structure              the Platform
                                       designation must be unique for the field (some    Verficiation Program
                                       fields are made up of several blocks); i.e.       (PVP), you must submit
                                       once a platform ``A'' has been used in the        four copies.
                                       field there should never be another platform
                                       ``A'' even if the old platform ``A'' has been
                                       removed. Single well free standing caissons
                                       should be given the same designation as the
                                       well. All other structures are to be designated
                                       by letter designations.
(b) Location plat...................  Latitude and longitude coordinates, Universal     Your plat must be drawn
                                       Mercator grid-system coordinates, state plane     to a scale of 1 inch
                                       coordinates in the Lambert or Transverse          equals 2,000 feet and
                                       Mercator Projection System, and distances in      include the coordinates
                                       feet from the nearest block lines. These          of the lease block
                                       coordinates must be based on the NAD (North       boundary lines. You
                                       American Datum) 27 datum plane coordinate         must submit three
                                       system.

[[Page 41578]]

 
(c) Front, Side, and Plan View        Platform dimensions and orientation, elevations   Your drawing sizes must
 drawings.                             relative to M.L.L.W. (Mean Lower Low Water),      not exceed 11'' x 17''.
                                       and pile sizes and penetration.                   You must submit three
                                                                                         copies (four copies for
                                                                                         PVP applications).
(d) Complete set of structural        The approved for construction fabrication         Your drawing sizes must
 drawings.                             drawings should be submitted including; e.g.      not exceed 11'' x 17''.
                                       cathodic protection systems; jacket design;       You must submit one
                                       pile foundations; drilling, production, and       copy.
                                       pipeline risers and riser tensioning systems;
                                       turrets and turret-and-hull interfaces; mooring
                                       and tethering systems; foundations and
                                       anchoring systems.
(e) Summary of environmental data...  A summary of the environmental data described in  You must submit one
                                       the applicable standards referenced under Sec.    copy.
                                        250.901(a) of this subpart and in Sec.
                                       250.198 of Subpart A, where the data is used in
                                       the design or analysis of the platform.
                                       Examples of relevant data include information
                                       on waves, wind, current, tides, temperature,
                                       snow and ice effects, marine growth, and water
                                       depth.
(f) Summary of the engineering        Loading information (e.g., live, dead,            You must submit one
 design data.                          environmental), structural information (e.g.,     copy.
                                       design-life; material types; cathodic
                                       protection systems; design criteria; fatigue
                                       life; jacket design; deck design; production
                                       component design; pile foundations; drilling,
                                       production, and pipeline risers and riser
                                       tensioning systems; turrets and turret-and-hull
                                       interfaces; foundations, foundation pilings and
                                       templates, and anchoring systems; mooring or
                                       tethering systems; fabrication and installation
                                       guidelines), and foundation information (e.g.,
                                       soil stability, design criteria).
(g) Project-specific studies used in  All studies pertinent to platform design or       You must submit one copy
 the platform design or installation.  installation, e.g., oceanographic and/or soil     of each study.
                                       reports including the overall site
                                       investigative report required in section
                                       250.906.
(h) Description of the loads imposed  Loads imposed by jacket; decks; production        You must submit one
 on the facility.                      components; drilling, production, and pipeline    copy.
                                       risers, and riser tensioning systems; turrets
                                       and turret-and-hull interfaces; foundations,
                                       foundation pilings and templates, and anchoring
                                       systems; and mooring or tethering systems.
(i) A copy of the in-service          This plan is described in Sec.   250.919........  You must submit one
 inspection plan.                                                                        copy.
(j) Certification statement.........  The following statement: ``The design of this     An authorized company
                                       structure has been certified by a recognized      representative must
                                       classification society, or a registered civil     sign the statement. You
                                       or structural engineer or equivalent, or a        must submit one copy.
                                       naval architect or marine engineer or
                                       equivalent, specializing in the design of
                                       offshore structures. The certified design and
                                       as-built plans and specifications will be on
                                       file at (give location)''.
----------------------------------------------------------------------------------------------------------------

Sec.  250.906  What must I do to obtain approval for the proposed site 
of my platform?

    (a) Shallow hazards surveys. You must perform a high-resolution or 
acoustic-profiling survey to obtain information on the conditions 
existing at and near the surface of the seafloor. You must collect 
information through this survey sufficient to determine the presence of 
the following features and their likely effects on your proposed 
platform:
    (1) Shallow faults;
    (2) Gas seeps or shallow gas;
    (3) Slump blocks or slump sediments;
    (4) Shallow water flows;
    (5) Hydrates; or
    (6) Ice scour of seafloor sediments.
    (b) Geologic surveys. You must perform a geological survey relevant 
to the design and siting of your platform. Your geological survey must 
assess:
    (1) Seismic activity at your proposed site;
    (2) Fault zones, the extent and geometry of faulting, and 
attenuation effects of geologic conditions near your site; and
    (3) For platforms located in producing areas, the possibility and 
effects of seafloor subsidence.
    (c) Subsurface surveys. Depending upon the design and location of 
your proposed platform and the results of the shallow hazard and 
geologic surveys, the Regional Supervisor may require you to perform a 
subsurface survey. This survey will include a testing program for 
investigating the stratigraphic and engineering properties of the soil 
that may affect the foundations or anchoring systems for your facility. 
The testing program must include adequate in situ testing, boring, and 
sampling to examine all important soil and rock strata to determine its 
strength classification, deformation properties, and dynamic 
characteristics. If required to perform a subsurface survey, you must 
prepare and submit to the Regional Supervisor a summary report to 
briefly describe the results of your soil testing program, the various 
field and laboratory test methods employed, and the applicability of 
these methods as they pertain to the quality of the samples, the type 
of soil, and the anticipated design application. You must explain how 
the engineering properties of each soil stratum affect the design of 
your platform. In your explanation you must describe the uncertainties 
inherent in your overall testing program, and the reliability and 
applicability of each test method.
    (d) Overall site investigation report. You must prepare and submit 
to the Regional Supervisor an overall site investigation report for 
your platform that integrates the findings of your shallow hazards 
surveys and geologic surveys, and, if required, your subsurface 
surveys. Your overall site investigation report must include analyses 
of the potential for:
    (1) Scouring of the seafloor;
    (2) Hydraulic instability;
    (3) The occurrence of sand waves;
    (4) Instability of slopes at the platform location;
    (5) Liquifaction, or possible reduction of soil strength due to 
increased pore pressures;
    (6) Degradation of subsea permafrost layers;
    (7) Cyclic loading;
    (8) Lateral loading;
    (9) Dynamic loading;
    (10) Settlements and displacements;

[[Page 41579]]

    (11) Plastic deformation and formation collapse mechanisms; and
    (12) Soil reactions on the platform foundations or anchoring 
systems.


Sec.  250.907  Where must I locate foundation boreholes?

    (a) For fixed or bottom-founded platforms and tension leg 
platforms, your maximum distance from any foundation pile to a soil 
boring must not exceed 500 feet.
    (b) For deepwater floating platforms which utilize catenary or 
taut-leg moorings, you must take borings at the most heavily loaded 
anchor location, at the anchor points approximately 120 and 240 degrees 
around the anchor pattern from that boring, and, as necessary, other 
points throughout the anchor pattern to establish the soil profile 
suitable for foundation design purposes.


Sec.  250.908  What are the minimum structural fatigue design 
requirements?

    (a) API RP 2A-WSD, Recommended Practice for Planning, Designing and 
Constructing Fixed Offshore Platforms (incorporated by reference as 
specified in 30 CFR 250.198), requires that the design fatigue life of 
each joint and member be twice the intended service life of the 
structure. When designing your platform, the following table provides 
minimum fatigue life safety factors for critical structural members and 
joints.

------------------------------------------------------------------------
              If . . .                            Then . . .
------------------------------------------------------------------------
(1) There is sufficient structural   The results of the analysis must
 redundancy to prevent catastrophic   indicate a maximum calculated life
 failure of the platform or           of twice the design life of the
 structure under consideration.       platform.
(2) There is not sufficient          The results of a fatigue analysis
 structural redundancy to prevent     must indicate a minimum calculated
 catastrophic failure of the          life or three times the design
 platform or structure.               life of the platform.
(3) The desirable degree of          The results of a fatigue analysis
 redundancy is significantly          must indicate a minimum calculated
 reduced as a result of fatigue       life of three times the design
 damage.                              life of the platform.
------------------------------------------------------------------------

    (b) The documents incorporated by reference in Sec.  250.901 may 
require larger safety factors than indicated in paragraph (a) of this 
section for some key components. When the documents incorporated by 
reference require a larger safety factor than the chart in paragraph 
(a) of this section, the requirements of the incorporated document will 
prevail.

Platform Verification Program


Sec.  250.909  What is the Platform Verification Program?

    The Platform Verification Program is the MMS approval process for 
ensuring that floating platforms; platforms of a new or unique design; 
platforms in seismic areas; or platforms located in deepwater or 
frontier areas meet stringent requirements for design and construction. 
The program is applied during construction of new platforms and major 
modifications of, or repairs to, existing platforms. These requirements 
are in addition to the requirements of the Platform Approval Program 
described in Sec. Sec.  250.904 through 250.908 of this subpart.


Sec.  250.910  Which of my facilities are subject to the Platform 
Verification Program?

    (a) All new fixed or bottom-founded platforms that meet any of the 
following five conditions are subject to the Platform Verification 
Program:
    (1) Platforms installed in water depths exceeding 400 feet (122 
meters);
    (2) Platforms having natural periods in excess of 3 seconds;
    (3) Platforms installed in areas of unstable bottom conditions;
    (4) Platforms having configurations and designs which have not 
previously been used or proven for use in the area; or
    (5) Platforms installed in seismically active areas.
    (b) All new floating platforms are subject to the Platform 
Verification Program to the extent indicated in the following table:

------------------------------------------------------------------------
              If . . .                            Then . . .
------------------------------------------------------------------------
(1) Your new floating platform is a  The entire platform is subject to
 buoyant offshore facility that       the Platform Verification Program
 does not have a ship-shaped hull.    including the following associated
                                      structures:
                                     (i) Drilling, production, and
                                      pipeline risers, and riser
                                      tensioning systems (each platform
                                      must be designed to accommodate
                                      all the loads imposed by all
                                      risers and riser does not have
                                      tensioning systems);
                                     (ii) Turrets and turret-and-hull
                                      interfaces;
                                     (iii) Foundations, foundation
                                      pilings and templates, and
                                      anchoring systems; and
                                     (iv) Mooring or tethering systems.
(2) Your new floating platform is a  Only the following structures that
 buoyant offshore facility with a     may be associated with a floating
 ship-shaped hull.                    platform are subject to the
                                      Platform Verification Program:
                                     (i) Drilling, production, and
                                      pipeline risers, and riser
                                      tensioning systems (each platform
                                      must be designed to accommodate
                                      all the loads imposed by all
                                      risers and riser a ship-shaped
                                      tensioning systems);
                                     (ii) Turrets and turret-and-hull
                                      interfaces;
                                     (iii) Foundations, foundation
                                      pilings and templates, and
                                      anchoring systems; and
                                     (iv) Mooring or tethering systems.
------------------------------------------------------------------------

    (c) If a platform is originally subject to the Platform 
Verification Program, then the conversion of that platform at that same 
site for a new purpose, or making a major modification of, or major 
repair to, that platform, is also subject to the Platform Verification 
Program. A major modification includes any modification that increases 
loading on a platform by 10 percent or more. A major repair is a 
corrective operation involving structural members affecting the 
structural integrity of a portion or all of the platform. Before you 
make a major modification or repair to a

[[Page 41580]]

floating platform, you must obtain approval from both the MMS and the 
USCG.
    (d) The applicability of Platform Verification Program requirements 
to other types of facilities will be determined by MMS on a case-by-
case basis.


Sec.  250.911  If my platform is subject to the Platform Verification 
Program, what must I do?

    If your platform, conversion, or major modification or repair meets 
the criteria in Sec.  250.910, you must:
    (a) Design, fabricate, install, use, maintain and inspect your 
platform, conversion, or major modification or repair to your platform 
according to the requirements of this subpart, and the applicable 
documents listed in Sec.  250.901(a) of this subpart;
    (b) Comply with all the requirements of the Platform Approval 
Program found in Sec. Sec.  250.904 through 250.908 of this subpart.
    (c) Submit for the Regional Supervisor's approval three copies each 
of the design verification, fabrication verification, and installation 
verification plans required by Sec.  250.912;
    (d) Include your nomination of a Certified Verification Agent (CVA) 
as a part of each verification plan required by Sec.  250.912;
    (e) Follow the additional requirements in Sec. Sec.  250.913 
through 250.918;
    (f) Obtain approval for modifications to approved plans and for 
major deviations from approved installation procedures from the 
Regional Supervisor; and
    (g) Comply with applicable USCG regulations for floating OCS 
facilities.


Sec.  250.912  What plans must I submit under the Platform Verification 
Program?

    If your platform, associated structure, or major modification meets 
the criteria in Sec.  250.910, you must submit the following plans to 
the Regional Supervisor for approval:
    (a) Design verification plan. You may submit your design 
verification plan with or subsequent to the submittal of your 
Development and Production Plan (DPP) or Development Operations 
Coordination Document (DOCD). Your design verification must be 
conducted by, or be under the direct supervision of, a registered 
professional civil or structural engineer or equivalent, or a naval 
architect or marine engineer or equivalent, with previous experience in 
directing the design of similar facilities, systems, structures, or 
equipment. For floating platforms, you must ensure that the 
requirements of the USCG for structural integrity and stability, e.g., 
verification of center of gravity, etc., have been met. Your design 
verification plan must include the following:
    (1) All design documentation specified in Sec.  250.905 of this 
subpart;
    (2) Abstracts of the computer programs used in the design process; 
and
    (3) A summary of the major design considerations and the approach 
to be used to verify the validity of these design considerations.
    (b) Fabrication verification plan. The Regional Supervisor must 
approve your fabrication verification plan before you may initiate any 
related operations. Your fabrication verification plan must include the 
following:
    (1) Fabrication drawings and material specifications for artificial 
island structures and major members of concrete-gravity and steel-
gravity structures;
    (2) For jacket and floating structures, all the primary load-
bearing members included in the space-frame analysis; and
    (3) A summary description of the following:
    (i) Structural tolerances;
    (ii) Welding procedures;
    (iii) Material (concrete, gravel, or silt) placement methods;
    (iv) Fabrication standards;
    (v) Material quality-control procedures;
    (vi) Methods and extent of nondestructive examinations for welds 
and materials; and
    (vii) Quality assurance procedures.
    (c) Installation verification plan. The Regional Supervisor must 
approve your installation verification plan before you may initiate any 
related operations. Your installation verification plan must include:
    (1) A summary description of the planned marine operations;
    (2) Contingencies considered;
    (3) Alternative courses of action; and
    (4) An identification of the areas to be inspected. You must 
specify the acceptance and rejection criteria to be used for any 
inspections conducted during installation, and for the post-
installation verification inspection.
    (d) You must combine fabrication verification and installation 
verification plans for manmade islands or platforms fabricated and 
installed in place.


Sec.  250.913  When must I resubmit Platform Verification Program 
plans?

    (a) You must resubmit any design verification, fabrication 
verification, or installation verification plan to the Regional 
Supervisor for approval if:
    (1) The CVA changes;
    (2) The CVA's or assigned personnel's qualifications change; or
    (3) The level of work to be performed changes.
    (b) If only part of a verification plan is affected by one of the 
changes described in paragraph (a) of this section, you can resubmit 
only the affected part. You do not have to resubmit the summary of 
technical details unless you make changes in the technical details.


Sec.  250.914  How do I nominate a CVA?

    (a) As part of your design verification, fabrication verification, 
or installation verification plan, you must nominate a CVA for the 
Regional Supervisor's approval. You must specify whether the nomination 
is for the design, fabrication, or installation phase of verification, 
or for any combination of these phases.
    (b) For each CVA, you must submit a list of documents to be 
forwarded to the CVA, and a qualification statement that includes the 
following:
    (1) Previous experience in third-party verification or experience 
in the design, fabrication, installation, or major modification of 
offshore oil and gas platforms. This should include fixed platforms, 
floating platforms, manmade islands, other similar marine structures, 
and related systems and equipment;
    (2) Technical capabilities of the individual or the primary staff 
for the specific project;
    (3) Size and type of organization or corporation;
    (4) In-house availability of, or access to, appropriate technology. 
This should include computer programs, hardware, and testing materials 
and equipment;
    (5) Ability to perform the CVA functions for the specific project 
considering current commitments;
    (6) Previous experience with MMS requirements and procedures;
    (7) The level of work to be performed by the CVA.


Sec.  250.915  What are the CVA's primary responsibilities?

    (a) The CVA must conduct specified reviews according to Sec. Sec.  
250.916, 250.917, and 250.918 of this subpart.
    (b) Individuals or organizations acting as CVAs must not function 
in any capacity that would create a conflict of interest, or the 
appearance of a conflict of interest.
    (c) The CVA must consider the applicable provisions of the 
documents listed in Sec.  250.901(a); the alternative codes, rules, and 
standards approved under 250.901(b); and the requirements of this 
subpart.
    (d) The CVA is the primary contact with the Regional Supervisor and 
is

[[Page 41581]]

directly responsible for providing immediate reports of all incidents 
that affect the design, fabrication and installation of the platform.


Sec.  250.916  What are the CVA's primary duties during the design 
phase?

    (a) The CVA must use good engineering judgement and practices in 
conducting an independent assessment of the design of the platform, 
major modification, or repair. The CVA must ensure that the platform, 
major modification, or repair is designed to withstand the 
environmental and functional load conditions appropriate for the 
intended service life at the proposed location.
    (b) Primary duties of the CVA during the design phase include the 
following:

------------------------------------------------------------------------
       Type of facility . . .                 The CVA must . . .
------------------------------------------------------------------------
(1) For fixed platforms and non-     Conduct an independent assessment
 ship-shaped floating facilities.     of all proposed:
                                     (i) Planning criteria;
                                     (ii) Operational requirements;
                                     (iii) Environmental loading data;
                                     (iv) Load determinations;
                                     (v) Stress analyses;
                                     (vi) Material designations;
                                     (vii) Soil and foundation
                                      conditions;
                                     (viii) Safety factors; and
                                     (ix) Other pertinent parameters of
                                      the proposed design.
(2)For all floating facilities.....  Ensure that the requirements of the
                                      U.S. Coast Guard for structural
                                      integrity and stability, e.g.,
                                      verification of center of gravity,
                                      etc., have been met. The CVA must
                                      also consider:
                                     (i) Drilling, production, and
                                      pipeline risers, and riser
                                      tensioning systems;
                                     (ii) Turrets and turret-and-hull
                                      interfaces;
                                     (iii) Foundations, foundation
                                      pilings and templates, and
                                      anchoring systems; and
                                     (iv) Mooring or tethering systems.
------------------------------------------------------------------------

    (c) The CVA must submit interim reports to the Regional Supervisor 
and to you, as appropriate. The CVA, upon completion of the design 
verification, must prepare a final report and submit one copy to the 
Regional Supervisor. The CVA must submit the final report within 90 
days of the receipt of the design data, or within 90 days from the date 
the approval to act as a CVA was issued, whichever is later. The CVA 
must submit the final report to the Regional Supervisor before 
fabrication begins, and must include:
    (1) A summary of the material reviewed and the CVA's findings;
    (2) The CVA's recommendation that the Regional Supervisor either 
accept, request modifications, or reject the proposed design;
    (3) The particulars of how, by whom, and when the independent 
review was conducted; and
    (4) Any additional comments the CVA may deem necessary.


Sec.  250.917  What are the CVA's primary duties during the fabrication 
phase?

    (a) The CVA must use good engineering judgement and practices in 
conducting an independent assessment of the fabrication activities. The 
CVA must monitor the fabrication of the platform or major modification 
to ensure that it has been built according to the approved design and 
the fabrication plan. If the CVA finds that fabrication procedures are 
changed or design specifications are modified, the CVA must inform you. 
If you accept the modifications, then the CVA must so inform the 
Regional Supervisor.
    (b) Primary duties of the CVA during the fabrication phase include 
the following:

------------------------------------------------------------------------
       Type of facility . . .                 The CVA must . . .
------------------------------------------------------------------------
(1) For all fixed platforms and non- Make periodic onsite inspections
 ship-shaped floating facilities.     while fabrication is in progress
                                      and must verify the following
                                      fabrication items, as appropriate:
                                     (i) Quality control by lessee and
                                      builder;
                                     (ii) Fabrication site facilities;
                                     (iii) Material quality and
                                      identification methods;
                                     (iv) Fabrication procedures
                                      specified in the approved plan,
                                      and adherence to such procedures;
                                     (v) Welder and welding procedure
                                      qualification and identification;
                                     (vi) Structural tolerences
                                      specified and adherence to those
                                      tolerances;
                                     (vii) The nondestructive
                                      examination requirements, and
                                      evaluation results of the
                                      specified examinations;
                                     (viii) Destructive testing
                                      requirements and results;
                                     (ix) Repair procedures;
                                     (x) Installation of corrosion-
                                      protection systems and splash-zone
                                      protection;
                                     (xi) Erection procedures to ensure
                                      that overstressing of structural
                                      members does not occur;
                                     (xii) Alignment procedures;
                                     (xiii) Dimensional check of the
                                      overall structure, including any
                                      turrets, turret-and-hull
                                      interfaces, any mooring line and
                                      chain and riser tensioning line
                                      segments; and
                                     (xiv) Status of quality-control
                                      records at various stages of
                                      fabrication.

[[Page 41582]]

 
(2) For all floating facilities....  Ensure that the requirements of the
                                      U.S. Coast Guard floating for
                                      structural integrity and
                                      stability, e.g., verification of
                                      center of gravity, etc., have been
                                      met. The CVA must also consider:
                                     (i) Drilling, production, and
                                      pipeline risers, and riser
                                      tensioning systems (at least for
                                      the initial fabrication of these
                                      elements);
                                     (ii) Turrets and turret-and-hull
                                      interfaces;
                                     (iii) Foundation pilings and
                                      templates, and anchoring systems;
                                      and
                                     (iv) Mooring or tethering systems.
------------------------------------------------------------------------

    (c) Reports. The CVA must submit interim reports to the Regional 
Supervisor and to you, as appropriate. The CVA must prepare a final 
report covering the adequacy of the entire fabrication phase. The final 
report need not cover aspects of the fabrication already included in 
interim reports. The CVA must submit one copy of the final report to 
the Regional Supervisor within 90 days after completion of the 
fabrication phase but before the beginning of the installation phase. 
In the final report the CVA must:
    (1) Give details of how, by whom, and when the independent 
monitoring activities were conducted;
    (2) Describe the CVA's activities during the verification process;
    (3) Summarize the CVA's findings;
    (4) Confirm or deny compliance with the design specifications and 
the approved fabrication plan;
    (5) Make a recommendation to accept or reject the fabrication; and
    (6) Provide any additional comments that the CVA deems necessary.


Sec.  250.918  What are the CVA's primary duties during the 
installation phase?

    (a) The CVA must use good engineering judgment and practice in 
conducting an independent assessment of the installation activities.
    (b) Primary duties of the CVA during the installation phase include 
the following:

------------------------------------------------------------------------
                                         Operation or equipment to be
         The CVA must . . .                    inspected . . .
------------------------------------------------------------------------
(1) Verify, as appropriate.........  (i) Loadout and initial flotation
                                      operations;
                                     (ii) Towing operations to the
                                      specified location, and review the
                                      towing records;
                                     (iii) Launching and uprighting
                                      operations;
                                     (iv) Submergence operations;
                                     (v) Pile or anchor installations;
                                     (vi) Installation of mooring and
                                      tethering systems;
                                     (vii) Final deck and component
                                      installations; and
                                     (viii) Installation at the approved
                                      location according to the approved
                                      design and the installation plan.
(2) Witness (for a fixed or          (i) The loadout of the jacket,
 floating platform).                  decks, piles, or structures from
                                      each fabrication site;
                                     (ii) The actual installation of the
                                      platform or major modification and
                                      the related installation
                                      activities.
(3) Witness (for a floating          (i) The loadout of the platform;
 platform).
                                     (ii) The installation of drilling,
                                      production, and pipeline risers,
                                      and riser tensioning systems (at
                                      least for the initial installation
                                      of these elements);
                                     (iii) The installation of turrets
                                      and turret-and-hull interfaces;
                                     (iv) The installation of foundation
                                      pilings and templates, and
                                      anchoring systems; and
                                     (v) The installation of the mooring
                                      and tethering systems.
(4) Conduct an onsite survey.......  Survey the platform after
                                      transportation to the approved
                                      location.
(5) Spot-check as necessary to       (i) Equipment;
 determine compliance with the       (ii) Procedures; and
 applicable documents listed in      (iii) Recordkeeping.
 Sec.   250.901(a); the alternative
 codes, rules and standards
 approved under 250.901(b); the
 requirements listed in Sec.
 250.903 and Sec.   250.906 through
 250.908 of this subpart and the
 approved plans.
------------------------------------------------------------------------

    (c) Reports. The CVA must submit interim reports to you and the 
Regional Supervisor, as appropriate. The CVA must prepare a final 
report covering the adequacy of the entire installation phase, and 
submit one copy of the final report to the Regional Supervisor within 
30 days of the installation of the platform. In the final report, the 
CVA must:
    (1) Give details of how, by whom, and when the independent 
monitoring activities were conducted;
    (2) Describe the CVA's activities during the verification process;
    (3) Summarize the CVA's findings;
    (4) Write a confirmation or denial of compliance with the approved 
installation plan;
    (5) Provide a recommendation to accept or reject the installation; 
and
    (6) Provide any additional comments that the CVA deems necessary.

Inspection, Maintenance, and Assessment of Platforms


Sec.  250.919  What in-service inspection requirements must I meet?

    (a) You must develop a comprehensive annual in-service inspection 
plan covering all of your platforms. As a minimum, your plan must 
address the recommendations of the appropriate documents listed in 
Sec.  250.901(a). Your plan must specify the type, extent, and 
frequency of in-place inspections which you will conduct for

[[Page 41583]]

both the above water and the below water structure of all platforms, 
and pertinent components of the mooring systems for floating platforms. 
The plan must also address how you are monitoring the corrosion 
protection for both the above water and below water structure.
    (b) You must submit a report annually on November 1 to the Regional 
Supervisor that must include:
    (1) A list of fixed or floating platforms inspected in the 
preceding 12 months;
    (2) The extent and area of inspection;
    (3) The type of inspection employed, (i.e., visual, magnetic 
particle, ultrasonic testing); and
    (4) A summary of the testing results indicating what repairs, if 
any, were needed and the overall structural condition of the fixed or 
floating platform.


Sec.  250.920  What are the MMS requirements for assessment of 
platforms?

    (a) You must perform a platform assessment when needed, based on 
the platform assessment initiators listed in sections 17.2.1-17.2.5 of 
API RP 2A-WSD, Recommended Practice for Planning, Designing and 
Constructing Fixed Offshore Platforms--Working Stress Design 
(incorporated by reference as specified in 30 CFR 250.198).
    (b) You must initiate mitigation actions for platforms that do not 
pass the assessment process of API RP 2A-WSD.
    (c) You must document all wells, equipment, and pipelines supported 
by the platform if you intend to use the medium or low consequence of 
failure exposure category for your assessment. Exposure categories are 
defined in API RP 2A-WSD Section 1.7.
    (d) MMS may require you to conduct a platform assessment where 
reduced environmental loading criteria are not allowed.
    (e) The use of Section 17, Assessment of Existing Platforms, of API 
RP 2A-WSD, is limited to existing fixed structures that are serving 
their original approved purpose.


Sec.  250.921  How do I analyze my platform for cumulative fatigue?

    (a) If you are required to analyze cumulative fatigue on your 
platform because of the results of an inspection or platform 
assessment, you must ensure that the safety factors for critical 
elements listed in Sec.  250.908 are met or exceeded.
    (b) If the calculated life of a joint or member does not meet the 
criteria of Sec.  250.908, you must either mitigate the load, 
strengthen the joint or member, or develop an increased inspection 
process.

0
8. In Sec.  250.1002, paragraphs (b)(4) and (b)(5) are added to read as 
follows:


Sec.  250.1002  Design requirements for DOI pipelines.

* * * * *
    (b) * * *
    (4) If you are installing pipelines constructed of unbonded 
flexible pipe, you must design them according to the standards and 
procedures of API Spec 17J, incorporated by reference as specified in 
30 CFR 250.198.
    (5) You must design pipeline risers for tension leg platforms and 
other floating platforms according to the design standards of API RP 
2RD, Design of Risers for Floating Production Systems (FPSs) and 
Tension Leg Platforms (TLPs), incorporated by reference as specified in 
30 CFR 250.198.
* * * * *
    9. In Sec.  250.1007, revise paragraph (a)(4) to read as follows:


Sec.  250.1007  What to include in applications.

    (a) * * *
    (4) The application must include a description of any additional 
design precautions which were taken to enable the pipeline to withstand 
the effects of water currents, storm or ice scouring, soft bottoms, 
mudslides, earthquakes, permafrost, and other environmental factors. If 
your application involves using unbonded flexible pipe, you must:
    (i) Review the manufacturer's Design Methodology Verification 
Report, and the independent verification agent's (IVA's) certificate 
for the design methodology contained in that report, to ensure that the 
manufacturer has complied with the requirements of API Spec 17J 
incorporated by reference as specified in 30 CFR 250.198;
    (ii) Determine that the unbonded flexible pipe is suitable for its 
intended purpose on the lease or pipeline right-of-way;
    (iii) Submit to the MMS Regional Supervisor the manufacturer's 
design specifications for the unbonded flexible pipe; and
    (iv) Submit to the MMS Regional Supervisor a statement certifying 
that the pipe is suitable for its intended use, and that the 
manufacturer has complied with the IVA requirements of API Spec 17J 
incorporated by reference as specified in 30 CFR 250.198.
* * * * *
[FR Doc. 05-14038 Filed 7-18-05; 8:45 am]
BILLING CODE 4310-MR-P