[Federal Register Volume 66, Number 248 (Thursday, December 27, 2001)]
[Proposed Rules]
[Pages 66851-66865]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 01-31723]



[[Page 66851]]

-----------------------------------------------------------------------

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 Documents Incorporated by 
Reference

AGENCY: Minerals Management Service (MMS), Interior.

ACTION: Notice of proposed rulemaking.

-----------------------------------------------------------------------

SUMMARY: We are proposing to amend our regulations to address floating 
offshore platforms that, until now, have not been expressly covered. 
These floating production systems (FPSs) are variously described as 
column-stabilized units (CSUs); floating production, storage and 
offloading facilities (referred to by industry as ``FPSOs''); tension-
leg platforms (TLPs); spars, etc. We are also incorporating into our 
regulations a body of industry standards pertaining to FPSs, and this 
will save the public the costs of developing separate, and in many 
cases unnecessarily duplicative, government standards. However, it will 
increase costs to industry by making certain independent third-party 
reviews mandatory, particularly by requiring hazards analyses for all 
new FPSs.

DATES: We will consider all comments we receive by February 25, 2002. 
We will begin reviewing comments then and may not fully consider 
comments we receive after February 25, 2002.

ADDRESSES: If you wish to comment, you may submit your comments by any 
one of several methods. You may mail or hand-carry comments (three 
copies) to the Department of the Interior; Minerals Management Service; 
Mail Stop 4024; 381 Elden Street; Herndon, Virginia 20170-4817; 
Attention: Rules Processing Team. You may also comment via e-mail to 
<a href="/cdn-cgi/l/email-protection#98eaedf4fdebb6fbf7f5f5fdf6ecebd8f5f5ebb6fff7ee"><span class="__cf_email__" data-cfemail="bccec9d0d9cf92dfd3d1d1d9d2c8cffcd1d1cf92dbd3ca">[email protected]</span></a>. Please submit e-mail comments as an ASCII file 
(MS Word) avoiding the use of special characters and any form of 
encryption. Include your name and return address in your e-mail message 
and mark your message for return receipt. Show the Rule Identification 
Number (RIN 1010-AC-85) in your subject line.
    Mail or hand-carry comments with respect to the information 
collection burden of the proposed rule to the Office of Information and 
Regulatory Affairs; Office of Management and Budget; Attention: Desk 
Officer for the Department of the Interior (OMB control number 1010-
XXXX); 725 17th Street, NW., Washington, DC 20503.

FOR FURTHER INFORMATION CONTACT: Carl Anderson, Physical Scientist, at 
(703) 787-1608; or Joseph Levine, Chief, Operations Analysis Branch, at 
(703) 787-1033 or FAX (703) 787-1555.

SUPPLEMENTARY INFORMATION: We propose incorporating into our 
regulations a body of industry standards pertaining to FPSs, and this 
will save the public the costs of developing Government standards. It 
will also 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 Gulf of Mexico (GOM).
    Incorporating the now-voluntary industry standards into our 
regulations would dictate that respondents comply with the requirements 
in the incorporated documents. This includes certified verification 
agent (CVA) reviews and hazards analyses for some areas that current 
regulations do not require, but the voluntary standards recommend. 
Thus, the now-voluntary CVA reviews and hazards analyses would become 
mandatory. This would 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)). Also, 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 the proposed rule.
    Deepwater areas of the GOM have shown a remarkable increase in oil 
and gas exploration, development, and production. In part this is due 
to the development of new technologies that (1) enable drilling and 
production in deeper waters; and (2) reduce operational costs and 
risks, such as new geophysical software used to identify highly 
productive reservoirs. In 1993, deepwater areas of the GOM (water 
depths greater than 1,000 feet, or 305 meters) accounted for only 12 
percent and 2 percent, respectively, of total GOM oil and gas 
production. Discovery and development of deepwater fields began 
accelerating in 1994, so that by the end of 1999, deepwater areas of 
the GOM accounted for 45 percent and 17 percent, respectively, of total 
GOM oil and gas production. (From 1994 through 1998, deepwater 
production of oil rose 260 percent.)
    To realize just how important the new deepwater areas of the GOM 
are to United States energy supplies, it is helpful to compare the 
productivity of deepwater wells to past wells in more shallow waters. 
Historically, GOM wells generally have produced between 200 and 300 
barrels (bbls.) per day. However, at least one existing deepwater well 
is producing over 30,000 bbls. of oil per day, and several are 
producing over 20,000 bbls. per day. An existing deepwater platform in 
the GOM is producing 140,000 bbls. of oil and 140 million cubic feet of 
gas per day. Success in deepwater is evident in both the high 
production rates and sustained drilling for new discoveries announced 
each year. Drilling is expected to move into water depths of 10,000 
feet (3,048 meters).
    The following discussion is intended to give the reviewer an idea 
of how fast technological changes are occurring in deepwater oil and 
gas operations. It is also meant to establish the urgency for MMS to 
adopt common industry standards so that system designers will know what 
is acceptable when they plan for floating deepwater platforms. Any of 
the drilling or production ``records'' discussed below will likely be 
exceeded by the time this Notice is published. Several notable examples 
show how new deepwater exploration and production systems are ``leap-
frogging'' the technical achievements of their recent predecessors.
    As of December 2000, there were 40 rigs drilling in water depths 
greater than 305 meters (1,000 feet), versus 32 for December 1999. This 
represents a record number of rigs drilling in deepwater. Until now, 
about 100 deepwater discoveries have been announced for the GOM.
    Concerning exploratory drilling in August 1998, Chevron U.S.A. set 
a GOM water-depth record in 7,718 feet of water (2,352 meters) on 
Atwater Valley Block 118, 175 miles southeast of New Orleans. But 
Chevron's record was recently exceeded, (1) in the GOM by Broken Hill 
Proprietary Petroleum, which drilled an exploratory well in 8,835 feet 
(2,693 meters) of water in the Walker Ridge area; and (2) offshore 
Brazil, where PetroBras set a new 9,111-foot (2,777-meter) world 
record.
    Concerning production water-depth records, Petrobras holds the 
water-depth record for sustained production at their Roncador field in 
the Campos Basin with the Petrobras 36 column stabilized floating 
production system installed in 6,079 feet (1,853 meters) of water. 
Subsea wells tie back to Petrobras 36 in

[[Page 66852]]

6,560 feet (1,999 meters) of water, which is a world production depth 
record.
    So far, only 21 permanent development platforms have been installed 
in waters over 1,000 feet deep (305 meters) in the GOM. Seven of these 
structures are fixed platforms, three are compliant towers, eight are 
TLPs, and three are spars. All of these production platforms were 
approved on a case-by-case basis under existing MMS regulations. 
However, it would streamline the permitting process and increase the 
up-front net-present-value of deepwater projects for the offshore 
industry if MMS had 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, stationkeeping and mooring 
systems, flexible pipelines, and hazards analysis.
    A discussion of the expense involved in exploring for and 
developing deepwater oil and gas reserves was presented at the World 
Petroleum Congress (WPC) in Calgary, Canada, in June 2000. According to 
the ``Oil & Gas Journal,'' Mr. Luiz Rodolfo Landim Machado of Petroleo 
Brasileiro SA projected that through 2004, the oil industry would spend 
about $76 billion in deepwater areas worldwide to explore for and 
develop about 19 billion barrels of oil equivalent. He indicated that 
about 27 percent of the reserves would be found in the GOM. (``WPC: 
Deepwater holds industry's greatest challenges, opportunities,'' Vol. 
98, Issue 26 (June 26, 2000).) Assuming a commensurate expenditure of 
27 percent, that would lead to the oil industry spending $20.5 billion 
in deepwater areas of the GOM through 2004. That represents industry 
deepwater expenditures of over $4.5 billion per year from June 2000 
through 2004.
    To provide further background on the potential impact of this 
proposal, leases lying in water depths of from 400 to 800 meters (from 
1,312 to 2,625 feet) have lease terms of 8 years, as opposed to the 
customary 5-year term. Leases lying in water depth of over 800 meters 
(2,625 feet) have 10-year terms. These longer lease terms give lessees 
much longer time horizons to plan their lease development activities. 
Consequently, the MMS GOM Region estimates that about six FPSs will be 
approved for installation during any given year. This means that 
probably much fewer than even half of the approximately 98 companies 
currently holding leases in deepwater would ever submit development 
plans for a floating platform before their lease terms expire.

The Purpose of this Rule

    The purpose of this proposed rule is to incorporate into our 
regulations a body of industry standards that will enable us to more 
efficiently examine plans for and issue permits for floating offshore 
platforms. Our regulations currently do not specifically cover these 
facilities. Therefore, this proposal includes a complete rewrite of 
subpart I of 30 CFR Part 250 to cover floating platforms. Incorporating 
the voluntary industry standards would save the public the cost of 
developing government-specific standards. It would also 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 GOM 
in two ways. First, it would provide more certainty to the lessees' 
design engineers so that they would know in advance what design 
criteria are acceptable to MMS. Second, it would enhance MMS engineers' 
efforts in reviewing each new project to ensure structural integrity, 
operational and human safety, and environmental protection. This is 
because the proposed regulation would establish a single body of 
standards on which each new project would be based. These enhancements 
would streamline the regulatory review process and, thereby, increase 
the net-present-value of the project to lessees that assume the high 
financial risks of developing deepwater areas. There can be 
considerable costs to the industry if revenues from the project are 
delayed while industry and government engineers haggle over acceptable 
standards for the project in question.
    Under existing MMS regulations, lessees and operators have to 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 that we have already incorporated, they have the option to 
use equivalent standards, provided they first obtain our approval.
    Many industry standards reference ``second-tier documents'' that we 
do not directly incorporate into our regulations. Nevertheless, the 
fact that an industry standard relies on second-tier documents 
effectively makes them part of the justification for approving a 
permit. It is incumbent upon MMS and the certified verification agent 
(CVA) to make certain that referenced standards are properly followed. 
MMS has operated under this premise for years, and it has worked well. 
However, the system usually works more efficiently when an industry 
standard is directly incorporated by reference into our regulations. 
That way, lessees do not have to go through the steps of obtaining our 
approval for various standards prior to developing their plans. Also, 
it saves MMS time, because we do not have to conduct special reviews of 
certain industry standards with which we may be unfamiliar.
    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.'' This is for the 
purpose of ``eliminating unnecessary duplication and complexity in the 
development and promulgation of conformity assessment requirements and 
measures'' (i.e., 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 use of consensus standards would be inconsistent with 
applicable law or otherwise impractical. Agencies have the discretion 
to decline to use existing voluntary consensus standards if they 
determine that such standards are inconsistent with applicable law or 
otherwise impractical.
    In this proposed rulemaking, MMS intends to incorporate eight 
American Petroleum Institute (API) standards, and one American Welding 
Society (AWS) standard. In one case, we would be adopting the latest 
edition of an API standard already incorporated into MMS regulations. 
We have actively participated in developing several of these standards 
and believe that we could not write duplicative government regulations 
that would be either as technically detailed or as broad in their scope 
as these standards. Moreover, the writing of such duplicative 
government regulations could neither be done in a timely nor 
economically efficient way--nor could it be done with the same level of 
expertise that was involved in the

[[Page 66853]]

industry effort. We believe that it is entirely within the letter and 
spirit of the NTTAA that we incorporate these voluntary industry 
standards into our regulations. Moreover, we believe it is in the 
public interest that we so adopt these standards.
    The nine industry standards proposed for incorporation are as 
follows:
    (1) API Recommended Practice 2A (API RP 2A)--WSD, Recommended 
Practice for Planning, Designing and Constructing Fixed Offshore 
Platforms--Working Stress Design; Twenty-First Edition, December 2000, 
API Order No. G2AWSD. The 19th and 20th editions of this standard are 
already incorporated by reference into MMS regulations. The 21st 
edition would simply update and replace these two earlier editions. The 
21st edition provides the rationale for revising much of subpart I--
Platforms and Structures--in the proposed rulemaking. It deals with 
bottom-founded structures which, until this rulemaking, have been the 
primary focus of Subpart I. Upon the effective date of the final rule, 
the following National Notices to Lessees and Operators (NTLs) related 
to API RP 2A would be cancelled: (1) NTL No. 98-1N provides interim 
guidance for applying platform design criteria from API RP 2A; and (2) 
NTL No. 98-4N provides interim guidance for applying the ``Simplified 
Fatigue Analysis Procedure'' from API RP 2A. These two NTLs had been 
published in cooperation with the API RP 2A workgroup. The workgroup 
had discovered some insufficient design criteria in both the 19th and 
20th editions of RP 2A related to various structures and the water 
depths in which they were to be constructed. Depending on the type of 
structure, either the 19th or 20th edition was the correct standard to 
be used. The NTLs provided guidance on the correct use of the 
standards.
    (2) API RP 2RD, Design of Risers for Floating Production Systems 
(FPSs) and Tension-Leg Platforms (TLPs), First Edition, June 1998, API 
Stock No. G02RD1. This standard covers drilling, production, and 
pipeline risers associated with all FPSs, including spars, TLPs, CSUs, 
and FPSOs. Moreover, it deals with construction of flexible riser 
systems, which have not been explicitly covered under MMS regulations.
    (3) 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 Stock No. G02SK2. 
Again, stationkeeping systems for floating platforms have not been 
explicitly covered under MMS regulations.
    (4) 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 GOM 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 the deepwater 
areas of the GOM. 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 very heavily on the analysis contained in API 
RP 2A, 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.
    (5) API RP 14J, Recommended Practice for Design and Hazards 
Analysis for Offshore Production Facilities, First Edition, Sept. 1, 
1993, API Stock No. 811-07200. Implementing this standard for all new 
deepwater floating production platforms will be the most costly element 
of the proposed rule. This is a standard that has provided much of the 
early rationale and background for MMS's voluntary Safety and 
Environmental Management Planning program. During 2000, a consensus was 
reached within the industry that the complexities and safety issues 
involved in FPSs warrant the imposition 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 barrels per day. 
Therefore, we have 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, we believe 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.) We 
would require an analysis of operational hazards to be included as 
integral parts 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 Stock No. G17J02. For several years MMS has been permitting 
remote subsea wells that use flexible pipe for deep sea production 
pipelines. We believe that this standard adequately serves the 
interests of environmental protection and safety in providing guidance 
to both regulators and industry in the proper design and construction 
of flexible pipelines and flowlines. The industry projects that as many 
as 50 percent of future deepwater wells will be remote subsea wells 
tied back to existing production platforms. Also, there will be an 
increasing number of shallow water subsea tie-backs. Therefore, this 
standard will be essential for future production operations.
    (7) AWS D3.6M:1999, Specification for Underwater Welding. MMS 
refers to this document every time we receive an application for an 
underwater welding repair. This document is analogous and complimentary 
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 our regulations for 
over 20 years. Further, MMS was a member of the subcommittee which 
developed AWS D3.6M. It serves a definite purpose in our reassessment 
process. Underwater welding is used infrequently because of the 
expenses 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. We receive applications for 
underwater welding repairs on an infrequent basis; but AWS D3.6M is the 
primary document the industry follows for these purposes. We need to 
incorporate it into our regulations, because we anticipate 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 2FPS, Recommended Practice for Planning, Designing, and 
Constructing Floating Production Systems, First Edition, March 2001, 
API Order No. G2FPS1. 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.
    (9) API RP 2SM, Recommended Practice for Design, Manufacture,

[[Page 66854]]

Installation, and Maintenance of Synthetic Fiber Ropes for Offshore 
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 not been used in the 
mooring systems of floating OCS platforms and have seen only limited 
use for similar applications worldwide. Therefore, given the lack of 
long-term experience with the use of synthetic fiber rope, API RP 2SM 
will serve as the primary MMS document of reference 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

    In addition to incorporating new industry documents, the proposed 
rule would include 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 we published in the Federal 
Register on January 15, 1999 (64 FR 2660-2667). The MOU describes our 
respective and overlapping responsibilities for regulating ``Floating 
Outer Continental Shelf (OCS) Facilities.''
    In response to issues raised by the International Association of 
Drilling Contractors (IADC) and Noble Drilling Services, Inc., we 
propose to insert new language to address our regulatory 
responsibilities under the MOU. We propose to insert the language into 
subpart H, at Sec. 250.800(b), and subpart I at proposed 
Sec. 250.904(e). The IADC and Noble Drilling Services had commented on 
an MMS Federal Register Notice of June 21, 2000 (65 FR 38453). In 
reviewing our third-party review requirements in that Notice, they 
expressed concern that we did not adequately clarify the differences 
between our responsibilities and those of the USCG. MMS and the USCG 
have overlapping responsibilities under the MOU, so it is not possible 
to completely eliminate ambiguities in our regulations.
    We stated above that the 21st edition of API RP 2A provides the 
rationale for revising and shortening much of Subpart I--Platforms and 
Structures--in the proposed rulemaking. With the incorporation of the 
21st edition, we can eliminate much of the verbiage in the current 
subpart I regulations. Therefore, we propose to rename and totally 
reorganize subpart I.
    On July 7, 2000, we published a proposed rule concerning 
decommissioning activities (65 FR 41892). We assume that the 
decommissioning rule will be finalized before this rule. Therefore, we 
have written proposed Sec. 250.913 to correspond to relevant sections 
of the decommissioning activities proposed rule. If, for any reason, 
the decommissioning rule does not become final before this rule, 
Sec. 250.913 will be rewritten in the final rule to correspond to the 
status of 30 CFR part 250 at the time of publication.

Derivation Table

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

 
------------------------------------------------------------------------
          Proposed new section              Current regulation section
------------------------------------------------------------------------
Sec.  250.900 What general requirements  Sec.  250.900; New requirement.
 apply to fixed and floating platforms?
Sec.  250.901 What industry standards    Sec.  250.900(g); Sec.
 must fixed and floating platforms        250.907(b), (c), (d); Sec.
 meet?                                    250.908 (b), (c), (d), (e);
                                          New requirements.
Sec.  250.902 What must an application   Sec.  250.901(a), (b)
 to approve a fixed, or floating
 platform contain?
Sec.  250.903 Which of my platforms,      250.902; New requirements.
 associated structures, and major
 modifications are subject to the
 Platform Verification Program?
Sec.  250.904 If my platform,            Sec.  250.902; New
 associated structure, or major           requirements.
 modification is subject to the
 Platform Verification Program, what
 must I do?
Sec.  250.905 What plans must I submit   Sec.  250.902; New
 under the Platform Verification          requirements.
 Program?
Sec.  250.906 When must I resubmit       Sec.  250.902; New
 Platform Verification Program plans?     requirements.
Sec.  250.907 When must I combine        Sec.  250.902; New
 Platform Verification Program plans?     requirements.
Sec.  250.908 How do I nominate a CVA?   Sec.  250.902; Sec.
                                          250.903(b).
Sec.  250.909 What are the CVA's         Sec.  250.903(a).
 primary responsibilities?
Sec.  250.910 What are the CVA's         Sec.  250.903(a)(1).
 primary duties during the design
 phase?
Sec.  250.911 What are the CVA's         Sec.  250.903(a)(2).
 primary duties during the fabrication
 phase?
Sec.  250.912 What are the CVA's         Sec.  250.903(a)(3).
 primary duties during the installation
 phase?
Sec.  250.913 What are the minimum       Sec.  250.907(c).
 structural fatigue requirements?
Sec.  250.914 What records must I keep   Sec.  250.907(a).
 for all primary structural members?
Sec.  250.915 Where must I locate        New requirements.
 foundation boreholes?
Sec.  250.916 What in-service            Sec.  250.912(b); New
 inspection requirements must I meet?     requirements.
Sec.  250.917 What are the requirements  Sec.  250.913
 for fixed or floating platform removal
 and location clearance?
Sec.  250.918 What records must I keep?  Sec.  250.914
------------------------------------------------------------------------

Procedural Matters

Public Comment Procedures

    Our practice is to make comments, including names and home 
addresses of respondents, available for public review during regular 
business hours. Individual respondents may request that we withhold 
their home address from the rulemaking record, which we will honor to 
the extent allowable by law. There may be circumstances in which we 
would withhold from the rulemaking record a respondent's identity, as 
allowable by law. If you wish us to withhold your name and/or address, 
you must state this prominently at the beginning of your

[[Page 66855]]

comment. However, we will not consider anonymous comments. We will make 
all submissions from organizations or businesses, and from individuals 
identifying themselves as representatives or officials of organizations 
or businesses, available for public inspection in their entirety.

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) The proposed 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 the proposed 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. (Indeed, 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 
proposed 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 proposed rule is 
available from the Department of the Interior; Minerals Management 
Service; Operations Analysis Branch; Mail Stop 4022; 381 Elden Street; 
Herndon, Virginia 20170-4817; Attention: Carl W. Anderson.
    (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 proposed 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 precedents for actions of this type under past lease stipulations 
and regulations dealing with oil spill response and oil spill financial 
responsibility provisions under the OCS Lands Act and the Oil Pollution 
Act of 1990.

Regulatory Flexibility (RF Act)

    The Department certifies that this document 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 small deepwater lessees 
would submit plans for floating platforms in any given year. Most 
likely, these lessees would join in 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, we 
conclude 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 (888) 734-3247.

Small Business Regulatory Enforcement Fairness Act (SBREFA)

    This rule is not a major rule under (5 U.S.C. 804(2)), SBREFA. 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 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 deepwater lessees would submit plans for floating 
platforms in any given year. Most likely, these lessees would join in 
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, we conclude that the rule would not have a 
significant economic impact on a substantial number of small entities.

Paperwork Reduction Act (PRA) of 1995

    The proposed revisions to sections in subparts A and B of 30 CFR 
250 do not affect the information collection (IC) aspects of those 
regulations. These are currently approved under OMB control numbers 
1010-0114 (subpart A) and 1010-0049 (subpart B). We did not submit an 
information collection request (ICR) to OMB for these sections.
    With respect to the proposed revisions in 30 CFR part 250, subparts 
H, I, and J, we have submitted an ICR (form OMB 83-I) to OMB for review 
and approval according to section 3507(d) of the PRA. The title of the 
collection of information is ``Proposed Rulemaking--30 CFR part 250, 
Subparts J, H, and I, Fixed and Floating Platforms and Structures.'' 
The ICR covers only the proposed changes to subparts H and J. Because 
subpart I would be revised in

[[Page 66856]]

its entirety, the ICR does cover the burden for all of subpart I.
    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. We 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 proposed information collected under 
subparts H and J to ensure proper construction of production safety 
systems and pipelines.
    Although the proposed regulations would specifically cover floating 
platforms as well as fixed platforms, this is not a new category of IC. 
MMS has always permitted floating facilities on a case-by-case basis. 
Incorporating the new documents provides industry with specific 
standards by which we will hold them accountable in the design, 
fabrication, and installation of fixed and floating platforms offshore. 
Making mandatory these now voluntary standards would dictate that 
respondents comply with the requirements in the incorporated documents. 
This includes CVA review for some areas that current regulations do not 
require, but the voluntary standards recommend. The proposed 
regulations will increase the number of CVA nominations and reports 
associated with the facilities and require hazards analysis 
documentation for new floating platforms.
    A separate proposed rulemaking on 30 CFR part 250, subpart Q, 
Decommissioning Activities (published on July 7, 2000, 65 FR 41892) 
would relocate the platform and structure removal and site clearance 
requirements from current subpart I regulations to the new subpart Q. 
The hour burdens for those paperwork requirements were included in the 
OMB approval of the IC requirements of that rulemaking (1010-0142) and 
are not included in this submission.
    OMB has approved the IC required by current regulations in subparts 
H, I, and J under control numbers 1010-0059, 1010-0058 and 1010-0050. 
We estimate the proposed changes will increase the currently approved 
hour burdens by:

  3,300  hours for subpart H
  4,320  hours for subpart I
  1,800  hours for subpart J
--------
  9,420  total burden hour increase
 

    The proposed 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 new requirements 
in subparts H and J and all of the requirements in subpart I. New 
subpart I requirements are so noted.

----------------------------------------------------------------------------------------------------------------
                                                                                                    Hour burden
                                                                                                   per response
   Citation 30 CFR 250 proposed section            Reporting or recordkeeping requirement            or record
                                                                                                      (hours)
----------------------------------------------------------------------------------------------------------------
                                                    Subpart H
----------------------------------------------------------------------------------------------------------------
800(b)...................................  Submit CVA documentation under API RP 2RD. (Estimate               50
                                            60 per year).
803(b)(2)(iii)...........................  Submit CVA documentation under API RP 17J. (Estimate               50
                                            6 per year).
----------------------------------------------------------------------------------------------------------------
                                                    Subpart I
----------------------------------------------------------------------------------------------------------------
900(a); 901(b); 902; 903; 905; 907.......  Submit application to install new fixed or floating                24
                                            platform or significant changes to approved
                                            applications, including use of alternative codes,
                                            rules, or standards; and Platform Verification
                                            Program plans for design, fabrication and
                                            installation of new, fixed, bottom-founded, pile-
                                            supported, or concrete-gravity platforms and new
                                            floating platforms.
900(a)(2); 903(c); 906...................  Submit application for major modification to any                   24
                                            platform.
900(a)(4)................................  Notify MMS within 24 hours of damage and emergency                 16
                                            repairs and request approval of repairs.
900(a)(5)................................  Submit application for the conversion of the use of                24
                                            an existing mobile offshore drilling unit (MODU).
901(a)(6), (a)(7), (a)(8)................  NEW: Submit CVA documentation under API RP 2RD, API               100
                                            RP 2SK, and API RP 2SM. (Estimate 6 per year).
901(a)(10)...............................  NEW: Submit hazards analysis documentation under API              500
                                            RP 14J. (Estimate 6 per year).
904(c); 908..............................  Submit nomination and qualification statement for CVA              16
910(c), (d)..............................  Submit interim and final CVA reports and                          200
                                            recommendations on design phase.
911(d), (e), (f).........................  NEW: Submit interim and final CVA reports and                      60
                                            recommendations on fabrication phase, including
                                            notice of fabrication procedure changes or design
                                            specification modifications. (Estimate 6 per year).
912(c), (d), (e).........................  NEW: Submit interim and final CVA reports and                      60
                                            recommendations on installation phase, including
                                            notice of any discrepancies or damage to structural
                                            members. (Estimate 6 per year).
914; 918: See footnote*..................  Recordkeeping: Record origin and relevant material                 50
                                            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.

[[Page 66857]]

 
916......................................  Develop in-service inspection plan and submit annual               45
                                            (November 1 of each year) report on inspection of
                                            fixed or floating platforms, including summary of
                                            testing results.
900 thru 918.............................  General departure and alternative compliance requests               2
                                            not specifically covered elsewhere in subpart I
                                            regulations.
----------------------------------------------------------------------------------------------------------------
                                                    Subpart J
----------------------------------------------------------------------------------------------------------------
1002(b)(4); 1007(a)(4)...................  Submit CVA documentation under API RP 17J. (Estimate              100
                                            12 per year).
1002(b)(5)...............................  Submit CVA documentation under API RP 2RD. (Estimate              50
                                            12 per year).
----------------------------------------------------------------------------------------------------------------
* The records required are such that respondents would retain them as a usual and customary business practice.
  The burden would be to make them available to MMS for review.

    As part of our continuing effort to reduce paperwork and respondent 
burdens, MMS invites the public and other Federal agencies to comment 
on any aspect of the reporting burden in the proposed rule. You may 
submit your comments directly to the Office of Information and 
Regulatory Affairs, OMB. Please send a copy of your comments to MMS so 
that we can summarize written comments and address them in the final 
rule preamble. Refer to the Addresses section for mailing instructions.
    The PRA provides that an agency may not conduct or sponsor a 
collection of information unless it displays a currently valid OMB 
control number. Until OMB approves the collection of information and 
assigns a control number, you are not required to respond. The PRA 
requires OMB to make its decision on the information collection aspects 
of this proposed rule between 30 to 60 days after publication in the 
Federal Register. Therefore, a comment to OMB is best assured of having 
its full effect if OMB receives it by January 28, 2002. This does not 
affect the deadline for the public to comment to MMS on the proposed 
regulations.
    a. We specifically solicit comments on the following questions:
    (1) Is the proposed collection of information necessary for MMS to 
properly perform its functions, and will it be useful?
    (2) Are the estimates of the burden hours of the proposed 
collection reasonable?
    (3) Do you have any suggestions that would enhance the quality, 
clarity, or usefulness of the information to be collected?
    (4) Is there a way to minimize the information collection burden on 
those who are to respond, including the use of appropriate automated 
electronic, mechanical, or other forms of information technology?
    b. In addition, the PRA requires agencies to estimate the total 
annual reporting and recordkeeping ``non-hour'' cost burden resulting 
from the collection of information. We have not identified any and 
solicit your comments on this item. For reporting and recordkeeping 
only, your response should split the cost estimate into two components: 
(1) The total capital and startup cost component, and (2) annual 
operation, maintenance, and purchase of services component. Your 
estimates should consider the costs to generate, maintain, and disclose 
or provide the information. You should describe the methods you use to 
estimate major cost factors, including system and technology 
acquisition, expected useful life of capital equipment, discount 
rate(s), and the period over which you incur costs. Generally, your 
estimates should not include equipment or services purchased: before 
October 1, 1995; to comply with requirements not associated with the 
information collection; for reasons other than to provide information 
or keep records for the Government; or as part of a usual and customary 
business or private practice.

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 proposed rule, the annual incremental cost of 
complying with this regulation for approximately 98 businesses will be 
about $190,000 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. 
We do not believe that paying this cost will result in any takings. 
Thus, the Department of the Interior does not need to prepare a Takings 
Implication Assessment under Executive Order 12630, Governmental 
Actions and Interference with Constitutionally Protected Property 
Rights. The proposed 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 
the Office of Management and Budget 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 proposed 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

[[Page 66858]]

resources and would provide more certainty to OCS lessees who assume 
the high financial risks of developing deepwater areas.

Clarity of This Regulation (Executive Order 12866)

    Executive Order 12866 requires each agency to write regulations 
that are easy to understand. We invite your comments on how to make 
this proposed rule easier to understand, including answers to questions 
such as the following:
    (1) Are the requirements in the rule clearly stated?
    (2) Does the rule contain technical language or jargon that 
interferes with its clarity?
    (3) Does the format of the rule (grouping and order of sections, 
use of headings, paragraphing, etc.) aid or reduce its clarity?
    (4) Would the rule be easier to understand if it were divided into 
more (but shorter) sections?
    (5) Is the description of the rule in the Supplementary Information 
section of this preamble helpful in understanding the rule? What else 
can we do to make the rule easier to understand?
    Send a copy of any comments that concern how we could make this 
rule easier to understand to: Office of Regulatory Affairs, Department 
of the Interior, Room 7229, 1849 C Street, NW., Washington, DC 20240. 
You may also e-mail the comments to this address: <a href="/cdn-cgi/l/email-protection#6a2f12190f092a030519440e0503440d051c"><span class="__cf_email__" data-cfemail="a3e6dbd0c6c0e3caccd08dc7ccca8dc4ccd5">[email protected]</span></a>.

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. We have analyzed this 
rule under the criteria of the NEPA and 516 Departmental Manual 6, 
Appendix 10.4C(1). We completed a Categorical Exclusion Review for this 
action on November 20, 2000, and concluded that ``the proposed 
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 required by the UMRA (2 U.S.C. 1531 et seq.) 
is not required.

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: December 3, 2001.
J. Steven Griles,
Acting Assistant Secretary, Land and Minerals Management.

    For the reasons stated in the preamble, the Minerals Management 
Service (MMS) proposes to amend 30 CFR part 250 as follows:

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

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

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

    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. 250.417(b), means a vessel, a structure, or an 
artificial island used for drilling, well completion, well-workover, or 
production operations.
    (4) As used in Secs. 250.900 through 250.918, 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.
* * * * *
    3. In Sec. 250.198, in the table in paragraph (e), the following 
changes are made:
    A. Remove entries for API RP 2A, 19th Edition; API RP 2A-WSD, 20th

[[Page 66859]]

Edition; and API RP 2A-WSD, 20th Edition, Supplement 1.
    B. Add entries in alphanumerical order for API RP 2A-WSD, 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:
    C. Revise entries for ACI Standard 318-95, ACI 357R-84, AISC 
Standard Specification for Structural Steel Buildings, 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 and     Sec.  250.901(a)(2).
 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 for  Sec.  250.901(a)(4).
 Planning, Designing and Constructing
 Fixed Offshore Platforms--Working
 Stress Design; Twenty-first Edition,
 December 2000, API Order No. G2AWSD.
 
*                  *                  *                  *
                  *                  *                  *
API RP 2FPS, Recommended Practice for     Sec.  250.901(a)(5).
 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) and    250.901(a)(6); Sec.
 Tension-Leg Platforms (TLPs), First       250.1002(b)(5).
 Edition, June 1998, API Stock No.G02RD1.
API RP 2SK, Recommended Practice for      Sec.  250.800(b); Sec.
 Design and Analysis of Stationkeeping     250.901(a)(7).
 Systems for Floating Structures, Second
 Edition, December 1996, Effective Date:
 March 1, 1997, API Stock No. G02SK2.
API RP 2SM, Recommended Practice for      Sec.  250.901(a)(8).
 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, Order No.
 G02T02.
 
*                  *                  *                  *
                  *                  *                  *
API RP 14J, Recommended Practice for      Sec.  250.800(b); Sec.
 Design and Hazards Analysis for           250.803(a); Sec.
 Offshore Production Facilities, First     250.901(a)(10).
 Edition, Sept. 1, 1993, API Stock No.
 811-07200.
 
*                  *                  *                  *
                  *                  *                  *
API Spec 17J, Specification for Unbonded  Sec.  250.803(b)(2)(iii); Sec.
 Flexible Pipe, Second Edition, November    250.1002(b)(4); Sec.
 1999, Effective Date: July 1, 2000, API   250.1007(a)(4).
 Stock No. G17J02.
 
*                  *                  *                  *
                  *                  *                  *
ASTM Standard C 33-99a, Standard          Sec.  250.901(a)(11).
 Specification for Concrete Aggregates.
ASTM Standard C 94/C 94M-99, Standard     Sec.  250.901(a)(12).
 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 Code--    Sec.  250.901(a)(16).
 Steel, 1996, including Commentary.
AWS D1.4-79, Structural Welding Code--    Sec.  250.901(a)(17).
 Reinforcing Steel, 1979.
AWS D3.6M:1999, Specification for         Sec.  250.901(a)(18).
 Underwater Welding.
NACE Standard MR0175-99, Sulfide Stress   Sec.  250.417(p)(2); Sec.
 Cracking Resistant Metallic Materials     250.901(a)(19).
 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.
------------------------------------------------------------------------

    4. In Sec. 250.204, paragraph (a)(2) is revised to read as follows:


Sec. 250.204  Development and Production Plan.

    (a) * * *
    (2) A description of any drilling vessels, fixed or floating 
platforms, pipelines, or other facilities and operations located 
offshore which are proposed or known by the lessee (whether or not 
owned or operated by

[[Page 66860]]

the lessee) to be directly related to the proposed development. The 
description must include the location, size, design, and important 
safety, pollution prevention, and environmental monitoring features of 
the facilities and operations. Floating production systems (FPSs) 
include column-stabilized units (CSUs); floating production, storage, 
and offloading facilities (FPSOs); tension-leg platforms (TLPs); spars, 
etc.
* * * * *
    5. In Sec. 250.800, the introductory paragraph 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, 
the lessee, must do all of the following:
    (1) Comply with API RP 14J;
    (2) Meet the drilling and production riser standards of API RP 2RD;
    (3) Meet the production-safety systems requirements contained in 
this subpart;
    (4) Design all stationkeeping systems for floating facilities to 
meet the standards of API RP 2SK, as well as relevant U.S. Coast Guard 
regulations; and
    (5) Design stationkeeping systems for floating facilities to meet 
structural requirements in subpart I, Secs. 250.900 through 250.918 of 
this part.
    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 new floating production platforms, you must comply with 
API RP 14J. For all production platforms, you must comply with the 
following production safety system requirements, in addition to the 
requirements of Sec. 250.802 and the requirements of API RP 14C.
    (b) * * *
    (2) * * *
    (iii) If you are installing flowlines constructed of unbonded 
flexible pipe on a floating platform, you must comply with the 
requirements of API Spec 17J, including its third-party review 
standards for independent verification agents (IVAs). You must submit 
your IVA reviews for flowlines constructed of unbonded flexible pipe 
for review by the MMS District Supervisor.
* * * * *
    7. Subpart I and its title are revised to read as follows:

Subpart I--Fixed and Floating Platforms and Structures

Sec.
250.900   What general requirements apply to fixed and floating 
platforms?
250.901   What industry standards must fixed and floating platforms 
meet?
250.902   What must an application to approve a fixed or floating 
platform contain?
250.903   Which of my platforms, associated structures, and major 
modifications are subject to the Platform Verification Program?
250.904   If my platform, associated structure, or major 
modification is subject to the Platform Verification Program, what 
must I do?
250.905   What plans must I submit under the Platform Verification 
Program?
250.906   When must I resubmit Platform Verification Program plans?
250.907   When must I combine Platform Verification Program plans?
250.908   How do I nominate a CVA?
250.909   What are the CVA's primary responsibilities?
250.910   What are the CVA's primary duties during the design phase?
250.911   What are the CVA's primary duties during the fabrication 
phase?
250.912   What are the CVA's primary duties during the installation 
phase?
250.913   What are the minimum structural fatigue requirements?
250.914   What records must I keep for all primary structural 
members?
250.915   Where must I locate foundation boreholes?
250.916   What in-service inspection requirements must I meet?
250.917   What are the requirements for fixed or floating platform 
removal and location clearance?
250.918   What records must I keep?

Subpart I--Fixed and Floating Platforms and Structures


Sec. 250.900  What general requirements apply to fixed and floating 
platforms?

    (a) You must design, fabricate, install, inspect, and maintain all 
fixed and floating 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. You must submit an application under 
Sec. 250.902 and obtain the approval of the Regional Supervisor before 
installing any platform or performing any of the other activities 
described in the following table:

------------------------------------------------------------------------
           Activity               Conditions to be met for application
------------------------------------------------------------------------
(1) Install a platform.......  You must adhere to the requirements of
                                this subpart, including the industry
                                standards in Sec.  250.901
(2) Make a major modification  Major modifications are any structural
 to any platform.               changes that materially alter the
                                approved plan or cause a major deviation
                                from approved operations. They are
                                subject to the requirements of this
                                subpart, including the industry
                                standards in Sec.  250.901
(3) Make a major repair to     Major repairs of damage are corrective
 damage to any platform.        operations involving structural members
                                affecting the structural integrity of a
                                portion or all of the platform. They are
                                subject to the requirements of this
                                subpart, including the industry
                                standards in Sec.  250.901
(4) Make an emergency repair   Under emergency conditions, you may make
 to a primary structural        repairs to primary structural elements
 element to restore an          to restore an existing permitted
 existing permitted condition.  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
(5) Conversion of the use of   The Regional Supervisor will determine on
 an existing mobile offshore    a case-by-case basis the requirements
 drilling unit (MODU).          for an application for conversion of an
                                existing MODU. Your application must
                                include:
                               (i) The converted MODU's intended
                                location and use;
                               (ii) A demonstration of the adequacy of
                                the design and structural condition of
                                the converted MODU; and
                               (iii) A demonstration that the level of
                                safety for the converted MODU is at
                                least equal to that of reused platforms.
------------------------------------------------------------------------


[[Page 66861]]

    (b) You must design, fabricate, install, inspect, and maintain all 
new fixed or bottom-founded platforms (e.g., template type, tower type, 
caisson, gravity-base type, artificial island, etc.) according to all 
the requirements of this section, Sec. 250.901 (including applicable 
referenced documents), Sec. 250.902, and Secs. 250.913 through 250.918.
    (c) Section 250.903 fully describes the facilities that are subject 
to the Platform Verification Program. In brief, all floating platforms 
are subject to the Platform Verification Program. Also, all fixed or 
bottom-founded platforms that meet certain conditions listed in 
Sec. 250.903(a) are subject to the Platform Verification Program.


Sec. 250.901  What industry standards must fixed and floating platforms 
meet?

    (a) In addition to the other requirements of this subpart, your 
plans for fixed or floating platform design, analysis, fabrication, and 
installation must, as appropriate, conform to:
    (1) American Concrete Institute (ACI) Standard 318, Building Code 
Requirements for Reinforced Concrete, plus Commentary.
    (2) ACI 357R, Guide for the Design and Construction of Fixed 
Offshore Concrete Structures;
    (3) American Institute of Steel Construction (AISC) Standard 
Specification for Structural Steel Buildings, Allowable Stress Design 
and Plastic Design;
    (4) American Petroleum Institute (API) Recommended Practice (RP) 
2A, Recommended Practice for Planning, Designing, and Constructing 
Fixed Offshore Platforms;
    (5) API RP 2FPS, Recommended Practice for Planning, Designing, and 
Constructing Floating Production Systems;
    (6) API RP 2RD, Design of Risers for Floating Production Systems 
(FPSs) and Tension-Leg Platforms (TLPs);
    (7) API RP 2SK, Recommended Practice for Design and Analysis of 
Station Keeping Systems for Floating Structures;
    (8) API RP 2SM, Recommended Practice for Design, Manufacture, 
Installation, and Maintenance of Synthetic Fiber Ropes for Offshore 
Mooring;
    (9) API RP 2T, Recommended Practice for Planning, Designing and 
Constructing Tension Leg Platforms;
    (10) API RP 14J, Recommended Practice for Design and Hazards 
Analysis for Offshore Production Facilities;
    (11) American Society for Testing and Materials (ASTM) Standard C 
33-99a, Standard Specification for Concrete Aggregates;
    (12) ASTM Standard C 94/C 94M-99, Standard Specification for Ready-
Mixed Concrete;
    (13) ASTM Standard C 150-99, Standard Specification for Portland 
Cement;
    (14) ASTM Standard C 330-99, Standard Specification for Lightweight 
Aggregates for Structural Concrete;
    (15) ASTM Standard C 595-98, Standard Specification for Blended 
Hydraulic Cements;
    (16) AWS D1.1, Structural Welding Code--Steel;
    (17) AWS D1.4, Structural Welding Code--Reinforcing Steel;
    (18) AWS D3.6M, Specification for Underwater Welding;
    (19) NACE Standard MR0175, Sulfide Stress Cracking Resistant 
Metallic Materials for Oilfield Equipment; and
    (20) NACE Standard RP 01-76-94, Standard Recommended Practice, 
Corrosion Control of Steel Fixed Offshore Platforms Associated with 
Petroleum Production.
    (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, paragraphs (a), (b), and (c) of this part.
    (c) For information on all standards mentioned in this section, see 
Sec. 250.198 of this part.


Sec. 250.902  What must an application to approve a fixed or floating 
platform contain?

    You must submit to the Regional Supervisor for approval all 
applications under this subpart and all significant changes or 
modifications to approved applications. Your application for all new 
fixed or floating platforms or major modifications must contain all of 
the following general facility information:

----------------------------------------------------------------------------------------------------------------
         Required documents                         Required contents                     Other requirements
----------------------------------------------------------------------------------------------------------------
(a) Application cover letter.......  Proposed facility designation, lease number,     You must submit three
                                      area, name, and block number, and the type of    copies.*
                                      facility (e.g., drilling, production,
                                      quarters)..
(b) Location plat..................  Latitude and longitude coordinates, Universal    Your plat must be drawn to
                                      Mercator grid-system coordinates, state plane    a scale of 1 inch equals
                                      coordinates in the Lambert or Transverse         2,000 feet and include
                                      Mercator Projection System, and distances in     the coordinates of the
                                      feet from nearest block lines.                   the lease block boundary
                                                                                       lines. You must submit
                                                                                       three copies.*
(c) Front, Side, and Plan View       Platform dimensions and orientation, elevations  Your drawing sizes must
 drawings.                            relative to M.S.L., and pile sizes and           not exceed 11" x 17". You
                                      penetrations.                                    must submit three
                                                                                       copies.*
(d) Complete set structural          ...............................................  Your drawing sizes must
 drawings.                                                                             not exceed 11" x 17". You
                                                                                       must submit one copy.
(e) Summary of environmental data..  A Summary of the environmental data described    You must submit one copy.
                                      in the standards referenced under Sec.
                                      250.901(a) and in Sec.  250.198 of this part,
                                      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 enigneering       Loading information (e.g., live, dead,           You must submit one copy.
 design data.                         environmental), structural information (e.g.,
                                      design-life, material types, cathodic
                                      protection systems, design criteria fatigue
                                      life, fabrication and installation
                                      guidelines), and foundation information (e.g.,
                                      soil stability, design criteria).

[[Page 66862]]

 
(g) Project-specific...............  All studies pertinent to platform design or      You must submit one copy
                                      installation, e.g., soil and/or oceanographic    each study.
                                      reports.
(h) Description of the loads         Loads imposed by production and pipeline risers  You must submit one copy.
 imposed on the facility.             and mooring and anchoring systems.
(i) A copy of the inservice          This plan is described in Sec. 250.916.........  You must submit one copy.
 inspection plan.
(j) Certification..................  The following statement: ``The design of this    An authorized company must
                                      structure has been certified by a recognized     sign the registered
                                      classification society, or a registered civil    statement. You must
                                      or structural engineer, or equivalent,           submit one copy.
                                      specializing in the design of offshore
                                      structures. The certified design and as-built
                                      plans and specifications will be on file at
                                      (give location)''.
----------------------------------------------------------------------------------------------------------------
*For your facilities subject to Platform Verification Program requirements in Secs.  250.903 through 250.912,
  you must submit one additional copy of these items (four copies total).

Sec. 250.903  Which of my platforms, associated structures, and major 
modifications 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. Floating platforms include floating production 
systems (FPSs) such as column-stabilized units (CSUs); floating 
production, storage and offloading systems (FPSOs); tension-leg 
platforms (TLPs); spars, etc. The following structures that may be 
associated with a floating platform are also subject to the Platform 
Verification Program:
    (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.
    (c) Platform Verification Program requirements apply to any major 
modification to a fixed or floating platform covered under this 
section.
    (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. 250.904  If my platform, associated structure, or major 
modification is subject to the Platform Verification Program, what must 
I do?

    If your platform, associated structure, or major modification meets 
the criteria in Sec. 250.903, you must:
    (a) Design, fabricate, and install your facility, associated 
structures, or major modification to your facility according to the 
requirements of Secs. 250.900 through 250.918, and the applicable 
documents listed in Sec. 250.901(a);
    (b) Submit for the Regional Supervisor's approval three copies each 
of the design verification, fabrication verification, and installation 
verification plans required by Sec. 250.905; and
    (c) Include as a part of each verification plan required by 
Sec. 250.905 your nomination of a Certified Verification Agent (CVA);
    (d) Follow the additional requirements in Secs. 250.906 through 
250.912; and
    (e) Prepare and submit for MMS review, plans for ship-shaped FPSs 
which are modified to address in detail only those items listed in 
Sec. 250.903(b). For detailed requirements pertaining to the ship-
shaped hull and superstructure, you must refer to, and comply with 
applicable U.S. Coast Guard regulations.


Sec. 250.905  What plans must I submit under the Platform Verification 
Program?

    If your platform, associated structure, or major modification meets 
the criteria in Sec. 250.903, you must submit all of the following 
plans required by this section:
    (a) Design verification plan. You may submit your design 
verification plan with or subsequent to the submittal of your 
Exploration Plan (EP) or Development and Production Plan (DPP). You may 
not submit your design verification plan before you submit your EP or 
DPP. Your design verification must be conducted by, or be under the 
direct supervision of, a registered professional civil or structural 
engineer or equivalent, with previous experience in directing the 
design of similar facilities, systems, structures, or equipment. Your 
design verification plan must include the following:
    (1) All design documentation specified in Sec. 250.902;
    (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. You must submit your fabrication 
verification plan to the Regional Supervisor, and 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- 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. You must submit your 
installation verification plan to the Regional Supervisor, and 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;

[[Page 66863]]

    (2) Contingencies considered;
    (3) Alternative courses of action; and
    (4) The inspections to be performed, including an identification of 
areas to be inspected and the acceptance and rejection criteria to be 
used.


Sec. 250.906  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. 250.907  When must I combine Platform Verification Program plans?

    You must combine fabrication verification and installation 
verification plans for manmade islands or platforms fabricated and 
installed in place.


Sec. 250.908  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; 
for two phases; or for all three phases.
    (b) For each CVA, you must submit a qualification statement that 
includes the following:
    (1) Previous experience in third-party verification or experience 
in the design, fabrication, or installation of fixed offshore oil and 
gas platforms, similar facilities and other structures, floating 
platforms, manmade islands, other marine structures, and related 
systems and equipment;
    (2) Technical capabilities of the individual or the primary staff 
to be associated with the CVA functions for the specific project;
    (3) Size and type of organization or corporation;
    (4) In-house availability of, or access to, appropriate technology, 
i.e., computer programs and 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; and
    (8) A list of documents to be furnished to the CVA.


Sec. 250.909  What are the CVA's primary responsibilities?

    (a) The CVA nominated by you and approved by the Regional 
Supervisor must conduct specified reviews according to Secs. 250.910, 
250.911, and 250.912.
    (b) The CVA must handle all data you provide in the strictest 
confidence. Other than to MMS, the CVA must not release any data 
without your consent.
    (c) Individuals or organizations acting as CVAs for a particular 
platform or floating facility must not function in any capacity other 
than that of a CVA for that specific project whenever the additional 
activities would create a conflict of interest, or the appearance of a 
conflict of interest.


Sec. 250.910  What are the CVA's primary duties during the design 
phase?

    (a) The CVA must conduct the design verification to ensure that the 
proposed fixed or floating platform or major modification is designed 
to withstand the maximum environmental and functional load conditions 
anticipated during the intended service life at the proposed location.
    (b) The CVA must consider the applicable provisions of the 
documents listed in Sec. 250.901(a) and of Secs. 250.913 through 
250.915 and use good engineering practice in conducting an independent 
assessment of the adequacy of all proposed:
    (1) Planning criteria;
    (2) Operational requirements;
    (3) Environmental data;
    (4) Load determinations;
    (5) Stress analyses;
    (6) Material designations;
    (7) Soil and foundation conditions;
    (8) Safety factors; and
    (9) Other pertinent parameters of the proposed design.
    (c) The CVA must submit interim reports to the Regional Supervisor 
and to you, as appropriate.
    (d) The CVA, upon completion of the design verification, must 
prepare a final report which summarizes the material reviewed and the 
CVA's findings. The CVA must submit one copy of the report to the 
Regional Supervisor. The CVA must make this submittal within 6 weeks of 
the receipt of the design data or from the date the approval to act as 
a CVA was issued, whichever is later. The final report must include:
    (1) The CVA's recommendation that the Regional Supervisor either 
accept, request modifications, or reject the proposed design;
    (2) The particulars of how, by whom, and when the independent 
review was conducted; and
    (3) Any special comments the CVA may deem necessary.


Sec. 250.911  What are the CVA's primary duties during the fabrication 
phase?

    (a) The CVA must monitor the fabrication of the fixed or floating 
platform or major modification to ensure that it has been built 
according to the approved design plans and specifications and the 
fabrication plan.
    (b) The CVA must make periodic onsite inspections while fabrication 
is in progress. The CVA must verify the following fabrication items, as 
appropriate:
    (1) Quality control by lessee and builder;
    (2) Fabrication site facilities;
    (3) Material quality and identification methods;
    (4) Fabrication procedures specified in the approved plan and 
adherence to such procedures;
    (5) Welder and welding procedure qualification and identification;
    (6) Structural tolerences specified and adherence to those 
tolerances;
    (7) The nondestructive examination requirements and evaluation 
results of the specified examinations;
    (8) Destructive testing requirements and results;
    (9) Repair procedures;
    (10) Installation of corrosion-protection systems and splash-zone 
protection;
    (11) Erection procedures to ensure that overstressing of structural 
members does not occur;
    (12) Alignment procedures;
    (13) Dimensional check of the overall structure, including any 
turrets, turret and hull interfaces, any mooring line and chain and 
riser tensioner line segments; and
    (14) Status of quality-control records at various stages of 
fabrication.
    (c) The CVA must consider the applicable provisions of the 
documents listed in Sec. 250.901(a) and of Secs. 250.913 through 
250.915 and use good engineering practice in conducting the independent 
assessment of the adequacy of the fabrication of the fixed or floating 
platform or major modification.
    (d) The CVA must submit interim reports to the Regional Supervisor 
and to you, as appropriate.
    (e) 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.

[[Page 66864]]

    (f) The CVA must prepare a final report covering the adequacy of 
the entire fabrication phase. The CVA is not required in the final 
report to cover aspects of the fabrication already included in interim 
reports. The CVA must submit one copy of the report to the Regional 
Supervisor immediately after completion of the fabrication of the fixed 
or floating platform. In the report the CVA must:
    (1) Give details of how, by whom, and when the independent 
monitoring activities were conducted;
    (2) Provide any special comments that the CVA deems necessary;
    (3) Describe the CVA's activities during the verification process;
    (4) Summarize the CVA's findings
    (5) Confirm or deny compliance with the design specifications and 
the approved fabrication plan; and
    (6) Make a recommendation to accept or reject the fabrication.


Sec. 250.912  What are the CVA's primary duties during the installation 
phase?

    (a) The CVA must perform the following:
    (1) Witness the loadout of the jacket, decks, piles, or structures 
from each fabrication site;
    (2) Review the towing records;
    (3) Witness the loadout of a floating platform;
    (4) Conduct an onsite survey after transportation to the approved 
location;
    (5) Witness the actual installation of the fixed or floating 
platform or major modification;
    (6) For floating platforms, witness the installation of the 
mooring, tethering, and anchoring systems; and
    (7) Determine that the platform has been installed at the approved 
location according to the approved design and the installation plan.
    (b) The CVA must consider the applicable provisions of the 
documents listed in Sec. 250.901(a) and of Secs. 250.913 through 
250.915 and use good engineering practice in conducting an independent 
assessment of the adequacy of the installation activities. The CVA must 
verify the following parts of the overall installation process, as 
appropriate:
    (1) Loadout and initial flotation operations, if any;
    (2) Towing operations to the specified location;
    (3) Launching and uprighting operations;
    (4) Submergence operations;
    (5) Pile or anchor installation;
    (6) Installation of mooring and tethering systems; and
    (7) Final deck and component installations on fixed and floating 
offshore facilities.
    (c) The CVA must observe the installation activities, spot-check 
equipment, procedures, and recordkeeping, as necessary, to determine 
compliance with the applicable documents listed in Sec. 250.901(a) and 
of Secs. 250.913 through 250.915 and the approved plans, and 
immediately report to you and the Regional Supervisor any discrepancies 
or damage to structural members. You must obtain approval for modified 
installation procedures or for major deviations from approved 
installation procedures from the Regional Supervisor.
    (d) The CVA must submit interim reports to you and the Regional 
Supervisor, as appropriate.
    (e) 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 2 weeks of completion of the 
installation of the platform. In the report, the CVA must:
    (1) Give details of how, by whom, and when the independent 
monitoring activities were conducted;
    (2) Provide any special comments that the CVA deems necessary;
    (3) Describe the CVA's activities during the verification process;
    (4) Summarize the CVA's findings;
    (5) Write a confirmation or denial of compliance with the approved 
installation plan; and
    (6) Provide recommendation to accept or reject the installation.


Sec. 250.913  What are the minimum structural fatigue requirements?

    There are numerous circumstances in which it may be necessary to 
conduct a detailed analysis of cumulative fatigue damage on structural 
members and joints. The following table provides minimal requirements 
for structural members and joints which require a detailed analysis of 
cumulative fatigue damage.

------------------------------------------------------------------------
                If * * *                            Then * * *
------------------------------------------------------------------------
(a) There is sufficient structural       The results of the analysis
 redundancy to prevent catastrophic       must indicate a minimum
 failure of the member or join under      calculated life of twice the
 consideration.                           design life of the platform.
(b) There is not sufficient structural   The results of a fatigue
 reduncancy to prevent catastrophic       analysis must indicate a
 failure of the member or joint.          minimum calculated life of
                                          three times the design life of
                                          the platform.
(c) The desirable degree of redundancy   The results of a fatigue
 is significantly reduced as a result     analysis must indicate a
 of fatigue damage.                       minimum calculated life of
                                          three times the design life of
                                          the platform.
------------------------------------------------------------------------

Sec. 250.914  What records must I keep for all primary structural 
members?

    You must record and retain the origin and relevant material test 
results of all primary structural materials during all stages of 
construction. Primary material is material that, should it fail, it 
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).


Sec. 250.915  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. 250.916  What in-service inspection requirements must I meet?

    (a) You must develop an in-service inspection plan. As a minimum, 
your plan must fulfill the recommendations of the appropriate API 
documents listed in Sec. 250.901(a). Your plan must specify the type, 
extent, and frequency of in-place inspections which your contractor 
will conduct for both the above water and the under water structure of 
all platforms, and pertinent components of the mooring systems for 
floating platforms.

[[Page 66865]]

    (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. 250.917  What are the requirements for fixed or floating platform 
removal and location clearance?

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


Sec. 250.918  What records must I keep?

    You must compile, retain, and make available to MMS representatives 
for the functional life of all fixed or floating platforms:
    (a) The as-built drawings;
    (b) The design assumptions and analyses;
    (c) A summary of the fabrication and installation nondestructive 
examination records; and
    (d) The inspection results from the inspections required by 
Sec. 250.916.
    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, they must be built according to the standards and the 
third-party review standards for an independent verification agent 
(IVA) in API Spec 17J.
    (5) You must construct pipeline risers for tension leg platforms 
and other floating platforms according to the design standards of API 
RP 2RD.
* * * * *
    9. In Sec. 250.1007, a new sentence is added at the end of 
paragraph (a)(4) to read as follows:


Sec. 250.1007  What to include in applications.

    (a) * * *
    (4) * * * If your application involves using unbonded flexible 
pipe, you must include a review by a third-party IVA according to API 
Spec 17J.
* * * * *
[FR Doc. 01-31723 Filed 12-26-01; 8:45 am]
BILLING CODE 4310-MR-P


</pre><script data-cfasync="false" src="/cdn-cgi/scripts/5c5dd728/cloudflare-static/email-decode.min.js"></script></body>
</html>