Federal Register / Vol. 66, No. 248 / Thursday, December 27, 2001 / Proposed Rules 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 columnstabilized 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

rules.comments@mms.gov. 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 ‘‘leapfrogging’’ 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

66852 Federal Register / Vol. 66, No. 248 / Thursday, December 27, 2001 / Proposed Rules

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-bycase 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 netpresent-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 secondtier 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

Federal Register / Vol. 66, No. 248 / Thursday, December 27, 2001 / Proposed Rules 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 bottomfounded 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,

66854 Federal Register / Vol. 66, No. 248 / Thursday, December 27, 2001 / Proposed Rules

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 § 250.800(b), and subpart

I at proposed § 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 § 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, § 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

§ 250.900 What general requirements apply to fixed and floating platforms?§ 250.900; New requirement.

§ 250.901 What industry standards must fixed and floating platforms

meet?

§ 250.900(g); § 250.907(b), (c), (d); § 250.908 (b), (c), (d), (e); New requirements.

§ 250.902 What must an application to approve a fixed, or floating platform contain?§ 250.901(a), (b)

§ 250.903 Which of my platforms, associated structures, and major

modifications are subject to the Platform Verification Program?

250.902; New requirements.

§ 250.904 If my platform, associated structure, or major modification is

subject to the Platform Verification Program, what must I do?

§ 250.902; New requirements.

§ 250.905 What plans must I submit under the Platform Verification

Program?

§ 250.902; New requirements.

§ 250.906 When must I resubmit Platform Verification Program plans? § 250.902; New requirements.

§ 250.907 When must I combine Platform Verification Program plans? § 250.902; New requirements.

§ 250.908 How do I nominate a CVA? § 250.902; § 250.903(b).

§ 250.909 What are the CVA’s primary responsibilities? § 250.903(a).

§ 250.910 What are the CVA’s primary duties during the design phase? § 250.903(a)(1).

§ 250.911 What are the CVA’s primary duties during the fabrication

phase?

§ 250.903(a)(2).

§ 250.912 What are the CVA’s primary duties during the installation

phase?

§ 250.903(a)(3).

§ 250.913 What are the minimum structural fatigue requirements? § 250.907(c).

§ 250.914 What records must I keep for all primary structural members?§ 250.907(a).

§ 250.915 Where must I locate foundation boreholes? New requirements.

§ 250.916 What in-service inspection requirements must I meet? § 250.912(b); New requirements.

§ 250.917 What are the requirements for fixed or floating platform removal and location clearance?§ 250.913

§ 250.918 What records must I keep? § 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

Federal Register / Vol. 66, No. 248 / Thursday, December 27, 2001 / Proposed Rules 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 foreignbased 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

66856 Federal Register / Vol. 66, No. 248 / Thursday, December 27, 2001 / Proposed Rules

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 thirdparty 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

§ 250.901(e) on transporting the

platform to the installation site, and the

departure request in § 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.

Citation 30 CFR 250 proposed section Reporting or recordkeeping requirement

Hour burden

per response

or record

(hours)

Subpart H

800(b) ........................................................ Submit CVA documentation under API RP 2RD. (Estimate 60 per year) .................. 50

803(b)(2)(iii) .............................................. Submit CVA documentation under API RP 17J. (Estimate 6 per year) ...................... 50

Subpart I

900(a); 901(b); 902; 903; 905; 907 .......... Submit application to install new fixed or floating 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.

24

900(a)(2); 903(c); 906 ............................... Submit application for major modification to any platform .......................................... 24

900(a)(4) ................................................... Notify MMS within 24 hours of damage and emergency repairs and request approval of repairs.16

900(a)(5) ................................................... Submit application for the conversion of the use of an existing mobile offshore drilling unit (MODU).24

901(a)(6), (a)(7), (a)(8) ............................. NEW: Submit CVA documentation under API RP 2RD, API RP 2SK, and API RP

2SM. (Estimate 6 per year).

100

901(a)(10) ................................................. NEW: Submit hazards analysis documentation under API RP 14J. (Estimate 6 per

year).

500

904(c); 908 ................................................ Submit nomination and qualification statement for CVA ............................................. 16

910(c), (d) ................................................. Submit interim and final CVA reports and recommendations on design phase ......... 200

911(d), (e), (f) ........................................... NEW: Submit interim and final CVA reports and recommendations on fabrication

phase, including notice of fabrication procedure changes or design specification

modifications. (Estimate 6 per year).

60

912(c), (d), (e) ........................................... NEW: Submit interim and final CVA reports and recommendations on installation

phase, including notice of any discrepancies or damage to structural members.

(Estimate 6 per year).

60

914; 918: See footnote* ............................ Recordkeeping: Record origin and relevant material test results of all primary structural materials; retain records during all stages of construction. Compile, retain,

and make available to MMS for the functional life of platform, the as-built drawings, design assumptions/analyses, summary of nondestructive examination

records, and inspection results.

50

Federal Register / Vol. 66, No. 248 / Thursday, December 27, 2001 / Proposed Rules 66857

Citation 30 CFR 250 proposed section Reporting or recordkeeping requirement

Hour burden

per response

or record

(hours)

916 ............................................................ Develop in-service inspection plan and submit annual (November 1 of each year)

report on inspection of fixed or floating platforms, including summary of testing

results.

45

900 thru 918 ............................................. General departure and alternative compliance requests not specifically covered

elsewhere in subpart I regulations.

2

Subpart J

1002(b)(4); 1007(a)(4) .............................. Submit CVA documentation under API RP 17J. (Estimate 12 per year) .................... 100

1002(b)(5) ................................................. Submit CVA documentation under API RP 2RD. (Estimate 12 per year) .................. 50

* 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 ‘‘nonhour’’ 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

66858 Federal Register / Vol. 66, No. 248 / Thursday, December 27, 2001 / Proposed Rules

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: Exsec@ios.doi.gov.

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 § 250.105, the definition for

‘‘facility,’’ is revised to read as follows:

§ 250.105 Definitions.

* * * * *

Facility means: (1) As used in

§ 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 columnstabilized-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 § 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 skidoff 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 § 250.417(b), means a

vessel, a structure, or an artificial island

used for drilling, well completion, wellworkover, or production operations.

(4) As used in §§ 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 § 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

Federal Register / Vol. 66, No. 248 / Thursday, December 27, 2001 / Proposed Rules 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.

§ 250.198 Documents incorporated by

reference.

* * * * *

(e) * * *

Title of documents Incorporated by reference at

*******

ACI Standard 318–95, Building Code Requirements for Reinforced Concrete, plus

Commentary on Building Code Requirements for Reinforced Concrete (ACI

318R–95).

§ 250.901(a)(1).

ACI 357R–84, Guide for the Design and Construction of Fixed Offshore Concrete

Structures, 1984.

§ 250.901(a)(2).

AISC Standard Specification for Structural Steel Buildings, Allowable Stress Design and Plastic Design, June 1, 1989, with Commentary.§ 250.901(a)(3).

*******

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.§ 250.901(a)(4).

*******

API RP 2FPS, Recommended Practice for Planning, Designing, and Constructing

Floating Production Systems, First Edition, March 2001, API Order No.

G2FPS1.

§ 250.901(a)(5).

API RP 2RD, Design of Risers for Floating Production Systems (FPSs) and Tension-Leg Platforms (TLPs), First Edition, June 1998, API Stock No.G02RD1.§ 250.800(b); § 250.901(a)(6); § 250.1002(b)(5).

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.

§ 250.800(b); § 250.901(a)(7).

API RP 2SM, Recommended Practice for Design, Manufacture, Installation, and

Maintenance of Synthetic Fiber Ropes for Offshore Mooring, First Edition,

March 2001, API Order No. G02SM1.

§ 250.901(a)(8).

API RP 2T, Planning, Designing and Constructing Tension Leg Platforms, Second

Edition, August 1997, Order No. G02T02.

§ 250.901(a)(9).

*******

API RP 14J, Recommended Practice for Design and Hazards Analysis for Offshore Production Facilities, First Edition, Sept. 1, 1993, API Stock No. 811–

07200.

§ 250.800(b); § 250.803(a); § 250.901(a)(10).

*******

API Spec 17J, Specification for Unbonded Flexible Pipe, Second Edition, November 1999, Effective Date: July 1, 2000, API Stock No. G17J02.§ 250.803(b)(2)(iii); § 250.1002(b)(4); § 250.1007(a)(4).

*******

ASTM Standard C 33–99a, Standard Specification for Concrete Aggregates ......... § 250.901(a)(11).

ASTM Standard C 94/C 94M–99, Standard Specification for Ready-Mixed Concrete.§ 250.901(a)(12).

ASTM Standard C 150–99, Standard Specification for Portland Cement ................ § 250.901(a)(13).

ASTM Standard C 330–99, Standard Specification for Lightweight Aggregates for

Structural Concrete.

§ 250.901(a)(14).

ASTM Standard C 595–98, Standard Specification for Blended Hydraulic Cements.§ 250.901(a)(15).

AWS D1.1–96, Structural Welding Code—Steel, 1996, including Commentary ...... § 250.901(a)(16).

AWS D1.4–79, Structural Welding Code—Reinforcing Steel, 1979 ......................... § 250.901(a)(17).

AWS D3.6M:1999, Specification for Underwater Welding ........................................ § 250.901(a)(18).

NACE Standard MR0175–99, Sulfide Stress Cracking Resistant Metallic Materials

for Oilfield Equipment, Revised January 1999, NACE Item No. 21302.

§ 250.417(p)(2); § 250.901(a)(19).

NACE Standard RP 01–76–94, Standard Recommended Practice, Corrosion

Control of Steel Fixed Offshore Platforms Associated with Petroleum Production.

§ 250.901(a)(20).

4. In § 250.204, paragraph (a)(2) is

revised to read as follows:

§ 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

66860 Federal Register / Vol. 66, No. 248 / Thursday, December 27, 2001 / Proposed Rules

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 § 250.800, the introductory

paragraph is redesignated as paragraph

(a), and a new paragraph (b) is added to

read as follows:

§ 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, §§ 250.900

through 250.918 of this part.

6. In § 250.803, paragraph (a) is

revised and paragraph (b)(2)(iii) is

added to read as follows:

§ 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

§ 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

§ 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

§ 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

§ 250.901

(2) Make a major modification to any platform .. Major modifications are any structural 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 § 250.901

(3) Make a major repair to damage to any platform.Major repairs of damage are corrective 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 § 250.901

(4) Make an emergency repair to a primary

structural element to restore an existing permitted condition.

Under emergency conditions, you may make repairs to primary structural elements to restore

an existing permitted condition without an application or prior approval. You must notify the

Regional Supervisor of the damage that occurred within 24 hours, and you must notify the

Regional Supervisor of the repairs that were made within 24 hours of completing the repairs

(5) Conversion of the use of an existing mobile

offshore drilling unit (MODU).

The Regional Supervisor will determine on a case-by-case basis the requirements 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.

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(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, § 250.901 (including applicable

referenced documents), § 250.902, and

§§ 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

§ 250.903(a) are subject to the Platform

Verification Program.

§ 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 § 250.141,

paragraphs (a), (b), and (c) of this part.

(c) For information on all standards

mentioned in this section, see § 250.198

of this part.

§ 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, area, name, and block

number, and the type of facility (e.g., drilling, production, quarters)..

You must submit three copies.*

(b) Location plat ............................... Latitude and longitude coordinates, Universal Mercator grid-system

coordinates, state plane coordinates in the Lambert or Transverse

Mercator Projection System, and distances in feet from nearest

block lines.

Your plat must be drawn to a

scale of 1 inch equals 2,000

feet and include the coordinates

of the the lease block boundary

lines. You must submit three

copies.*

(c) Front, Side, and Plan View drawings.Platform dimensions and orientation, elevations relative to M.S.L.,

and pile sizes and penetrations.

Your drawing sizes must not exceed 11′′ x 17′′. You must submit three copies.*

(d) Complete set structural drawings ............................................................................................................... Your drawing sizes must not exceed 11′′ x 17′′. You must submit one copy.

(e) Summary of environmental data A Summary of the environmental data described in the standards

referenced under § 250.901(a) and in § 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.

You must submit one copy.

(f) Summary of the enigneering design data.Loading information (e.g., live, dead, 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).You must submit one copy.

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Required documents Required contents Other requirements

(g) Project-specific ............................ All studies pertinent to platform design or installation, e.g., soil and/or

oceanographic reports.

You must submit one copy each

study.

(h) Description of the loads imposed

on the facility.

Loads imposed by production and pipeline risers and mooring and

anchoring systems.

You must submit one copy.

(i) A copy of the inservice inspection

plan.

This plan is described in §250.916 ...................................................... You must submit one copy.

(j) Certification .................................. The following statement: ‘‘The design of this structure has been certified by a recognized classification society, or a registered civil or

structural engineer, or equivalent, specializing in the design of offshore structures. The certified design and as-built plans and specifications will be on file at (give location)’’.

An authorized company must sign

the registered statement. You

must submit one copy.

*For your facilities subject to Platform Verification Program requirements in §§ 250.903 through 250.912, you must submit one additional copy

of these items (four copies total).

§ 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.

§ 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 § 250.903, you must:

(a) Design, fabricate, and install your

facility, associated structures, or major

modification to your facility according

to the requirements of §§ 250.900

through 250.918, and the applicable

documents listed in § 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 § 250.905; and

(c) Include as a part of each

verification plan required by § 250.905

your nomination of a Certified

Verification Agent (CVA);

(d) Follow the additional

requirements in §§ 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 § 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.

§ 250.905 What plans must I submit under

the Platform Verification Program?

If your platform, associated structure,

or major modification meets the criteria

in § 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 § 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;

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(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.

§ 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.

§ 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.

§ 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.

§ 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 §§ 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.

§ 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 § 250.901(a) and of §§ 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.

§ 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 corrosionprotection 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 § 250.901(a) and of §§ 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.

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(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.

§ 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 § 250.901(a) and of §§ 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

§ 250.901(a) and of §§ 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.

§ 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 redundancy to prevent catastrophic failure of the member or join under consideration.The results of the analysis must indicate a minimum calculated life of

twice the design life of the platform.

(b) There is not sufficient structural reduncancy to prevent catastrophic

failure of the member or joint.

The results of a fatigue analysis must indicate a minimum calculated

life of three times the design life of the platform.

(c) The desirable degree of redundancy is significantly reduced as a result of fatigue damage.The results of a fatigue analysis must indicate a minimum calculated

life of three times the design life of the platform.

§ 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).

§ 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.

§ 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 § 250.901(a). Your plan must specify

the type, extent, and frequency of inplace 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.

Federal Register / Vol. 66, No. 248 / Thursday, December 27, 2001 / Proposed Rules 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.

§ 250.917 What are the requirements for

fixed or floating platform removal and

location clearance?

You must remove all structures

according to §§ 250.1725 through

250.1730 of Subpart Q—

Decommissioning Activities—of this

part.

§ 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 § 250.916.

8. In § 250.1002 paragraphs (b)(4) and

(b)(5) are added to read as follows:

§ 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 § 250.1007, a new sentence is

added at the end of paragraph (a)(4) to

read as follows:

§ 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

DEPARTMENT OF TRANSPORTATION

Coast Guard

33 CFR Part 117

[CGD09–01–148]

RIN–2115–AE47

Drawbridge Operation Regulations;

Chicago River, IL

AGENCY: Coast Guard, DOT.

ACTION: Notice of proposed rulemaking.

SUMMARY: The Coast Guard proposes to

revise the operating regulation

governing drawbridges over Chicago

River waterways. The proposed rule

would add Division Street bridge, mile

3.30, over the North Branch of Chicago

River, to the current list of bridges not

required to open for navigation; remove

the requirement for Kinzie Street bridge,

mile 1.81 over North Branch of Chicago

River, and Cermak Road bridge, mile

4.05 over South Branch of Chicago

River, to open on signal for commercial

vessels due to the recently

accomplished increases in vertical

clearances; require a 12-hour advance

notice requirement from commercial

vessels year-round for City of Chicago

moveable bridges; update ownership of

certain railroad bridges; specify rush

hour times (7 a.m. to 10 a.m. and 4 p.m.

to 6:30 p.m.—Monday through Friday,

with the exception of Federal holidays)

that City of Chicago bridges would not

be required to open for any vessels; and

generally make the regulation easier to

read and understand.

DATES: Comments must be received on

or before February 25, 2002.

ADDRESSES: Comments may be mailed

or delivered to: Commander (obr), Ninth

Coast Guard District, 1240 East Ninth

Street, Room 2019, Cleveland, OH,

44199–2060 between 8 a.m. and 3 p.m.,

Monday through Friday, except Federal

holidays. The telephone number is (216)

902–6084.

FOR FURTHER INFORMATION CONTACT: Mr.

Scot M. Striffler, Project Manager, Ninth

Coast Guard District Bridge Branch, at

(216) 902–6084.

SUPPLEMENTARY INFORMATION:

Request for Comments

The Coast Guard encourages

interested persons to participate in this

rulemaking by submitting written data,

views or arguments for or against this

rule. Persons submitting comments

should include names and addresses,

identify the rulemaking [CGD09–01–

148] and the specific section of this

proposal to which each comment

applies, and give the reason(s) for each

comment. Please submit all comments

and attachments in an unbound format,

no larger than 81⁄2 by 11 inches, suitable

for copying and electronic filing.

Persons wanting acknowledgement of

receipt of comments should enclose a

stamped, self-addressed postcard or

envelope.

The Coast Guard plans no public

hearing. Individuals may request a

public hearing by writing to the address

under ADDRESSES. The request should

include the reasons why a hearing

would be beneficial. If the Coast Guard

determines that the opportunity for oral

presentation will aid this rulemaking,

we will hold a public hearing at a time

and place announced by a subsequent

notice in the Federal Register.

Background and Purpose

The City of Chicago has requested that

Commander, Ninth Coast Guard District,

revise the operating regulations for

Chicago City operated drawbridges over

Chicago River waterways. The primary

changes are: (1) Remove the

requirements for Kinzie Street bridge

over the North Branch and Cermak Road

bridge over the South Branch to open on

signal for commercial vessels due to

restrictive clearances. Both bridges have

been raised to provide vertical

clearances consistent with other fixed

and moveable bridges on the Chicago

River system. (2) Add Division Street

bridge over the North Branch of Chicago

River to the current list of drawbridges

not required to open for vessels. (3)

Require a 12-hour advance notice

requirement for bridge openings from

commercial vessels for City of Chicago

moveable bridges throughout the year.

(4) Clarify rush hour times (7 a.m. to 10

a.m. and 4 p.m. to 6:30 p.m.—Monday

through Friday, with the exception of

Federal holidays) that City of Chicago

bridges would not be required to open

for any vessels.

Discussion of Proposed Rule

The current operating regulations for

Chicago River bridges are contained in

33 CFR 117.391. This section was last

changed on October 6, 1995 (60 FR

52311) to establish opening schedules

for recreational vessels. This proposed

rule only alters the sections pertaining

to recreational vessels by specifying

rush hour times (7 a.m. to 10 a.m. and

4 p.m. to 6:30 p.m.—Monday through

Friday, with the exception of Federal

holidays) that bridges would not be

required to open.

The City of Chicago requested that

both Kinzie Street bridge over North

Branch and Cermak Road bridge over

South Branch be granted the same status

as all other City of Chicago bridges and