Federal Register / Vol. 65, No. 120 / Wednesday, June 21, 2000 / Proposed Rules 38453

promulgated, will not have a significant

economic impact, positive or negative,

on a substantial number of small entities

under the criteria of the Regulatory

Flexibility Act. A copy of the draft

regulatory evaluation prepared for this

action is contained in the Rules Docket.

A copy of it may be obtained by

contacting the Rules Docket at the

location provided under the caption

ADDRESSES.

List of Subjects in 14 CFR Part 39

Air transportation, Aircraft, Aviation

safety, Safety.

The Proposed Amendment

Accordingly, pursuant to the

authority delegated to me by the

Administrator, the Federal Aviation

Administration proposes to amend part

39 of the Federal Aviation Regulations

(14 CFR part 39) as follows:

PART 39—AIRWORTHINESS

DIRECTIVES

1. The authority citation for part 39

continues to read as follows:

Authority: 49 U.S.C. 106(g), 40113, 44701.

§ 39.13 [Amended]

2. Section 39.13 is amended by

adding the following new airworthiness

directive:

Boeing: Docket 98–NM–298–AD.

Applicability: Model 737, 757, and 767

series airplanes, certificated in any category,

as listed in the following Boeing Alert

Service Bulletins:

—737–29A1073, Revision 2, dated July 1,

1999 (for Model 737 series airplanes);

—757–29A0048, Revision 2, dated July 1,

1999 (for Model 757 series airplanes);

—767–29A0083, Revision 2, dated July 15,

1999 (for Model 767 series airplanes).

Note 1: This AD applies to each airplane

identified in the preceding applicability

provision, regardless of whether it has been

modified, altered, or repaired in the area

subject to the requirements of this AD. For

airplanes that have been modified, altered, or

repaired so that the performance of the

requirements of this AD is affected, the

owner/operator must request approval for an

alternative method of compliance in

accordance with paragraph (d) of this AD.

The request should include an assessment of

the effect of the modification, alteration, or

repair on the unsafe condition addressed by

this AD; and, if the unsafe condition has not

been eliminated, the request should include

specific proposed actions to address it.

Compliance: Required as indicated, unless

accomplished previously.

To prevent failure of the motor operated

hydraulic shutoff valves, which could result

in leakage of hydraulic fluid to the engine

fire zone, reduced ability to retract the

landing gear, loss of backup electrical power

or other combinations of failures, and

consequent reduced controllability of the

airplane, accomplish the following:

Repetitive Operational Checks/Corrective

Action

(a) Within 6 months after the effective date

of this AD: Perform an operational check to

detect malfunctioning of any Circle Seal

motor operated hydraulic shutoff valve

having a part number specified in the

‘‘Existing Part Number’’ column (including

parts marked with the suffix ‘‘R’’ after the

serial number), of Paragraph 2.E. of Boeing

Alert Service Bulletin 737–29A1073,

Revision 2 (for Model 737 series airplanes),

or 757–29A0048, Revision 2 (for Model 757

series airplanes), both dated July 1, 1999; or

767–29A0083, Revision 2, dated July 15,

1999 (for Model 767 series airplanes); as

applicable; in accordance with the applicable

alert service bulletin.

(1) If any malfunction of any valve is

detected, prior to further flight, replace the

valve with a new Whittaker valve in

accordance with the applicable service

bulletin. Repeat the operational check

thereafter at intervals not to exceed 6 months

until accomplishment of the terminating

action required by paragraph (b) of this AD

on all subject valves.

(2) If no malfunction of any valve is

detected, repeat the operational check

thereafter at intervals not to exceed 6 months

until accomplishment of the terminating

action required by paragraph (b) of this AD

on all subject valves.

Terminating Action

(b) Within 3 years after the effective date

of this AD, accomplish the replacement of

any Circle Seal valve having a P/N specified

in the ‘‘Existing Part Number’’ column

(including parts marked with the suffix ‘‘R’’

after the serial number), of Paragraph 2.E. of

Boeing Alert Service Bulletin 737–29A1073,

Revision 2 (for Model 737 series airplanes);

757–29A0048, Revision 2 (for Model 757

series airplanes), both dated July 1, 1999; or

767–29A0083, Revision 2, dated July 15,

1999 (for Model 767 series airplanes); with a

new Whittaker valve in accordance with the

applicable alert service bulletin.

Accomplishment of this replacement

constitutes terminating action for the

repetitive operational checks required by this

AD.

Spares

(c) As of the effective date of this AD, no

person shall install on any airplane, any part

identified in the ‘‘Existing Part Number’’

column (including parts marked with the

suffix ‘‘R’’ after the serial number), of

Paragraph 2.E. of Boeing Alert Service

Bulletin 737–29A1073, Revision 2 (for Model

737 series airplanes); 757–29A0048, Revision

2 (for Model 757 series airplanes), both dated

July 1, 1999; or 767–29A0083, Revision 2,

dated July 15, 1999 (for Model 767 series

airplanes); as applicable.

Alternative Methods of Compliance

(d) An alternative method of compliance or

adjustment of the compliance time that

provides an acceptable level of safety may be

used if approved by the Manager, Seattle

Aircraft Certification Office (ACO), FAA,

Transport Airplane Directorate. Operators

shall submit their requests through an

appropriate FAA Principal Maintenance

Inspector, who may add comments and then

send it to the Manager, Seattle ACO.

Note 2: Information concerning the

existence of approved alternative methods of

compliance with this AD, if any, may be

obtained from the Seattle ACO.

Special Flight Permits

(e) Special flight permits may be issued in

accordance with sections 21.197 and 21.199

of the Federal Aviation Regulations (14 CFR

21.197 and 21.199) to operate the airplane to

a location where the requirements of this AD

can be accomplished.

Issued in Renton, Washington, on June 15,

2000.

Donald L. Riggin,

Acting Manager, Transport Airplane

Directorate, Aircraft Certification Service.

[FR Doc. 00–15661 Filed 6–20–00; 8:45 am]

BILLING CODE 4910–13–U

DEPARTMENT OF THE INTERIOR

Minerals Management Service

30 CFR Part 250

RIN 1010–AC43

Oil and Gas and Sulphur Operations in

the Outer Continental Shelf—Oil and

Gas Drilling Operations

AGENCY: Minerals Management Service

(MMS), Interior.

ACTION: Proposed rule.

SUMMARY: This proposed rule

restructures the requirements for oil and

gas drilling operations on the Outer

Continental Shelf (OCS), adds some new

requirements, and converts the rule into

plain language. The proposed rule

follows the logical sequence of

obtaining approval to drill a well and

conducting operations. The proposed

rule also removes overly prescriptive

requirements and updates requirements

to reflect changes in drilling technology.

Restructuring the drilling requirements

will make the regulations easier to read,

understand, and follow. The proposed

technical changes will help ensure that

lessees conduct operations in a safe

manner.

DATES: MMS will consider all comments

we receive by September 19, 2000. We

will begin reviewing comments then

and may not fully consider comments

we receive after September 19, 2000.

ADDRESSES: Mail or hand-carry

comments to the Department of the

Interior; Minerals Management Service;

Mail Stop 4024; 381 Elden Street;

Herndon, Virginia 20170–4817;

38454 Federal Register / Vol. 65, No. 120 / Wednesday, June 21, 2000 / Proposed Rules

Attention: Rules Processing Team

(Comments).

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–NEW); 725 17th Street,

NW., Washington, DC 20503.

FOR FURTHER INFORMATION CONTACT: Bill

Hauser, Engineering and Operations

Division, at (703) 787–1600.

SUPPLEMENTARY INFORMATION: This

proposed revision of Subpart D, Oil and

Gas Drilling Operations, contains

several changes from the current

regulations. One major change is the

organization of the subpart. We have

moved the Application for Permit to

Drill (APD) section into the front of the

subpart, where it becomes the

cornerstone of the drilling requirements.

The other sections follow in a logical

sequence. The last major revision to the

drilling regulations occurred on April 1,

1988 (53 FR 10596), when MMS

consolidated the OCS Orders and the

regulations into a single package. We

welcome comments on the order of the

sections.

The proposed rule uses several

methods to put MMS’s drilling

requirements in plain language. These

methods include:

• Breaking down lengthy sections

into multiple sections;

• Using lists in place of lengthy

paragraphs;

• Moving and consolidating similar

requirements into single sections;

• Using tables where possible (such

as casing and cementing requirements);

• Removing overly prescriptive

requirements;

• Using ‘‘you’’ to refer to the lessee,

operator, or person acting on behalf of

a lessee; and

• Using questions as section titles.

We encourage your comments on any

of these innovations.

The rule also proposes some new

requirements. MMS District Supervisors

and Drilling Engineers recommended

most of the new proposed requirements

based on their experience of reviewing

and approving Applications for Permit

to Drill and other drilling operations.

Some of the new requirements will

improve the flow of information

between the lessee and the Drilling

Engineer reviewing a request (such as

listing all departures in one place as

required in § 250.418(g)) or will fill a

gap in the current regulations (such as

recordkeeping for casing tests in

§ 250.428). The following paragraphs

identify and briefly discuss the most

important proposed revisions. We

welcome your comments on these

proposed requirements.

Rig Move Notification (§ 250.404)

The proposed rule would require the

lessee to notify the District Supervisor

24 hours before rig arrival on and

departure from the well location. MMS

needs to know the comings and goings

of drilling rigs to effectively and

efficiently schedule inspections of

drilling operations. MMS has attached

this requirement as a condition of

approval to APDs for many years. This

would now make this condition of

approval part of the regulations.

New Form To Supplement the APD

Information (§ 250.410)

The proposed rule requires a lessee to

use the new form MMS–123–

Supplemental APD Information Sheet.

The new form provides MMS drilling

engineers with a technical summary of

the information required in the APD.

This aids District offices in the efficient

review and approval of APDs. We also

believe the successful use of this form

helps pave the way for future electronic

submissions of APDs.

The Office of Management and Budget

has approved the new form, which does

not require any new information. For

further information about this form, you

may contact Bill Hauser or Alexis

London with the Rules Processing Team

at 703–787–1600.

Well Location Description (§ 250.412)

The proposed rule requires the lessee

to provide a more precise description of

the surface and subsurface locations of

the proposed well. The current

regulations require lessees to provide

the location in feet from the block line,

but there has been a longstanding

problem for computer routines that

convert distances from block lines to xy and longitude-latitude coordinates for

well locations in irregular blocks. The xy and longitude-latitude coordinates

will be more accurate, allow easier data

entry, and be more compatible for

mapping.

Requests for Using Alternative

Procedures or Departures from the

Regulations (§ 250.418(g))

The proposed rule requires the lessee

to list and discuss all requests for using

alternative procedures or departures

from the regulations in one place within

the APD. This will aid District offices in

the review and approval of these

requests and the APD. The proposed

rule requires you to explain how the

alternative procedure affords an equal or

greater degree of protection, safety, or

performance or why you need the

departure.

Waiting on Cement (§ 250.422(b))

The proposed rule requires that the

lessee must determine when it is safe to

nipple down (remove) the diverter or

blowout preventer (BOP) stack after

cementing a casing string. MMS

proposes this new requirement because

there have been some cases where a

blowout occurred after a lessee nippled

down the diverter or BOP stack while

waiting on cement. We considered

setting a specific waiting time or a

compressive strength for the cement but

decided that the complexity of

cementing operations and variety of

cements are not good candidates for a

prescriptive requirement. The proposed

rule makes the lessee responsible for

evaluating the factors associated with

each cement job to determine when it is

safe to nipple down the diverter or BOP

stack.

Currently, MMS requires the lessee to

hold the cement in newly cemented

casing strings under pressure for 8 hours

for conductor casing or 12 hours for

other casing strings before resuming

drilling. It is during these waiting times

that the lessees usually nipple down

and nipple up (install) the diverter or

BOP stack. The proposed rule does not

revise or remove these waiting times.

These required waiting times help

ensure that the cement attains sufficient

strength to safely resume drilling. Your

comments on this approach to

addressing this issue are welcomed.

Best Cementing Practices

The current drilling requirements do

not address the methods you must use

to cement casing strings. MMS has

allowed lessees to use their judgment in

selecting the proper method of

cementing casing and liners. While this

approach has worked for the successful

drilling and completion of wells, we are

less convinced that this approach has

been successful for the long-term life of

many wells. MMS believes that poor

cementing practices are among the main

primary causes of sustained casing

pressures on producing wells. As a

preventive measure to reduce the

number of wells with sustained casing

pressures, we recommend that lessees

use better cementing practices for

production wells. This is especially true

with subsea wells where it is not

possible to monitor most casing

pressures. We welcome your comments

on the use of improved cementing

practices to address some of the

problems associated with sustained

casing pressures.

Federal Register / Vol. 65, No. 120 / Wednesday, June 21, 2000 / Proposed Rules 38455

Minimum Cemented Casing Strings for

Producing Wells (§ 250.423(f))

The proposed rule requires that you

must have at least two cemented casing

strings if you plan to produce the well.

This has been an unwritten rule for OCS

wells in the Gulf of Mexico Region

(GOMR) for many years. MMS believes

that two cemented casing strings (not

including any cemented liners) are the

minimum needed to ensure safe

production for the life of the well. This

proposed requirement makes this

unwritten requirement available for

comment.

Recordkeeping for Casing, Liner, and

Diverter Pressure Tests (§§ 250.427 and

250.434)

The proposed rule clarifies what

MMS has expected a lessee to record for

casing, liner, and diverter pressure tests.

The casing pressure test must be

recorded on a pressure chart and

certified by your onsite representative as

being correct. The time, date, and

results are then recorded in the driller’s

report. Recordkeeping requirements for

a diverter test are similar to those

required for a BOP test.

Blind-shear Ram for Surface BOP

Systems (§§ 250.441, 250.515(b), and

250.615(b))

The proposed rule requires a lessee to

install a blind-shear ram in the surface

BOP stack instead of a blind ram. MMS

believes that a blind-shear ram in the

surface stack provides an additional

safety measure in handling well control

events. We recently reviewed the

blowouts that have occurred since 1977

and found at least 12 incidents where a

blind-shear ram had helped or could

have helped control the situation. These

blowouts usually occurred when drill

pipe or tubing was hung in the BOP

stack, and there were difficulties in

installing or closing a drill string safety

valve, inside the BOP, or tubing safety

valve. Several of these blowout events

had major casualties and/or damage to

platforms and drilling rigs.

MMS believes that the use of blindshears rams will prevent or minimize

some blowouts on the OCS. This would

reduce the risk of injury and loss of life

to personnel and the risk of

environmental damages from a blowout.

We believe the benefits from reduced

injuries, fatalities, environmental

damages, and losses from property

damages will easily out weigh the costs

of installing the blind-shear rams. This

measure is consistent with our

Congressional mandate to prevent or

minimize the likelihood of blowouts

(OCS Lands Act at 43 U.S.C. 1332(6)).

MMS believes that the installation of

a blind-shear ram in BOP stacks should

also be applied to completion and

workover operations because several of

the above blowout events involved

completions and workovers. The

proposed rule does not apply to

workovers with the tree in place. The

proposed rule also revises § 250.515(b)

and § 250.615(b).

The proposed rule provides for a 1-

year grace period to comply with the

requirement to install a blind-shear ram

on surface stacks. Lessees will have 1

year from the effective date of the final

rule to install blind-shear rams in all

surface BOP stacks.

Reference Minimum Accumulator

Requirements for Subsea BOP Systems

(§ 250.442)

The proposed rule references section

12.3, Accumulator Volumetric Capacity,

in the American Petroleum Institute’s

Recommended Practice for Blowout

Prevention Equipment Systems for

Drilling Wells (API RP 53). We included

this reference so that both industry and

MMS would have guidelines for

determining the minimum requirements

and performance for subsea

accumulators and BOP systems.

Included in this section are minimum

accumulator response times for annular

and ram preventers. The proposed rule

also requires the lessee to record the

closing times for subsea annular and

ram preventers. These proposed

revisions will help ensure that subsea

BOP systems operate at proper levels of

performance.

Reference Minimum BOP Maintenance

Requirements (§ 250.446)

The current regulations in § 250.407

require the lessee to maintain BOP

equipment to ensure that it operates

properly. The proposed rule goes on to

require that this maintenance must meet

or exceed the provisions of sections

17.10 and 18.10 (Inspections); sections

17.11 and 18.11 (Maintenance); and

sections 17.12 and 18.12 (Quality

Management), in API RP 53. MMS

selected API RP 53 as the standard to

use because it represents a composite of

the practices used by various operators

and drilling contractors.

The importance of a thorough

maintenance program is even greater

now that MMS has allowed lessees to

test BOP equipment less frequently than

before (see final rule for BOP testing

published June 1, 1998, 63 FR 29604).

MMS believes that maintenance is

critical to the proper operation of BOP

equipment. MMS considered including

specific maintenance practices when we

revised the BOP testing requirements

but decided to limit that rulemaking to

the BOP testing issue since the BOP

performance study did not specifically

address BOP maintenance. This

rulemaking would set those minimum

requirements.

The proposed rule references only

specific sections of API RP 53. We have

referenced specific sections because

these were the most critical areas of

concern. However, several industry

commenters on the BOP testing

requirements recommended

incorporating the entire API RP 53

document. We would like your

comments on whether MMS should

reference specific sections or

incorporate the entire document into the

regulations.

Use of Maximum Anticipated Surface

Pressure (MASP) for Determining BOP

Test Pressures (§ 250.448)

As discussed in the preambles of the

proposed (July 15, 1997, 62 FR 37819)

and final rules for BOP testing

requirements, MMS has considered

using MASP in determining BOP test

pressures. Industry comments on the

proposed BOP testing rule showed

interest in this approach for determining

test pressures, but both industry and

MMS expressed concerns about how to

calculate MASP. After considerable

thought, MMS has decided to propose

using MASP calculations in determining

BOP test pressures. Under the proposed

rule, the high pressure test must either

equal the rated working pressure of the

equipment, or be 500 pounds per square

inch (psi) greater than the calculated

MASP for the applicable section of hole,

whichever is smaller. This reflects how

MMS currently reviews and approves

test pressures. It is also consistent with

current industry practice of testing

BOPs at less than the rated working

pressures. The proposed rule also

clearly states that the District Supervisor

must have approved the MASP plus 500

psi test pressures in the APD.

Currently, District Supervisors base

the approval of alternate test pressures

on a comparison of the anticipated

surface pressure calculations submitted

with the APD to MASP calculations

made by MMS drilling engineers. If the

two calculations compare favorably, the

District Supervisor approves the

requested test pressures. If the

calculations for anticipated surface

pressure are less than those calculated

by MMS, the District Supervisor advises

the lessee of any necessary revisions to

the APD.

38456 Federal Register / Vol. 65, No. 120 / Wednesday, June 21, 2000 / Proposed Rules

Change in Terminology—Mud to

Drilling Fluid

The proposed rule changes the term

‘‘mud’’ as in drilling mud to ‘‘drilling

fluid.’’ We believe that this change more

accurately reflects the current

terminology. We have changed the term

‘‘mud’’ to ‘‘drilling fluid’’ throughout

subpart D. We will make the same

change in other subparts as we revise

them.

Posting Maximum Safe Pressures

Contained Under a Shut-In BOP

(§ 250.456(f))

The proposed rule clarifies the

current requirement of posting the

maximum pressure that you may safely

contain under a shut-in BOP for each

casing string. The proposed rule

requires the posting of two pressures: (1)

the surface pressure at which the casing

shoe would break down and, (2) the

lesser of the BOP’s rated working

pressure or 70 percent of casing burst

pressure (or casing test pressure

otherwise approved by the District

Supervisor). The current requirement

has led to some confusion as to what

safe pressure MMS wants posted, i.e.,

formation fracture pressure or

equipment limitation pressure. By

having both pressures posted, the driller

will have additional information

immediately available for

decisionmaking.

Establish Well Testing Requirements

(§ 250.460)

The proposed rule establishes

minimum requirements for well-testing

activities. Currently there are no

regulations that specifically address

well testing. MMS believes that

minimum requirements are necessary to

understand and evaluate the lessee’s

anticipated well-testing activities. The

proposed rule would require a lessee to

submit information about testing

procedures and equipment to the

District Supervisor for approval with the

APD or a Sundry Notice. You would not

be allowed to conduct the well test until

the District Supervisor approves the

submitted test information. The

information that must be submitted

includes estimated flowing and shut-in

tubing pressures; estimated flow rates

and cumulative volumes; time duration

of flow, buildup, and drawdown

periods; a description of surface and

subsurface test equipment; proposed

methods to handle or transport

produced fluids; and a full description

of the test procedures.

Simplify Survey Requirements for

Directional Drilling (§ 250.461)

The proposed rule simplifies the

language and the requirements to be

consistent with current practices and

technology. The proposed rule also

makes these survey requirements a

separate section.

Hydrogen Sulfide (§ 250.470)

The hydrogen sulfide section of

subpart D was not revised. We are not

revising this section now because it was

revised in January 1997 (62 FR 3795).

MMS will consider revising this section

as we begin the rewriting of subpart E,

Oil and Gas Well-Completion

Operations; subpart F, Oil and Gas WellWorkover Operations; and subpart H,

Oil and Gas Production Safety Systems.

Your comments on the best method to

rewrite or reorganize the hydrogen

sulfide requirements are welcomed.

Requirements Removed From Subpart

D

The proposed rule does not contain

requirements for the welding and

burning practices and procedures

(former § 250.402) or electrical

equipment (former § 250.403). These

requirements were moved to subpart A

of the regulations in the Notice of Final

Rulemaking for subpart A, which was

published in the Federal Register on

December 28, 1999 (64 FR 72756).

The proposed rule also removes the

detailed well-control drill requirements.

These requirements (current § 250.408)

prescribe how the lessee is to conduct

the drill. MMS proposes to remove these

requirements because they are too

prescriptive. MMS still would require

the lessee to outline the assignments for

each member of the drilling crew.

Other Considerations for Drilling

Regulations

MMS also considered including

regulations for drilling with coiled

tubing units in this revision of subpart

D. However, we decided to postpone

proposing requirements for coiled

tubing drilling operations until MMS

has a better understanding of these

operations and the amount of activity

that will likely take place on the OCS.

MMS would most likely use API’s

Recommended Practice for Coiled

Tubing Operations in Oil and Gas Well

Services (API RP 5C7) as a guideline

when we do propose appropriate

regulations. We would like your

comments on the need for regulations

for coiled tubing drilling.

MMS is also looking at requiring

drilling rigs to use automated pipe

handling systems during drilling

operations. MMS believes that the use of

automated pipe handling systems

clearly provides safety advantages over

non-automated pipe handling systems.

After further consultation with the U.S.

Coast Guard, we may propose this new

requirement under the provision in

§ 250.107, which mandates that the

Director require the use of the best

available and safest technology to

protect health, safety, property, and

environment. We welcome your

comments on requiring automated pipe

handling systems as well as your

comments on the best approach to

implementing this requirement.

Derivation Table

The derivation table below shows

where the proposed requirements come

from in relation to the current sections.

The table also provides the section

numbers that were used from 1988 up

until mid-1998 when MMS assigned

new numbers to the sections to aid in

the updating and revision of the

regulations (63 FR 29478, May 29,

1998).

DERIVATION TABLE

Proposed new section and title Current section Previous numbering

system

250.400 Who is subject to the requirements of this subpart? New section ........................................... New section.

250.401 What must I do to keep wells under control? 250.400 ................................................. 250.50.

250.402 When and how must I secure a well? 250.411 ................................................. 250.61.

250.403 What safety requirements must my drilling unit meet? 250.401 ................................................. 250.51.

250.404 What mobile drilling unit movements must I report? New requirement ................................... New requirement.

250.410 How can I apply for a permit to drill a well? 250.414(a) ............................................. 250.64(a).

250.411 What material must I submit with my application? ?250.414(f) ............................................ 250.64(f).

250.412 What requirements must my plat meet? ?250.414(f)(1) ........................................ 250.64(f)(1).

250.413 What items must my description of well drilling design criteria address?250.414(f)(2) .......................................... 250.64(f)(2).

Federal Register / Vol. 65, No. 120 / Wednesday, June 21, 2000 / Proposed Rules 38457

DERIVATION TABLE—Continued

Proposed new section and title Current section Previous numbering

system

250.414 What items must my drilling prognosis include? 250.414(f)(5) .......................................... 250.64(f)(5).

250.415 What items must my casing and cementing programs include? 250.414(f)(4 and 6) ............................... 250.64(f)(4 and 6).

250.416 What information must be included in the diverter and BOP descriptions?250.414(f)(3) .......................................... 250.64(f)(3).

250.417 What information must I provide if I intend to use a mobile drilling unit

to drill a proposed well?

250.414(b) ............................................. 250.64(b).

250.418 What additional requirements must I meet? 250.414(f)(11) ........................................ 250.64(f)(11).

250.420 What well casing and cementing requirements must I meet? 250.404(a)(1) .........................................

250.404(a)(2) .........................................

250.54(a)(1)

250.54(a)(2).

250.421 What are the casing and cementing requirements by type of casing

string?

250.404(b),(c),(d), and (e) ..................... 250.54(b),(c), (d),

and (e).

250.422 When may I resume drilling after cementing? 250.405(d) ............................................. 250.55(d).

250.423 How must I remedy cementing and casing problems and situations? 250.404 and .405 .................................. 250.54 and .55.

250.424 What are the requirements for pressure testing casing? 250.405 ................................................. 250.55.

250.425 What special pressure tests must I perform on casings for prolonged

drilling operations?

250.405 ................................................. 250.55.

250.426 What are the requirements for pressure testing liners? 250.405 ................................................. 250.55.

250.427 What are the recordkeeping requirements for casing and liner pressure tests?250.405(a) and New requirement ......... 250.55(a).

250.428 What are the requirements for pressure integrity tests? 250.404(a)(6) ......................................... 250.54(a)(6).

250.430 When must I install a diverter system? 250.409(a) ............................................. 250.59(a).

250.431 What are the diverter design and installation requirements? 250.409(c) ............................................. 250.59(c).

250.432 What must I do to obtain a departure to diverter design and installation requirements?250.409(d) ............................................. 250.59(d).

250.433 How must I test the diverter system after installation? 250.409(f) .............................................. 250.59(f).

250.434 What are the recordkeeping requirements for diverter tests? 250.409(f) .............................................. 250.59(f).

250.440 What are the general requirements for BOP systems and system

components?

250.406(a) and (b) ................................ 250.56(a) and (b).

250.441 What are the requirements for a surface BOP stack? 250.406(f) .............................................. 250.56(f).

250.442 What are the requirements for a subsea BOP stack? 250.406(e) ............................................. 250.56(e).

250.443 What associated BOP systems and related equipment must my BOP

system include?

250.406(d) ............................................. 250.56(d).

250.444 What are the choke manifold requirements? 250.406(d)(7) ......................................... 250.56(d)(7).

250.445 What are the requirements for kelly cocks, inside BOPs, and drillstring safety valves?250.406(d)(10) ....................................... 250.56(d)(10).

250.446 What must I do to maintain and inspect my BOP? 250.407(f) and (g) ................................. 250.57(f) and (g).

250.447 When must I conduct BOP system pressure tests? 250.407(a) ............................................. 250.57(a).

250.448 What are the BOP pressure tests requirements? 250.407(b) and (c) ................................ 250.57(b) and (c).

250.449 Are there additional BOP testing requirements with which I must

comply?

250.407(d) ............................................. 250.57(d).

250.450 What are the recordkeeping requirements for BOP tests? 250.407(h) ............................................. 250.57(h).

250.451 How do I remedy BOP problems and situations? 250.407(c), (d) and (e) .......................... 250.57(c), (d) and

(e).

250.455 What are the general requirements for a drilling fluid program? 250.410(a) ............................................. 250.60(a).

250.456 What are the required safe drilling fluid program practices? 250.410(b) ............................................. 250.60(b).

250.457 What equipment must I have to test and monitor drilling fluids? 250.410(c) ............................................. 250.60(c).

250.458 What quantities of drilling fluids are required? 250.410(d) ............................................. 250.60(d).

250.459 What are the safety requirements for drilling fluid-handling areas? 250.410(e) ............................................. 250.60(e).

250.460 What are the requirements for well testing? 250.401(e)(1) and new requirement for

well testing.

250.51(e)(1).

250.461 What are the requirements for directional and inclination surveys? 250.401(e)(2),(3), and (4) ..................... 250.51(e)(2),(3), and

(4).

250.462 What are the requirements for well-control drills? 250.408 ................................................. 250.58.

250.463 Who establishes field drilling rules? 250.412 ................................................. 250.62.

250.465 When must I submit forms to MMS? 250.415 ................................................. 250.65.

250.466 What well records must I keep? 250.416(a) ............................................. 250.66(a).

250.467 What well records may I be required to submit? 250.416(c) ............................................. 250.66(c).

250.468 How long must I keep drilling-related records? 250.416(a) and (g) ................................ 250.66(a) and (g).

250.469 Must I submit copies of well logs? 250.416(d) ............................................. 250.66(d).

250.470 Hydrogen sulfide 250.417 ................................................. 250.67.

Procedural Matters

Public Comments 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 the law. If you

wish us to withhold your name and/or

address, you must state this

prominently at the beginning of your

comment. However, we will not

consider anonymous comments. We

will make all submissions from

38458 Federal Register / Vol. 65, No. 120 / Wednesday, June 21, 2000 / Proposed Rules

organizations or businesses, and from

individuals identifying themselves as

representatives or officials of

organizations or businesses, available

for public inspection in their entirety.

Takings Implication Assessment

(Executive Order (E.O.) 12630)

According to E.O. 12630, the

proposed rule does not have significant

Takings Implications. A Takings

Implication Assessment is not required.

The proposed rule revises existing

operation regulations. It does not

prevent any lessee, operator, or drilling

contractor from performing operations

on the OCS, provided they follow the

regulations. Thus, MMS did not need to

prepare a Takings Implication

Assessment pursuant to E.O. 12630,

Governmental Actions and Interference

with Constitutionally Protected Property

Rights.

Regulatory Planning and Review (E.O.

12866)

This proposed rule is a significant

rule under E.O. 12866; therefore, OMB

will review the proposed rule.

(1) This proposed rule will not have

an effect of $100 million or more on the

economy. It will not adversely affect in

a material way the economy,

productivity, competition, jobs, the

environment, public health or safety, or

State, local, or tribal governments or

communities. The major purpose for

this proposed rule is the restructuring of

the rule and simplifying the regulatory

language. The restructuring and plain

language revisions will not result in any

economic effects to small or large

entities. Some of the proposed technical

revisions will have a minor economic

effect on lessees and drilling

contractors. The cost of the rule is

affected by the response of existing and

future potential regulated entities to

anticipated prices and returns in the

energy markets. With increases in the

prices of oil and natural gas, the amount

of drilling activity and affected entities

could increase as could the estimated

cost of the proposed rule. However,

even with such changes, MMS believes

the rule will not have an annual effect

on the economy of $100 million.

Specifically, given the existing industry

structure (i.e., the number and size of

affected regulated entities remains

constant), MMS estimates the first year

cost to implement the rule at less than

$15 million. Over 95 percent of the

estimated cost of the proposed rule is

due to the acquisition and installation of

the blind-shear rams. The recurring

costs in the ensuing years, given no

change to the existing structure of the

OCS lessees and drilling contractors, are

estimated at $1 million annually.

The majority of the cost to implement

the proposed rule is due to the required

installation of blind-shear rams ($14

million) in a surface BOP stack. The

most significant benefits of preventing

or minimizing some blowouts will be

the reduced risk of injury or fatality to

personnel and of environmental

damage. Property damages (including

lost productivity) resulting from

blowouts will also be reduced by this

proposed rule. Property and financial

damages from a blowout or near

blowout can range from minimal

damage to a facility and the loss of a

day’s activity to the total loss of the

drilling rig and production facility.

MMS estimates that installation of a

blind-shear ram in the BOP stack could

prevent or minimize one blowout every

2 years. This estimate comes from the 12

incidents that MMS identified where a

blind-shear ram had helped or could

have helped prevent or minimize a

blowout over a 23+ year period (1977 to

present). Considering that a single

blowout could cause multiple injuries,

fatalities, and tens of millions of dollars

in property damage and financial losses,

MMS believes that the benefits of this

proposed requirement will more than

offset the cost of this proposed

requirement.

(2) This proposed rule will not create

a serious inconsistency or otherwise

interfere with an action taken or

planned by another agency. The

proposed rule does not affect how

lessees or operators interact with other

agencies. Nor does this proposed rule

affect how MMS will interact with other

agencies.

(3) This proposed rule does not alter

the budgetary effects or entitlements,

grants, user fees, or loan programs or the

rights or obligations of their recipients.

The proposed rule only addresses the

regulatory requirements for obtaining

permission to drill on the OCS and the

safety of drilling operations.

(4) This proposed rule does not raise

novel legal or policy issues. The

proposed rule involves some new policy

issues, such as requiring minimum BOP

maintenance requirements and blindshear rams for surface BOP stacks, but

these new policy decisions are not

‘‘novel.’’ They simply address

recognized gaps in our safety

regulations. These minimum

requirements are generally accepted

practices that are included in API

documents.

Civil Justice Reform (E.O. 12988)

According to E.O. 12988, the Office of

the Solicitor has determined that this

proposed rule does not unduly burden

the judicial system and does meet the

requirements of sections 3(a) and 3(b)(2)

of the Order.

National Environmental Policy Act

(NEPA)

This proposed rule does not

constitute a major Federal action

significantly affecting the quality of the

human environment. An environmental

assessment is not required.

Paperwork Reduction Act (PRA) of 1995

The proposed rule contains a

collection of information that has been

submitted to OMB for review and

approval under § 3507(d) of the PRA. 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 and

recordkeeping burden. Submit your

comments to the Office of Information

and Regulatory Affairs; OMB; Attention:

Desk Officer for the Department of the

Interior (OMB control number 1010–

NEW); 725 17th Street, NW,

Washington, DC 20503. Send a copy of

your comments to the Rules Processing

Team, Attn: Comments; Mail Stop 4024;

Minerals Management Service; 381

Elden Street; Herndon, Virginia 20170–

4817. You may obtain a copy of the

supporting statement for the new

collection of information by contacting

the Bureau’s Information Collection

Clearance Officer at (202) 208–7744.

The PRA provides that an agency may

not conduct or sponsor and a person is

not required to respond to a collection

of information unless it displays a

currently valid OMB control number.

OMB is required to make a decision

concerning the collection of information

contained in these proposed regulations

between 30 to 60 days after publication

of this document in the Federal

Register. Therefore, a comment to OMB

is best assured of having its full effect

if OMB receives it by July 21, 2000. This

does not affect the deadline for the

public to comment to MMS on the

proposed regulations.

The title of the collection of

information for this proposed rule is

‘‘Proposed Rulemaking—30 CFR 250,

Subpart D—Oil and Gas Drilling

Operations’’ (OMB control number

1010–NEW). Respondents include

approximately 130 Federal OCS oil and

gas or sulphur lessees. The frequency of

response is on occasion, daily, weekly,

quarterly, or annually depending upon

the requirement. Responses to this

collection of information are mandatory.

MMS will protect proprietary

information according to the Freedom of

Federal Register / Vol. 65, No. 120 / Wednesday, June 21, 2000 / Proposed Rules 38459

Information Act and 30 CFR 250.196,

‘‘Data and information to be made

available to the public.’’

The collection of information required

by the current subpart D regulations is

approved by OMB under control

number 1010–0053. The proposed rule

imposes very few changes to the

information collection burden. The

major changes are:

• Notification of drilling rig

movement on or off drilling location

(+100 burden hours);

• Incorporation of two new forms

(Supplemental APD Information Sheet

and Weekly Activity Report) separately

approved under 1010–0131 and 1010–

0132; and

• Submission of well testing plans

(+30 burden hours).

We estimate the total annual reporting

and recordkeeping ‘‘hour’’ burden for

the proposed rule to be 107,866 hours

representing an average burden of 830

hours per respondent. Except for the

items identified as ‘‘new’’ in the

following chart, the burden estimates

shown are those that are estimated for

the current subpart D regulations. The

public has had numerous opportunities

to comment on the estimates during the

process to renew the OMB approval of

the information collection requirements

in current regulations. We have also

consulted with a representative

sampling of respondents to verify these

estimates.

BURDEN BREAKDOWN

Citation 30 CFR 250

Subpart D Reporting requirement Frequency Number Burden Annualburden

402 [Current 411] ....... Request approval to use blind or blindshear ram or pipe rams and inside BOP.On occasion ............ 6 requests ................ 10 minutes ........ 1

403(c), 404 [New] ...... Notify MMS of drilling rig movement on or

off drilling location.

On occasion ............ 1,000 notifications ... 6 minutes .......... 100

403(c) [Current 401] .. Request approval not to shut-in well during equipment movement.On occasion ............ 10 requests .............. 1 hour ............... 10

410–418, plus various

references throughout subpart D*.

APD to drill, including various approvals

required in subpart D and obtained via

forms MMS–123 and MMS–123S, and

supporting information. [*All current requirements in various sections.].

Burden covered under 1010–0044 (form MMS–123, APD);

1010–0131 (new collection form MMS–123S, Supplemental

APD Information Sheet).

0

410(c), 417(b) [Current 405].Exploration Plan, Development and Production Plan, Development Operations

Coordination Document.

Burden covered under 1010–0049 (30 CFR 250, Subpart B) 0

417(c) [Current 401] .. Submit 3rd party review of drilling unit ...... Burden covered under 1010–0958 (30 CFR 250, Subpart I) 0

418(e) [Current 402] .. Submit welding and burning plan .............. Burden covered under 1010–0114 (30 CFR 250, Subpart A) 0

423 [Current 404/405] Submit revised casing and cementing program or changes.On occasion ............ 20% of 990 drilling

ops. = 198.

2 hours .............. 396

425 [Current 405] ....... Caliper, pressure test, or evaluate casing;

submit evaluation results; request approval before resuming operations or

beginning repairs.

Every 30 days during

pro longed drilling;

20% of 990 wells =

198.

5 hours .............. 990

456(c), (f) [Current

410].

Perform various calculations; post information.On occasion, daily,

weekly.

144 drilling rigs × 52

= 7,488.

.25 hour ............ 1,872

459(a)(3) [Current

410].

Request exception to procedure for protecting negative pressure area.On occasion ............ 5 requests ................ 2 hours .............. 10

460(b), (c) [New; Current 401].Submit plans for well testing and notify

MMS before test.

On occasion ............ 15 plans ................... 2 hours .............. 30

461(e) [Adjustment to

current 401].

Provide copy of well directional survey to

affected leaseholder.

On occasion ............ 10 occasions ........... 1 hour ............... 10

462(a) [Current 408] .. Prepare and post well control drill plan for

crew members.

On occasion ............ 26 plans ................... 3 hours .............. 78

463(b) [Current 412] .. Request field drilling rules be established,

amended, or canceled.

On occasion ............ 6 requests ................ 2.7 hours ........... 1 16

465, 467 [Current 415/

416].

Submit revised plans, changes, well/drilling records, etc., on forms MMS–124 or

MMS–125.

Burden covered under 1010–0045 (form MMS–124, Sundry Notices and Reports); 1010–0046 (form MMS–125, Well Summary Report)0

465(a), (b), (3); 467(c)

[New].

In the GOMR, submit drilling activity on

form MMS–133 on weekly basis.

Burden included under 1010–0132 (new form MMS–133)

(Weekly Activity Report)

0

465(a); 467 [Current

416].

Submit well records, daily drilling report

and other data as requested or specified by regional office.

On occasion, daily ... 20% of 990 wells =

198.

3 hours .............. 594

469 [Current 416] ....... Submit well logs and survey results .......... On occasion ............ 990 wells ................. 1.5 hours ........... 1,485

470(c)(4), (d) [Current

417].

Submit request for reclassification of H2S

zone; notify MMS if conditions change.

On occasion ............ 27 responses ........... 1.7 hours ........... 1 46

470(f) [Current 417] ... Submit contingency plans for operations

in H2S areas.

On occasion ............ 27 plans (16 drill, 5

workover, 6 prod.).

10 hours ............ 270

470(i) [Current 417] ... Display warning signs ................................ Not applicable: facilities would display warning signs and use

other visual and audible systems

0

470(j)(12) [Current

417].

Propose alternatives to minimize or eliminate SO2 hazards.Proposals would be submitted with contingency plans; burden

included in 250.470(f)

0

470(j)(13)(vi) [Current

417].

Label breathing air bottles ......................... Not applicable: supplier normally labels bottles; facilities would

routinely label if not

0

470(l) [Current 417] ... Notify (phone) MMS of unplanned H2S releases.On occasion (apprx.

2/year).

49 facilities × 2 = 98 .2 hour .............. 1 20

38460 Federal Register / Vol. 65, No. 120 / Wednesday, June 21, 2000 / Proposed Rules

BURDEN BREAKDOWN—Continued

Citation 30 CFR 250

Subpart D Reporting requirement Frequency Number Burden Annualburden

470(o)(5) [Current

417].

Request approval to use drill pipe for well

testing.

On occasion ............ 3 requests ................ 2 hours .............. 6

470(q)(1) [Current

417].

Seal and mark for the presence of H2S

cores to be transported.

Not applicable: facilities would mark transported cores 0

470(q)(9) [Current

417].

Request approval to use gas containing

H2S for instrument gas.

On occasion ............ 3 requests ................ 2 hours .............. 6

470(q)(12) [Current

417].

Analyze produced water disposed of for

H2S content and submit results to MMS.

On occasion (apprx.

weekly).

4 prod. platforms ×

52 = 208.

2.8 hours ........... 1 582

Total Reporting: .................................................................... .................................. 10,516 ...................... ........................... 6,522

1 Rounded.

Citation 30 CFR 250

Subpart D Recordkeeping requirement Frequency Number Burden Annualburden

403 [Current 401] ....... Perform operational check of crown block

safety device; record results.

Weekly (52) ............. 144 drilling rigs × 52

= 7,488.

.1 hour .............. 1 749

427 [Current 405] ....... Perform pressure test on all casing strings

and drilling liner lap; record results.

On occasion ............ 144 drilling rigs ×

apprx. 50 per rig =

7,200.

2 hours .............. 14,400

428(a) [Current 404] .. Perform pressure-integrity tests and related hole-behavior observations; record

results.

On occasion ............ 425 tests .................. 4 hours .............. 1,700

434 [Current 409] ....... Perform diverter tests when installed and

once every 7 days; actuate system at

least once every 24-hour period; record

results; retain records 2 years after drilling completed.

On occasion (average 2 per drilling

op).

990 drilling operations × 2 = 1,980.2 hours .............. 3,960

450 [Current 407] ....... Perform BOP pressure tests, actuations

and inspections; record results; retain

records 2 years following completion of

drilling activity.

When installed; at a

minimum every 14

days; as stated for

components.

144 drilling rigs ×

apprx. 35 per rig =

5,040.

6 hours .............. 30,240

450 [Current 407] ....... Function test annulars and rams; document results (Note: this test is part of

BOP test when BOP test is conducted.).

Every 7 days between BOP tests

(biweekly).

144 drilling rigs ×

appx. 20 per rig =

2,880.

.16 hour ............ 461

451(c) [Current 407] .. Record reason for postponing BOP test ... On occasion (apprx.

2/year).

144 drilling rigs × 2 =

288.

.1 hour .............. 1 29

456(b); 457(a), 458(b)

[Current 410].

Record each drilling fluid circulation; test

drilling fluid, record results; record daily

inventory of drilling fluid/materials; test

and recalibrate gas detectors; record results.

On occasion, daily,

weekly, quarterly.

144 drilling rigs × 52

= 7,488.

1.25 hours ......... 9,360

462(c) [Current 408] .. Perform well-control drills; record results .. On occasion (2

crews × 52=102).

144 drilling rigs ×

102 = 14,688.

1 hour ............... 14,688

466, 468 [Current 416] Retain drilling records for 90 days after

drilling complete; retain casing/liner

pressure, diverter, and BOP records for

2 years; retain well completion/well

workover until well is permanently

plugged/abandoned or lease assigned.

Annual records

maintenance.

990 wells ................. 1.5 hours ........... 1,485

470(g)(2), (g)(5) [Current 417].Conduct H2S training; post safety instructions; document training.On occasion; annual

refresher (apprx.

2/year).

49 facilities × 2 = 98 2 hours .............. 196

470(h)(2) [Current

417].

Conduct drills and safety meetings; document attendance.Weekly (52) ............. 49 facilities × 52 =

2,548.

1 hour ............... 2,548

470(j)(8) [Current 417] Test H2S detection and monitoring sensors during drilling; record testing and

calibrations (apprx. 12 sensors per rig).

On occasion (daily

during drilling).

26 drilling rigs × 365

days = 9,490.

2 hours .............. 18,980

470(j)(8) [Current 417] Test H2S detection and monitoring sensors during production; record testing

and calibrations (apprx. 30 sensors on

5 platforms + apprx. 42 sensors on 23

platforms).

14 days .................... 28 prod. platforms ×

26 weeks = 728.

3.5 hours ........... 2,548

Total Recordkeeping:.................................................................... .................................. .................................. ........................... 101,344

1 Rounded.

Federal Register / Vol. 65, No. 120 / Wednesday, June 21, 2000 / Proposed Rules 38461

Total Reporting ...................... = 6,522

Total Recordkeeping .............. = 101,344

Total Burden .......................... = 107,866

1. MMS specifically solicits

comments on the following questions:

(a) Is the proposed collection of

information necessary for MMS to

properly perform its functions, and will

it be useful?

(b) Are the estimates of the burden

hours of the proposed collection

reasonable?

(c) Do you have any suggestions that

would enhance the quality, clarity, or

usefulness of the information to be

collected?

(d) 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?

2. In addition, the PRA requires

agencies to estimate the total annual

reporting and recordkeeping ‘‘non-hour

cost’’ burden resulting from the

collection of information. We have not

identified any, and we solicit your

comments on this item. For reporting

and recordkeeping only, your response

should split the cost estimate into two

components: (a) Total capital and startup cost component and (b) 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. Capital and start-up costs

include, among other items, computers

and software you purchase to prepare

for collecting information; monitoring,

sampling, drilling, and testing

equipment; and record storage facilities.

Generally, your estimates should not

include equipment or services

purchased: (1) Before October 1, 1995;

(2) to comply with requirements not

associated with the information

collection; (3) for reasons other than to

provide information or keep records for

the Government; or (4) as part of

customary and usual business or private

practices.

Regulatory Flexibility (RF) Act

The Department of the Interior (DOI)

certifies that this proposed rule will not

have a significant economic effect on a

substantial number of small entities

under the RF Act (5 U.S.C. 601 et seq.).

This proposed rule applies to all lessees

and drilling contractors that operate on

the OCS. Small lessees and drilling

contractors that operate under this

proposed rule would fall under the

Small Business Administration’s (SBA)

Standard Industrial Classification (SIC)

codes 1311 Crude Petroleum and

Natural Gas and 1381 Drilling Oil and

Gas Wells. Under these SIC codes, SBA

considers all companies with fewer than

500 employees to be a small business.

Given the variability in the industry to

changes in the relative prices of oil and

natural gas, the numbers of small

entities affected by the proposed rule

may change over time. Based on data

from 1998, we estimate that of the 130

lessees that explore for and produce oil

and gas on the OCS, approximately 90

are small businesses (70 percent). We

also estimate that 20 drilling contractors

operate on the OCS, and that only one

of those drilling contractors is classified

as a small business. The number of

drilling contractors is based on current

drilling activity on the OCS, and the

size of each drilling contractor is based

on research into company statistics.

New compliance costs associated with

this proposed rule fall within two

categories—of meeting new drilling

requirements and the cost of purchasing

additional blind shear rams. Drilling

requirement costs will be borne by the

OCS lessees who explore for and

produce oil and are dependent on the

number of wells drilled. The cost of the

blind shear rams will be borne by

drilling contractors.

We estimate that the total annual cost

of the new drilling requirements

proposed in this rule to be

approximately $670,000, as shown in

the following table. The table also

shows the estimated cost per well for

the approximately 700 wells drilled

annually on the OCS using a surface

BOP stack.

ESTIMATED COSTS OF ADDITIONAL DRILLING REQUIREMENTS

Cost Cost per well

Total cost for

700 wells

drilled annually

One hour per well additional evaluation time on cementing operations @ $100 ................................................... $100 $70,000

One hour per well additional drilling rig rental @ $850 .......................................................................................... 850 595,000

Annual reporting and paperwork burden—140 hours @$50 .................................................................................. 10 7,000

Total .................................................................................................................................................................. 960 672,000

*The annual reporting and paperwork burden for the entire Subpart D—’’Oil and Gas Drilling Operations’ is 107,866 hours as indicated in the

Paperwork Reduction Act of 1995 (PRA) section of this preamble. However, the new burden that would be added by this proposed rule is only

140 hours (§ 250.403(c)—100 hours; § 250.460(b), (c)—30 hours; and § 250.461(e)—10 hours) as shown in the reporting and recordkeeping burden tables in the PRA section.

As indicated in the table, the

estimated cost per well is about $1,000.

Based on drilling data from 1999, we

estimate that the 90 small businesses

that explore for and produce oil and gas

on the OCS drill about 300 of the 700

wells drilled annually on the OCS using

a surface BOP stack. Thus, with the

small businesses drilling an average of

31⁄3 wells per year, the annual economic

effect for each small business is about

$3,300, or about $300,000 in total. The

estimated additional cost of $1,000 per

well is quite small (about .02 percent)

when compared to the $5 million

average cost of drilling a well. Based on

this very low percentage of well cost, we

believe that these proposed revisions to

the regulations will not have a

significant economic effect on any small

lessee. However, we do invite comment

on our analytical procedures, data

inputs, and findings.

The estimated economic effects of the

requirement to use blind-shear rams on

surface BOP stacks is the cost to

purchase the rams. This requirement

imposes no reporting or recordkeeping

burden. This requirement primarily will

affect drilling contractors operating

jackup and platform rigs on the OCS

who will be required to purchase the

rams. Using information from 1999, the

cost for a set of 10,000 pounds persquare-inch rams and associated

equipment is about $175,000. Some sets

of rams for lower-rated BOP stacks will

cost less, while a few sets of rams will

cost more for higher-rated BOP stacks,

38462 Federal Register / Vol. 65, No. 120 / Wednesday, June 21, 2000 / Proposed Rules

but the average cost will remain at about

$175,000.

We estimate that drilling contractors

will need to purchase a total of 80 blind

shear rams to meet the proposed

requirements. At an average cost of

about $175,000, the economic impact

will be $14,000,000. The largest drilling

contractor may need to purchase up to

20 sets of blind-shear rams, while the

one small drilling contractor will not

need to purchase any blind-shear rams

because the contractor already has

blind-shear rams for its rigs. A large

contractor may get a minor reduction in

the cost with a bulk purchase, but this

reduction should not significantly affect

the competition between large and small

contractors because the unit costs will

not vary much. Purchase of the rams to

meet the proposed requirements will be

an initial one-time cost. A blind-shear

ram should last for 20 years if properly

maintained.

The blind-shear ram requirement

should not hinder the ability of lessees

or contractors, including small

businesses, to conduct business on the

OCS. The proposed rule provides for a

1-year period after the effective date for

drilling contractors to plan and

purchase the rams and associated

equipment. This will allow contractors

sufficient time to obtain the equipment.

In addition, several drilling contractors

likely have one or more sets of blindshear rams, because some lessees

currently require the installation of

these rams for their wells. Also, some

contractors may choose not to outfit all

of their rigs with blind-shear rams

immediately. Those contractors may

continue to market those rigs in State or

international waters where blind-shear

rams are not required.

The cost of blind-shear rams probably

will affect the rates that drilling

contractors charge lessees and operators

to drill wells. Contractors base these

rates, called day rates, primarily on the

supply and demand of drilling rigs. We

estimate that a minor increase in day

rates (estimated at between $250 and

$750 depending on rig capability and

ram size) would increase the costs of

drilling a typical OCS well by less than

1 percent. The minor increase in day

rates to pay for the blind-shear rams

should not last more than 3 years (the

estimated time to pay for the rams).

Since drilling contractors will have 1

year from the date of the final rule to

purchase this equipment, they should

have sufficient time to plan their

purchase and adjust their day rates to

reflect this cost. MMS believes the

purchase of this equipment or any

adjustments in day rates are unlikely to

affect the competition between large and

small drilling contractors.

The following table summarizes the

estimated economic effects associated

with this proposed rule.

Requirement Frequency Total cost Cost to small

businesses

New drilling rules .......................................................... Annual ........................................................................... $672,000 $300,000

Use of blind shear rams ............................................... One-time ....................................................................... 14,000,000 0

Total ....................................................................... ....................................................................................... 14,672,000 300,000

As discussed above, we do not believe

that this rule will have a significant

impact on the lessees and drilling

contractors who explore for and

produce oil and gas on the OCS,

including those that are classified as

small businesses. MMS asks for

comments on the expected duration of

the anticipated costs and the finding

that the impacts on small drilling

contractors are not significant.

Your comments are important. The

Small Business and Agriculture

Regulatory Enforcement Ombudsman

and 10 Regional Fairness Boards were

established to receive comments from

small businesses 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 proposed rule is not a major rule

under (5 U.S.C. 804(2)) the SBREFA.

This proposed rule:

(a) Does not have an annual effect on

the economy of $100 million or more.

As described above, we estimate that the

initial one-time cost of the proposed

rule to be $14 million and $672,000 in

subsequent years. These costs will not

cause an annual effect on the economy

of $100 million.

(b) Will not cause a major increase in

costs or prices or consumers, individual

industries, Federal, State, or local

government agencies, or geographic

regions. The minor increase in drilling

costs will not change the way the oil

and gas industry conducts business, nor

will it affect regional oil and gas prices;

therefore, it will not cause major cost

increases for consumers, the oil and gas

industry, or any Government agencies.

(c) Does not have significant adverse

effects on competition, employment,

investment, productivity, innovation, or

ability of U.S.-based enterprises to

compete with foreign-based enterprises.

All lessees and drilling contractors,

regardless of nationality, will have to

comply with the requirements of this

rule. So the rule will not affect

competition, employment, investment,

productivity, innovation, or the ability

of U.S.-based enterprises to compete

with foreign-based enterprises.

Unfunded Mandates Reform Act

(UMRA) of 1995 (E.O. 12866)

This proposed 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

proposed rule does not have any Federal

mandates nor does the proposed rule

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.

Federalism (E.O. 13132)

According to E.O. 13132, this rule

does not have Federalism implications.

This proposed rule does not

substantially and directly affect the

relationship between the Federal and

State Governments. The rule applies to

lessees and drilling contractors that

operate on the OCS. This rule does not

impose costs on States or localities. Any

costs will be the responsibility of the

lessees and drilling contractors.

Clarity of This Regulation

E.O. 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

proposed rule clearly stated?

(2) Does the proposed rule contain

technical language or jargon that

interfere with its clarity?

Federal Register / Vol. 65, No. 120 / Wednesday, June 21, 2000 / Proposed Rules 38463

(3) Does the format of the proposed

rule (grouping and order of sections, use

of headings, paragraphing, etc.) aid or

reduce its clarity?

(4) Would the proposed rule be easier

to understand if it were divided into

more (but shorter) sections?

(5) Is the description of the proposed

rule in the ‘‘Supplementary

Information’’ section of this preamble

helpful in understanding the proposed

rule? What else can we do to make the

proposed rule easier to understand?

Send a copy of any comments that

concern how we could make this

proposed 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

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: February 11, 2000.

Sylvia V. Baca,

Acting Assistant Secretary, Land and

Minerals Management.

For the reasons stated in the

preamble, the 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 § 250.198, in the table in

paragraph (e), the following changes are

made in alphanumeric order:

A. Add an entry for API RP 53 as set

forth below.

B. Revise the entry for API RP 500 as

set forth below.

§ 250.198 Documents incorporated by

reference.

* * * * *

(e) * * *

Title of documents Incorporated by reference at

*******

API RP 53, Recommended Practice for Blowout Prevention Equipment Systems for Drilling

Wells, Third Edition, March 1997, API Stock No. G53003

§ 250.442(b); § 250.446(a).

API RP 500, Recommended Practice for Classification of Locations for Electrical Installations at

Petroleum Facilities, First Edition, June 1, 1991, API Stock No. G06005

§ 250.459; § 250.802(e)(4)(I);

§ 250.803(b)(9)(I); § 250.1628(b)(3); (d)(4)(I);

§ 250.1629(b)(4)(I).

*******

3. In 30 CFR part 250, subpart D,

§ 250.417 is redesignated as § 250.470,

§§ 250.400 through 250.416 are revised,

and §§ 250.417 through 250.469 are

added and a new undesignated center

heading is added preceding

redesignated §§ 250.470 to read as set

forth below. For the convenience of the

reader, the table of contents for subpart

D is also set forth below:

Subpart D—Oil and Gas Drilling Operations

Sec.

250.400 Who is subject to the requirements

of this subpart?

250.401 What must I do to keep wells under

control?

250.402 When and how must I secure a

well?

250.403 What safety requirements must my

drilling unit meet?

250.404 What mobile drilling unit

movements must I report?

Application for Permit To Drill

Requirements

250.410 How can I apply for a permit to

drill a well?

250.411 What material must I submit with

my application?

250.412 What requirements must my plat

meet?

250.413 What items must my description of

well drilling design criteria address?

250.414 What items must my drilling

prognosis include?

250.415 What items must my casing and

cementing programs include?

250.416 What information must be

included in the diverter and BOP

descriptions?

250.417 What information must I provide if

I intend to use a mobile drilling unit to

drill a proposed rule?

250.418 What additional requirements must

I meet?

Casing and Cementing Requirements

250.420 What well casing and cementing

requirements must I meet?

250.421 What are the casing and cementing

requirements by type of casing string?

250.422 When may I resume drilling after

cementing?

250.423 How must I remedy cementing and

casing problems and situations?

250.424 What are the requirements for

pressure testing casing?

250.425 What special pressure tests must I

perform on casings for prolonged drilling

operations?

250.426 What are the requirements for

pressure testing liners?

250.427 What are the recordkeeping

requirements for casing and liner

pressure tests?

250.428 What are the requirements for

pressure integrity tests?

Diverter System Requirements

250.430 When must I install a diverter

system?

250.431 What are the diverter design and

installation requirements?

250.432 What must I do to obtain a

departure to diverter design and

installation requirements?

250.433 How must I test the diverter system

after installation?

250.434 What are the recordkeeping

requirements for diverter tests?

Blowout Preventer (BOP) System

Requirements

250.440 What are the general requirements

for BOP systems and system

components?

250.441 What are the requirements for a

surface BOP stack?

250.442 What are the requirements for a

subsea BOP stack?

250.443 What associated BOP systems and

related equipment must my BOP system

include?

250.444 What are the choke manifold

requirements?

250.445 What are the requirements for kelly

cocks, inside BOPs, and drill-string

safety valves?

250.446 What must I do to maintain and

inspect my BOP?

250.447 When must I conduct BOP system

pressure tests?

250.448 What are the BOP pressure tests

requirements?

250.449 What additional BOP testing

requirements must I comply with?

250.450 What are the recordkeeping

requirements for BOP tests?

38464 Federal Register / Vol. 65, No. 120 / Wednesday, June 21, 2000 / Proposed Rules

250.451 How do I remedy BOP problems

and situations?

Drilling Fluid Requirements

250.455 What are the general requirements

for a drilling fluid program?

250.456 What are the required safe drilling

fluid program practices?

250.457 What equipment must I have to test

and monitor drilling fluids?

250.458 What quantities of drilling fluids

are required?

250.459 What are the safety requirements

for drilling fluid-handling areas?

Other Drilling Requirements

250.460 What are the requirements for well

testing?

250.461 What are the requirements for

directional and inclination surveys?

250.462 What are the requirements for wellcontrol drills?

250.463 Who establishes field drilling

rules?

Sundry Notices and Well Records

250.465 When must I submit sundry notices

to MMS?

250.466 What well records must I keep?

250.467 What well records may I be

required to submit?

250.468 How long must I keep drillingrelated records?

250.469 Must I submit copies of well logs?

Hydrogen Sulfide

250.470 Hydrogen sulfide.

Subpart D—Oil and Gas Drilling

Operations

General Requirements

§ 250.400 Who is subject to the

requirements of this subpart?

The requirements of this subpart

apply to lessees, operators, and their

contractors and subcontractors.

§ 250.401 What must I do to keep wells

under control?

You must take necessary precautions

to keep wells under control at all times.

You must:

(a) Use the best available and safest

drilling technology to monitor and

evaluate well conditions and to

minimize the potential for the well to

flow or kick;

(b) Have a person onsite that

represents your interests and can fulfill

your responsibilities;

(c) Ensure that the toolpusher or a

member of the drilling crew maintains

continuous surveillance of the rig floor

from the beginning of drilling

operations until the well is abandoned,

unless you have secured the well with

blowout preventers (BOPs) or packers;

(d) Use personnel trained according to

the provisions of subpart O; and

(e) Use and maintain equipment and

materials necessary to ensure the safety

and protection of personnel, equipment,

natural resources, and the environment.

§ 250.402 When and how must I secure a

well?

Whenever you interrupt drilling

operations, you must install a downhole

safety device, such as a cement plug,

bridge plug, or packer. You must install

the device as deep as possible within a

properly cemented casing string.

(a) Among the events that may cause

you to interrupt drilling operations are:

(1) Evacuation of the drilling crew;

(2) Inability to keep the drilling rig on

location, or

(3) Repair to major drilling or wellcontrol equipment;

(b) For floating drilling operations, the

District Supervisor may approve the use

of a blind or blind-shear ram or pipe

rams and an inside BOP if you don’t

have time to install a downhole safety

device or if special circumstances occur.

§ 250.403 What safety requirements must

my drilling unit meet?

Your drilling unit must meet all of the

safety requirements in this section.

Required safety measure When required Additional requirements

(a) Crown block safety device ........ For each drilling unit ...................... (1) The device must prevent the traveling block from striking the

crown block.

(2) You must check the device for proper operation once a week and

after each drill-line slipping operation.

(3) You must record the results of this operational check in the

driller’s report.

(b) Diesel engine air intake shutdown device.For each diesel engine1. ............... (1) For a diesel engine that is not continuously manned, you must install an automatic shutdown device.1

(2) For a diesel engine that is continuously manned, you may install

either a manual or automatic air intake shutdown device.

(c) Shut in all producible wells located in the affected wellbay.When you move a drilling rig or related equipment on a platform.You must shut in each well below the surface and at the wellhead,

unless otherwise approved by the District Supervisor.

(d) Emergency shutdown station installed near the driller’s console.When you conduct drilling operations on a platform that has

producing wells or other hydrocarbon flow.

1You do not need to install an air-intake shutdown device on a diesel engine that starts a larger engine or that powers any of the following: (1)

Firewater pumps; (2) Emergency generators; (3) BOP accumulator systems; (4) Air supply to divers or confined entry personnel; (5) Temporary

equipment on nonproducing platforms; or (6) Portable single cylinder rig washers.

§ 250.404 What mobile drilling unit

movements must I report?

You must report the movement of a

mobile drilling unit on and off a drilling

location to the District Supervisor. You

must inform the District Supervisor 24

hours before the arrival of the rig on

location and 24 hours before the rig

departs from the location.

Applying for a Permit to Drill

§ 250.410 How can I apply for a permit to

drill a well?

(a) You must obtain written or oral

approval from the District Supervisor

before you begin drilling any well. To

obtain approval, you must :

(1) Submit the forms required by

paragraph (b) of this section;

(2) Submit the information required

by § 250.411;

(3) Include the well in your approved

Exploration Plan (EP), Development and

Production Plan (DPP), or Development

Operations Coordination Document

(DOCD); and

(4) Meet the oil spill financial

responsibility requirements for offshore

facilities as required by 30 CFR part 253.

(b) You must submit the following

forms to the District Supervisor:

(1) An original and two copies of form

MMS–123, Application for a Permit to

Drill (APD);

(2) A separate public information

copy of form MMS–123 that meets the

requirements of § 250.127; and

Federal Register / Vol. 65, No. 120 / Wednesday, June 21, 2000 / Proposed Rules 38465

(3) Form MMS–123S, APD

Information Sheet.

§ 250.411 What material must I submit with

my application?

In addition to forms MMS–123 and

MMS–123S, you must include the

information described in the following

table.

Information that you must include with an APD Where to find

a description

(a) Plat that shows locations of the proposed well ............................................................................................................................. § 250.412

(b) Design criteria used for the proposed well .................................................................................................................................... 250.413

(c) Drilling prognosis ............................................................................................................................................................................ 250.414

(d) Casing and cementing programs ................................................................................................................................................... 250.415

(e) Diverter and BOP systems descriptions ........................................................................................................................................ 250.416

(f) Requirements for using a mobile drilling unit ................................................................................................................................. 250.417

(g) Additional requirements ................................................................................................................................................................. 250.418

§ 250.412 What requirements must my plat

meet?

(a) Have a scale of 1:24,000 (1 inch =

2,000 feet);

(b) Show the surface and subsurface

locations of the proposed well and all

the wells in the vicinity;

(c) Show the surface and subsurface

locations of the proposed well in feet or

meters from the block line;

(d) Contain the longitude and latitude

coordinates, and either Universal

Transverse Mercator grid-system

coordinates or state plane coordinates in

the Lambert or Transverse Mercator

Projection system for the surface and

subsurface locations of the proposed

well; and

(e) State the units and geodetic datum

(including whether the datum is North

American Datum 27 or 83) for these

coordinates. If the datum was converted,

you must state the method used for this

conversion, since the various methods

may produce different values.

§ 250.413 What items must my description

of well drilling design criteria address?

(a) Pore pressures;

(b) Formation fracture gradients,

adjusted for water depth;

(c) Potential lost circulation zones;

(d) Drilling fluid weights;

(e) Casing setting depths;

(f) Maximum anticipated surface

pressures. For this section, maximum

anticipated surface pressures are the

pressures that you reasonably expect to

be exerted upon a casing string and its

related wellhead equipment. In

calculating maximum anticipated

surface pressures, you must consider:

drilling, completion, and producing

conditions; drilling fluid densities to be

used below various casing strings;

fracture gradients of the exposed

formations; casing setting depths; total

well depth; formation fluid types; safety

margins; and other pertinent conditions.

You must include the calculations used

to determine the pressures for the

drilling and the completion phases,

including the anticipated surface

pressure used for designing the

production string;

(g) A single plot containing estimated

pore pressures, formation fracture

gradients, proposed drilling fluid

weights, and casing setting depths in

true vertical measurements;

(h) A summary report of the shallow

hazards site survey that describes the

geological and manmade conditions;

and

(i) Permafrost zones, if applicable.

§ 250.414 What items must my drilling

prognosis include?

(a) Projected plans for coring at

specified depths;

(b) Projected plans for logging;

(c) Planned safe drilling margin

between proposed drilling fluid weights

and estimated pore pressures. This safe

drilling margin may be shown on the

plot required by § 250.413(g);

(d) Estimated depths to the top of

significant marker formations;

(e) Estimated depths to significant

porous and permeable zones containing

fresh water, oil, gas, or abnormally

pressured formation fluids;

(f) Estimated depths to faults; and

(g) Estimated depths of permafrost, if

applicable.

§ 250.415 What items must my casing and

cementing programs include?

(a) Hole sizes and casing sizes,

including: weights; grades; tension,

collapse, and burst values; types of

connection; and setting depths

(measured and true vertical depth);

(b) Casing design safety factors for

tension, collapse, and burst with the

assumptions made to arrive at these

values;

(c) Type and amount of cement (in

cubic feet) planned for each casing

string; and

(d) In areas containing permafrost,

setting depths for conductor and surface

casing based on the anticipated depth of

the permafrost. Your program must

provide protection from thaw

subsidence and freezeback effect, proper

anchorage, and well control.

§ 250.416 What information must be

included in the diverter and BOP

descriptions?

(a) A description of the diverter

system and its operating procedures;

(b) A schematic drawing of the

diverter system (plan and elevation

views) that shows:

(1) the size of the annular preventer

installed in the diverter housing;

(2) spool outlet internal diameter(s);

(3) diverter-line lengths and

diameters; burst strengths and radius of

curvature at each turn; and

(4) valve type, size, working pressure

rating, and location;

(c) A description of the BOP system

and system components, including

pressure ratings of BOP equipment and

proposed BOP test pressures; and

(d) A schematic drawing of the BOP

system that shows the inside diameter

of the BOP stack, number and type of

preventers, location of choke and kill

lines, and associated valves.

§ 250.417 What information must I provide

if I intend to use a mobile drilling unit to

drill a proposed well?

(a) Fitness requirements. You must

provide information and data to

demonstrate the drilling unit’s

capability to perform at the proposed

drilling operation. This information

must include the maximum

environmental and operational

conditions that the unit is designed to

withstand, including the minimum air

gap necessary for both hurricane and

non-hurricane seasons. If sufficient

environmental information and data are

not available, the District Supervisor

may require you to collect and report

this information.

(b) Foundation requirements. You

must provide information to show that

site-specific soil and oceanographic

conditions are capable of supporting the

proposed drilling unit. If you provided

sufficient site-specific information in

your EP, DPP, or DOCD, you may

reference that information. The District

Supervisor may require you to conduct

38466 Federal Register / Vol. 65, No. 120 / Wednesday, June 21, 2000 / Proposed Rules

additional surveys and soil borings

before approving the APD.

(c) Third-party review. If the design of

the drilling unit is unique or has not

been proven for use in the proposed

environment, the District Supervisor

may require you to submit a third-party

review of the unit’s design. If required,

you must obtain the third-party review

according to § 250.903. You may submit

this information before submitting an

APD.

(d) Frontier areas. If you plan to drill

in a frontier area, you must have a

contingency plan that addresses design

and operating limitations of the drilling

unit. Your plan must identify the

actions necessary to maintain safety and

prevent damage to the environment.

Actions must include the suspension,

curtailment, or modification of drilling

or rig operations to remedy various

operational or environmental situations

(e.g. vessel motion, riser offset, anchor

tensions, wind speed, wave height,

currents, icing or ice-loading, settling,

tilt or lateral movement, resupply

capability).

(e) U.S. Coast Guard (USCG)

Documentation. You must provide the

current Certificate of Inspection or

Letter of Compliance from the USCG.

You must also provide current

documentation of any operational

limitations imposed by an appropriate

classification society.

(f) Floating drilling unit. If you use a

floating drilling unit, you must have a

contingency plan for moving off

location in an emergency situation.

(g) Inspection of unit. The drilling

unit must be available for inspection by

the District Supervisor before

commencing operations.

(h) Once the District Supervisor has

approved a mobile drilling unit for use,

you do not need to re-submit the

information required by this section

unless changes in equipment affect its

rated capacity to operate in the District.

§ 250.418 What additional requirements

must I meet?

You must include the following with

the APD:

(a) Rated capacities of the drilling rig

and major drilling equipment, if not

already on file with the appropriate

District office;

(b) Drilling fluids program that

includes the minimum quantities of

drilling fluids and drilling fluid

materials, including weight materials, to

be kept at the site;

(c) Proposed directional plot if the

well is to be directionally drilled;

(d) Hydrogen Sulfide Contingency

Plan (refer to § 250.470) if applicable

and not previously submitted;

(e) Welding and Burning Plan (refer to

§ 250.106) if applicable and not

submitted previously;

(f) In areas subject to subfreezing

conditions, evidence that the drilling

equipment, BOP systems and

components, diverter systems, and other

associated equipment and materials are

suitable for operating under such

conditions;

(g) A list and description of all

requests for using alternative procedures

or departures from the requirements of

this subpart in one place in the APD.

You must explain how the alternative

procedures afford an equal or greater

degree of protection, safety, or

performance, or why you need the

departure; and

(h) Such other information as the

District Supervisor may require.

Casing and Cementing Requirements

§ 250.420 What well casing and cementing

requirements must I meet?

You must case and cement all wells.

Your casing and cementing programs

must meet the requirements of this

section and of §§ 250.421 through

250.428.

(a) What casing and cementing

programs must do. Your casing and

cementing programs must:

(1) Properly control formation

pressures and fluids;

(2) Prevent the direct or indirect

release of fluids from any stratum

through the wellbore into offshore

waters;

(3) Prevent communication between

separate hydrocarbon-bearing strata;

(4) Protect freshwater aquifers from

contamination; and

(5) Support unconsolidated

sediments.

(b) Casing requirements. (1) You must

design casing (including liners) to

withstand the anticipated stresses

imposed by tensile, compressive, and

buckling loads; burst and collapse

pressures; thermal effects; and

combinations thereof.

(2) The casing design must include

safety measures that ensure well control

during drilling and safe operations

during the life of the well.

(c) Cementing requirements. You must

design and conduct your cementing jobs

so that cement composition, placement

techniques, and waiting times ensure

that the cement placed behind the

bottom 500 feet of casing attains a

minimum compressive strength of 500

psi.

§ 250.421 What are the casing and

cementing requirements by type of casing

string?

The table in this section identifies

specific design, setting, and cementing

requirements for casing strings and

liners. For the purposes of subpart D,

the casing strings in order of normal

installation are as follows: drive or

structural, conductor, surface,

intermediate, and production casings

(including liners). The District

Supervisor may approve or prescribe

other casing and cementing

requirements where appropriate.

Casing type Casing requirements Cementing requirements

(a) Drive or Structural Set by driving, jetting, or drilling to the minimum depth as

approved or prescribed by the District Supervisor.

If you drilled a portion of this hole, you must use enough

cement to fill the annular space back to the mudline.

(b) Conductor ........... Design casing and select setting depths based on relevant

engineering and geologic factors. These factors include

the presence or absence of hydrocarbons, potential hazards, and water depths.

Set casing immediately before drilling into formations

known to contain oil or gas. If you encounter oil or gas

or unexpected formation pressure before the planned

casing point, you must set casing immediately.

Use enough cement to fill the calculated annular space

back to the mudline.

Verify annular fill by observing cement returns. If you cannot observe cement returns, use additional cement to

ensure fill-back to the mudline.

For drilling on an artificial island or when using a glory

hole, you must discuss the cement fill level with the District Supervisor.

(c) Surface ................ Design casing and select setting depths based on relevant

engineering and geologic factors. These factors include

the presence or absence of hydrocarbons, potential hazards, and water depths.

Use enough cement to fill the calculated annular space to

at least 200 feet inside the conductor casing.

When geologic conditions such as near-surface fractures

and faulting exist, you must use enough cement to fill

the calculated annular space to the mudline.

Federal Register / Vol. 65, No. 120 / Wednesday, June 21, 2000 / Proposed Rules 38467

Casing type Casing requirements Cementing requirements

(d) Intermediate ........ Design casing and select setting depth based on anticipated or encountered geologic characteristics or wellbore

conditions.

Use enough cement to cover and isolate all hydrocarbonbearing zones in the well.

As a minimum, you must cement the annular space 500

feet above the casing shoe and each zone to be isolated.

(e) Production ........... Design casing and select setting depth based on anticipated or encountered geologic characteristics or wellbore

conditions.

Use enough cement to cover or isolate all hydrocarbonbearing zones above the shoe. As a minimum, you must

cement the annular space at least 500 feet above the

casing shoe and the uppermost hydrocarbon-bearing

zone.

(f) Liners ................... If you use a liner as conductor or surface casing, you must

set the top of the liner at least 200 feet above the previous casing/liner shoe.

If you use a liner as an intermediate or production casing,

you must set the top of the liner at least 100 feet above

the previous casing shoe.

Same as cementing requirements for specific casing types.

For example, a liner used as intermediate casing must

be cemented according to the cementing requirements

for intermediate casing.

§ 250.422 When may I resume drilling after

cementing?

(a) After cementing surface,

intermediate, or production casing (or

liners), you may not resume drilling

until the cement has been held under

pressure for 12 hours. For conductor

casing, you may not resume drilling

until the cement has been held under

pressure for 8 hours. Methods of

holding cement under pressure include

using float valves to hold the cement in

place.

(b) If you plan to nipple down your

diverter or BOP stack during the 8- or

12-hour waiting time, you must

determine, in advance, when it will be

safe to conduct this activity. Your

determination must consider cement

composition, well conditions, and the

effects of nippling down the equipment.

§ 250.423 How must I remedy cementing

and casing problems and situations?

The table in this section describes

remedies to problems and situations

that lessees encounter on a regular basis

during casing and cementing activities.

If you have the following problem or situation: Then you must . . .

(a) Encounter unexpected formation pressures

or conditions that warrant revising your casing design.

Submit a revised casing program to the District Supervisor for approval.

(b) Change casing setting depths more than

100 feet from the approved APD.

Submit those changes to the District Supervisor for approval.

(c) Indication of inadequate cement job (such

as lost returns, cement channeling, or failure

of equipment).

(1) Pressure test the casing shoe,

(2) Run a temperature survey,

(3) Run a cement bond log, or

(4) Use a combination of these techniques.

(d) Inadequate cement job ................................. Re-cement or take other remedial actions as approved by the District Supervisor.

(e) Primary cement job did not isolate abnormal

pressure intervals.

Isolate those intervals from normal pressures by squeeze cementing before you complete;

suspend operations; or abandon the well, whichever occurs first.

(f) Plan to produce a well ................................... Have at least two cemented casing strings (does not include liners) in the well.

(g) Plan to wash out or displace some cement

to facilitate casing removal upon well abandonment.

Obtain approval from the District Supervisor.

(h) Plan to drill a well without setting conductor

casing.

Submit geologic data and information to the District Supervisor that demonstrates the absence

of shallow hydrocarbons or hazards. This information must include logging and drilling fluidmonitoring from wells previously drilled within 500 feet of the proposed well path down to

the next casing point.

(i) Plan to use less than required cement for the

surface casing during floating drilling operations.

Submit information to the District Supervisor that demonstrates the use of less cement is necessary to provide protection from burst and collapse pressures.

(j) Plan to cement across a permafrost zone ..... Use cement that sets before it freezes and has a low heat of hydration.

(k) Plan to leave the annulus opposite a permafrost zone uncemented.Fill the annulus with a liquid that has a freezing point below the minimum permafrost temperature and minimizes corrosion.

(l) If your problem or situation is not described

in this table.

Contact the District Supervisor.

§ 250.424 What are the requirements for

pressure testing casing?

(a) You must pressure test each string

of casing to 70 percent of its minimum

internal yield. This testing requirement

does not apply to drive or structural

casing. When a diverter is installed on

conductor casing, you must test the

casing to a minimum of 200 psi. The

District Supervisor may approve or

require other casing test pressures.

(b) You may not resume drilling or

other down-hole operations until you

obtain a satisfactory pressure test. If the

pressure declines more than 10 percent

in a 30-minute test or if there is another

indication of a leak, you must recement, repair the casing, or run

additional casing to provide a proper

seal.

§ 250.425 What special pressure tests

must I perform on casings for prolonged

drilling operations?

(a) If wellbore operations continue for

more than 30 days within a casing string

run to the surface, you must stop

drilling operations as soon as

38468 Federal Register / Vol. 65, No. 120 / Wednesday, June 21, 2000 / Proposed Rules

practicable thereafter and evaluate the

effects of the prolonged operations on

continued drilling operations and the

life of the well. At a minimum, you

must:

(1) Caliper or pressure test the casing;

and

(2) Report the results of your

evaluation to the District Supervisor and

obtain approval of those results before

resuming operations.

(b) If casing integrity has deteriorated

to a level below minimum safety factors,

you must:

(1) Repair the casing or run another

casing string; and

(2) Obtain approval from the District

Supervisor before you begin repairs.

§ 250.426 What are the requirements for

pressure testing liners?

(a) You must test each drilling liner

(and liner-lap) to a pressure at least

equal to the anticipated pressure to

which the liner will be subjected during

the formation pressure-integrity test

below that liner shoe, or subsequent

liner shoes if set. The District

Supervisor may approve or require other

liner test pressures.

(b) You must test each production

liner (and liner-lap) to a minimum of

500 psi above the formation fracture

pressure at the casing shoe into which

the liner is lapped.

(c) You may not resume drilling or

other down-hole operations until you

obtain a satisfactory pressure test. If the

pressure declines more than 10 percent

in a 30-minute test or if there is another

indication of a leak, you must recement, repair the liner, or run

additional casing/liner to provide a

proper seal.

§ 250.427 What are the recordkeeping

requirements for casing and liner pressure

tests?

You must record the time, date, and

results of each pressure test in the

driller’s report. In addition, you must

record each test on a pressure chart and

have your onsite representative certify

(sign and date) the test as correct.

§ 250.428 What are the requirements for

pressure integrity tests?

You must conduct a pressure integrity

test below the surface casing/liner and

intermediate casing(s)/liner(s). The

District Supervisor may require you to

run a pressure-integrity test at the

conductor casing shoe if warranted by

local geologic conditions or the planned

casing setting depth. You must conduct

each pressure integrity test after drilling

no more than 50 feet of new hole below

the casing shoe. You must test to either

the formation leak-off pressure or to an

equivalent drilling fluid weight if

identified in an approved APD.

(a) You must use the pressure

integrity test and related hole-behavior

observations, such as pore-pressure test

results, gas-cut drilling fluid, and well

kicks to adjust the drilling fluid program

and the setting depth of the next casing

string. You must record all test results

and hole-behavior observations made

during the course of drilling related to

formation integrity and pore pressure in

the driller’s report.

(b) While drilling, you must maintain

the safe drilling margin identified in the

approved APD. When you cannot

maintain this safe margin, you must

suspend drilling operations and remedy

the situation.

Diverter System Requirements

§ 250.430 When must I install a diverter

system?

You must install a diverter system

before you drill a conductor or surface

hole. You must design, install, use,

maintain, and test the diverter system to

ensure proper diversion of gases, water,

drilling fluid, and other materials away

from facilities and personnel. The

diverter system consists of a diverter

sealing element, diverter lines, and

control systems.

§ 250.431 What are the diverter design and

installation requirements?

You must design and install your

diverter system to:

(a) Use diverter spool outlets and

diverter lines that have an internal

diameter of at least 10 inches for surface

wellhead configurations and at least 12

inches for floating drilling operations;

(b) Use dual diverter lines arranged to

provide for downwind diversion

capability;

(c) Use at least two diverter control

stations. One station must be on the

drilling floor. The other must be in a

readily accessible location away from

the drilling floor;

(d) Use only remote-controlled valves

in the diverter lines. All valves in the

diverter system must be full-opening.

You may not install manual or butterfly

valves in any part of the diverter system;

(e) Minimize the number of turns

(only one 90-degree turn allowed for

each line for bottom-founded drilling

units) in the diverter lines, maximize

the radius of curvature of turns, and

target all right-angles and sharp turns;

(f) Anchor and support the entire

diverter system to prevent whipping

and vibration; and

(g) Protect all diverter-control

instruments and lines from damage by

thrown or falling objects.

§ 250.432 What must I do to obtain a

departure to diverter design and installation

requirements?

The table below describes possible

departures to the diverter requirements

and the conditions required for each

departure. To obtain one of these

departures, you must have discussed or

noted the departure in your APD.

If you want a departure to: Then you must . . .

(a) Use flexible hose for diverter lines instead of rigid pipe .................... Use flexible hose that has integral end couplings.

(b) Use only one spool outlet for your diverter system ............................ (1) Have branch lines that meet the minimum internal diameter requirements: and

(2) provide downwind diversion capability.

(c) Use a spool with an outlet with an internal diameter of less than 10

inches on a surface wellhead.

Use a spool that has dual outlets with an internal diameter of at least 8

inches.

(d) Use a single diverter line for floating drilling operations on a dynamically positioned drillship.Maintain an appropriate vessel heading to provide for downwind diversion.

(e) If the departure you need is not described in this table ..................... Contact the District Supervisor.

§ 250.433 How must I test the diverter

system after installation?

When you install the diverter system,

you must actuate the diverter sealing

element, diverter valves, and divertercontrol systems and control stations.

You must also flow-test the vent lines.

(a) For drilling operations with a

surface wellhead configuration, you

must actuate the diverter system at least

once every 24-hour period after the

initial test. After you have nippled up

on conductor casing, you must pressuretest the diverter-sealing element and

diverter valves to a minimum of 200 psi.

While the diverter is installed, you must

Federal Register / Vol. 65, No. 120 / Wednesday, June 21, 2000 / Proposed Rules 38469

conduct subsequent pressure tests

within 7 days of the previous test.

(b) For floating drilling operations

with a subsea BOP stack, you must

actuate the diverter system at least once

every 7 days after the previous test.

(c) You must alternate actuations and

tests between control stations.

§ 250.434 What are the recordkeeping

requirements for diverter tests?

You must record the time, date, and

results of all diverter actuations and

tests in the driller’s report. In addition,

you must:

(a) Record the diverter pressure test

on a pressure chart;

(b) Require your onsite representative

to certify (sign and date) the pressure

test chart as correct;

(c) Identify the control station or pod

used during the test or actuation;

(d) Identify problems or irregularities

observed during the testing or

actuations and record actions taken to

remedy the problems or irregularities;

(e) Retain all pressure charts and

reports pertaining to the diverter tests

and actuations at the facility for the

duration of drilling; and

(f) After drilling is completed, retain

all the records listed in this section for

2 years at the facility, at the lessee’s

field office nearest to the facility, or at

another location conveniently available

to the District Supervisor.

Blowout Preventer (BOP) System

Requirements

§ 250.440 What are the general

requirements for BOP systems and system

components?

You must design, install, maintain,

and use the BOP system and system

components to ensure well control. The

working-pressure rating of each BOP

component must exceed maximum

anticipated surface pressures. The BOP

system includes the BOP stack and

associated BOP systems and equipment.

§ 250.441 What are the requirements for a

surface BOP stack?

(a) When you drill with a surface BOP

stack, you must install the BOP system

before drilling below surface casing. The

surface BOP stack must have at least

four remote-controlled, hydraulically

operated BOPs, consisting of an annular

preventer, two preventers equipped

with pipe rams, and one preventer

equipped with blind or blind-shear

rams.

(b) One year after the effective date of

this final rule, the surface BOP stack

must have at least four remotecontrolled, hydraulically operated BOPs

consisting of an annular preventer, two

preventers equipped with pipe rams,

and one preventer equipped with blindshear rams.

(c) In addition to the stack, you must

install the associated BOP systems and

equipment required by the regulations

in this subpart.

§ 250.442 What are the requirements for a

subsea BOP stack?

(a)(1) When you drill with a subsea

BOP stack, you must install the BOP

system before drilling below surface

casing. The District Supervisor may

require you to install a subsea BOP

system before drilling below the

conductor casing if proposed casing

setting depths or local geology indicate

the need.

(2) Your subsea BOP stack must have

at least four remote-controlled,

hydraulically operated BOPs consisting

of an annular preventer, two preventers

equipped with pipe rams, and one

preventer equipped with blind-shear

rams.

(3) In addition to the subsea stack,

you must install the associated BOP

systems and equipment required by the

paragraphs below and the regulations in

this subpart.

(b) You must install a subsea

accumulator closing unit to provide fast

closure of the BOP components and to

operate all critical functions in case of

a loss of the power fluid connection to

the surface. The subsea accumulator

must meet or exceed the provisions of

Section 13.3, Accumulator Volumetric

Capacity, in API RP 53, Recommended

Practice for Blowout Prevention

Equipment Systems for Drilling Wells.

The District Supervisor may approve a

suitable alternate method.

(c) The subsea BOP system must

include an operable dual-pod control

system to ensure proper and

independent operation of the BOP

system.

(d) Before removing the marine riser,

you must displace the riser with

seawater. You must maintain sufficient

hydrostatic pressure or take other

suitable precautions to compensate for

the reduction in pressure and to

maintain a safe and controlled well

condition.

§ 250.443 What associated BOP systems

and related equipment must my BOP

system include?

(a) An accumulator system that

provides 1.5 times the volume of fluid

capacity necessary to close and hold

closed all BOP components. The system

must perform with a minimum pressure

of 200 psi above the precharge pressure

without assistance from a charging

system. If you supply the accumulator

regulators by rig air and do not have a

secondary source of pneumatic supply,

you must equip the regulators with

manual overrides or other devices to

ensure capability of hydraulic

operations if rig air is lost.

(b) An automatic backup to the

primary accumulator-charging system.

The power source must be independent

from the power source for the primary

accumulator-charging system. The

independent power source must possess

sufficient capability to close and hold

closed all BOP components.

(c) At least two BOP control stations.

One station must be on the drilling

floor. You must locate the other station

in a readily accessible location away

from the drilling floor.

(d) Side outlets on the BOP stack for

separate kill and choke lines. If your

stack does not have side outlets, you

must install a drilling spool with side

outlets.

(e) A choke and a kill line on the BOP

stack. You must equip each line with

two full-opening valves with at least one

remote-controlled valve on each line.

For a subsea BOP system, both valves in

each line must be remote-controlled. In

addition:

(1) You must install the choke line

above the bottom ram;

(2) You may install the kill line below

the bottom ram; and

(3) For a surface BOP system, you may

install a check valve on the kill line

instead of the remote-controlled valve.

To use this check valve, both manual

valves must be readily accessible, and

you must install the check valve

between the manual valves and the

pump.

(f) A fill-up line above the uppermost

preventer.

(g) Locking devices installed on the

ram-type preventers.

(h) A wellhead assembly with a rated

working pressure that exceeds the

anticipated surface pressure.

§ 250.444 What are the choke manifold

requirements?

(a) Your BOP system must include a

choke manifold that is suitable for the

anticipated surface pressures,

anticipated methods of well control, the

surrounding environment, and the

corrosiveness, volume, and abrasiveness

of drilling fluids and well fluids that

you may encounter.

(b) Manifold components must have a

rated working pressure at least as great

as the rated working pressure of the ram

BOPs. If your manifold has buffer tanks

downstream of choke assemblies, you

must install isolation valves on any

bleed lines.

(c) Valves, pipes, flexible steel hoses,

and other fittings upstream of the choke

38470 Federal Register / Vol. 65, No. 120 / Wednesday, June 21, 2000 / Proposed Rules

manifold must have a rated working

pressure at least as great as the rated

working pressure of the ram BOPs.

§ 250.445 What are the requirements for

kelly cocks, inside BOPs, and drill-string

safety valves?

You must use or provide the

following BOP equipment during

drilling operations:

(a) A kelly cock installed below the

swivel (upper kelly cock);

(b) A kelly cock installed at the

bottom of the kelly (lower kelly cock).

You must be able to strip the lower kelly

cock through the BOP stack;

(c) If you drill with a mud motor and

use drill pipe instead of a kelly, you

must install one kelly cock above, and

one strippable kelly cock below, the

joint of drill pipe used in place of a

kelly;

(d) On a top-drive system equipped

with a remote-controlled valve, you

must install a strippable kelly-cock-type

valve below the remote-controlled

valve;

(e) An inside BOP in the open

position located on the rig floor. You

must be able to install an inside BOP for

each size connection in the drill string;

(f) A drill-string safety valve in the

open position located on the rig floor.

You must have a drill-string safety valve

available for each size connection in the

drill string;

(g) When running casing, you must

have a safety valve in the open position

available on the rig floor to fit the casing

string being run in the hole;

(h) All required manual and remotecontrolled kelly-cock valves, drill-string

safety valves, and comparable-type

valves in a top-drive system must be

essentially full-opening; and

(i) The drilling crew must have ready

access to a wrench to fit each manual

valve.

§ 250.446 What must I do to maintain and

inspect my BOP?

(a) You must maintain your BOP

system to ensure that the equipment

functions properly. BOP maintenance

must meet or exceed the provisions of

Sections 17.10 and 18.10, Inspections;

Sections 17.11 and 18.11, Maintenance;

and Sections 17.12 and 18.12, Quality

Management, described in API RP 53,

Recommended Practice for Blowout

Prevention Equipment Systems for

Drilling Wells.

(b) You must visually inspect your

surface BOP system on a daily basis.

You must visually inspect your subsea

BOP system and marine riser at least

once every 3 days if weather and sea

conditions permit. You may use

television cameras to inspect subsea

equipment.

§ 250.447 When must I conduct BOP

system pressure tests?

You must pressure test your BOP

system (this includes the choke

manifold, kelly cocks, inside BOP, and

drill-string safety valve):

(a) When installed;

(b) Before 14 days have elapsed since

your last BOP pressure test. You must

begin to test your BOP system before

midnight on the 14th day following the

conclusion of the previous test.

However, the District Supervisor may

require more frequent testing if

conditions or BOP performance warrant;

and

(c) Before drilling out each string of

casing or a liner. The District Supervisor

may allow you to omit this test if you

didn’t remove the BOP stack to run the

casing string or liner and the required

BOP test pressures for the next section

of the hole are not greater than the test

pressures for the previous BOP test. You

must indicate in your APD which casing

strings and liners meet these criteria.

§ 250.448 What are the BOP pressure tests

requirements?

When you pressure test the BOP

system, you must conduct a lowpressure and a high-pressure test for

each BOP component. You must

conduct the low-pressure test before the

high-pressure test. Each individual

pressure test must hold pressure long

enough to demonstrate that the tested

component(s) holds the required

pressure. Required test pressures are as

follows:

(a) Low-pressure test. All low-pressure

tests must be between 200 and 300 psi.

Any initial pressure above 300 psi must

be bled back to a pressure between 200

and 300 psi before starting the test. If

the initial pressure exceeds 500 psi, you

must bleed back to zero and reinitiate

the test.

(b) High-pressure test for ram-type

BOPs, the choke manifold, and other

BOP components. The high-pressure

test must equal the rated working

pressure of the equipment or be 500 psi

greater than your calculated maximum

anticipated surface pressure (MASP) for

the applicable section of hole. Before

you may test BOP equipment to the

MASP plus 500 psi, the District

Supervisor must have approved those

test pressures in your APD.

(c) High pressure test for annular-type

BOPs. The high pressure test must equal

70 percent of the rated working pressure

of the equipment.

(d) Duration of pressure test. Each test

must hold the required pressure for 5

minutes. However, for surface BOP

systems and surface equipment of a

subsea BOP system, a 3-minute test

duration is acceptable if you record your

test pressures on the outermost half of

a 4-hour chart, on a 1-hour chart, or on

a digital recorder. If the equipment does

not hold the required pressure during a

test, you must correct the problem and

retest the affected component(s).

§ 250.449 What additional BOP testing

requirements must I comply with?

(a) Use water to test a surface BOP

system;

(b) Stump test a subsurface BOP

system before installation. You must use

water to conduct this test. You may use

drilling fluids to conduct subsequent

tests of a subsea BOP system;

(c) Alternate tests between control

stations and pods;

(d) Pressure test the blind or blindshear ram during stump tests and at all

casing points;

(e) The interval between any blind or

blind-shear ram pressure tests may not

exceed 30 days;

(f) Pressure test variable bore-pipe

rams against all sizes of pipe in use,

excluding drill collars and bottom-hole

tools;

(g) Pressure test affected BOP

components following the

disconnection or repair of any wellpressure containment seal in the

wellhead or BOP stack assembly;

(h) Function test annulars and rams

every 7 days between pressure tests; and

(i) Actuate safety valves assembled

with proper casing connections before

running casing.

§ 250.450 What are the recordkeeping

requirements for BOP tests?

You must record the time, date, and

results of all pressure tests, actuations,

and inspections of the BOP system,

system components, and marine riser in

the driller’s report. In addition, you

must:

(a) Record BOP test pressures on

pressure charts;

(b) Require your onsite representative

to certify (sign and date) BOP test charts

and reports as correct;

(c) Document the sequential order of

BOP and auxiliary equipment testing

and the pressure and duration of each

test. For subsea BOP systems, you must

also record the closing times for annular

and ram preventers. You may reference

a BOP test plan if it is available at the

facility;

(d) Identify the control station or pod

used during the test;

(e) Identify any problems or

irregularities observed during BOP

system testing and record actions taken

to remedy the problems or irregularities;

(f) Retain all records, including

pressure charts, driller’s report, and

Federal Register / Vol. 65, No. 120 / Wednesday, June 21, 2000 / Proposed Rules 38471

referenced documents pertaining to BOP

tests, actuations, and inspections at the

facility for the duration of drilling; and

(g) After drilling is completed, you

must retain all the records listed in this

section for a period of 2 years at the

facility, at the lessee’s field office

nearest the facility, or at another

location conveniently available to the

District Supervisor.

§ 250.451 How do I remedy BOP problems

and situations?

The table in this section describes

remedies to problems and situations

that lessees encounter with BOP

systems on a regular basis during

drilling activities.

If you have the following situation or problem: Then you must . . .

(a) BOP equipment does not hold the required pressure during a test .. Correct the problem and retest the affected equipment.

(b) Need to repair or replace a surface or subsea BOP system ............. First place the well in a safe, controlled condition (e.g., before drilling

out a casing shoe or after setting a cement plug, bridge plug, or a

packer).

(c) Need to postpone a BOP test due to well-control problems such as

lost circulation, formation fluid influx, or stuck drill pipe.

Record the reason for postponing the test in the driller’s report and

conduct the required BOP test on the first trip out of the hole.

(d) BOP control station or pod that does not function properly ............... Suspend further drilling operations until that station or pod is operable.

(e) Want to drill with a tapered drill-string ................................................ Install two or more sets of conventional or variable-bore pipe rams in

the BOP stack to provide for the following: two sets of rams must be

capable of sealing around the larger-size drill string and one set of

pipe rams must be capable of sealing around the smaller-size drill

string.

(f) Install casing rams in a BOP stack ..................................................... Test the ram bonnets before running casing.

(g) Want to use an annular preventer with a rated working pressure

less than the anticipated surface pressure.

Demonstrate that your well control procedures or the anticipated well

conditions will not place demands above its rated working pressure

and obtain approval from the District Supervisor.

(h) Use a subsea BOP system in an ice-scour area ............................... Install the BOP stack in a glory hole. The glory hole must be deep

enough to ensure that the top of the stack is below the deepest

probable ice-scour depth.

(i) If your problem or situation is not described in this table ................... Contact the District Supervisor.

Drilling Fluid Requirements

§ 250.455 What are the general

requirements for a drilling fluid program?

You must design and implement your

drilling fluid program to prevent the

loss of well control. This program must

address drilling fluid safe practices,

testing and monitoring equipment,

drilling fluid quantities, and drilling

fluid handling areas.

§ 250.456 What are the required safe

drilling fluid program practices?

Your drilling fluid program must

include the following safe practices:

(a) Before starting out of the hole with

drill pipe, you must properly condition

the drilling fluid. You must circulate a

volume of drilling fluid equal to the

annular volume with the drill pipe just

off-bottom. You may omit this practice

if documentation in the driller’s report

shows:

(1) No indication of formation fluids

influx before starting to pull the drill

pipe from the hole;

(2) The weight of returning drilling

fluid is within 0.2 pounds per gallon

(1.5 pounds per cubic foot) of the

drilling fluid entering the hole; and

(3) Other drilling fluid properties are

within the limits established by the

program approved in the APD.

(b) Record each time you circulate

drilling fluid in the hole in the driller’s

report;

(c) When coming out of the hole with

drill pipe, you must fill the annulus

with drilling fluid before the hydrostatic

pressure decreases by 75 psi, or every

five stands of drill pipe, whichever

gives a lower decrease in hydrostatic

pressure. You must calculate the

number of stands of drill pipe and drill

collars that you may pull before you

must fill the hole. You must also

calculate the equivalent drilling fluid

volume needed to fill the hole. Both sets

of numbers must be posted near the

driller’s station. You must use a

mechanical, volumetric, or electronic

device to measure the drilling fluid

required to fill the hole;

(d) You must run and pull drill pipe

and downhole tools at controlled rates

so you do not swab or surge the well;

(e) When there is an indication of

swabbing or influx of formation fluids,

you must take appropriate measures to

control the well. You must circulate and

condition the well, on or near-bottom,

unless well or drilling-fluid conditions

prevent running the drill pipe back to

the bottom;

(f) You must calculate and post near

the driller’s console the maximum

pressures that you may safely contain

under a shut-in BOP for each casing

string. The pressures posted must

consider the surface pressure at which

the formation at the shoe would break

down, the rated working pressure of the

BOP stack, and 70 percent of casing

burst (or casing test as approved by the

District Supervisor). As a minimum, you

must post the following two pressures:

(1) The surface pressure at which the

shoe would break down. This

calculation must consider the current

drilling fluid weight in the hole; and

(2) The lesser of the BOP’s rated

working pressure or 70 percent of

casing-burst pressure (or casing test

otherwise approved by the District

Supervisor);

(g) You must install an operable

drilling fluid-gas separator and degasser

before you begin drilling operations.

You must maintain this equipment

throughout the drilling of the well;

(h) Before pulling drill-stem test tools

from the hole, you must circulate or

reverse-circulate the test fluids in the

hole. If circulating out test fluids is not

feasible, you may bullhead test fluids

out of the drill-stem test string and tools

with an appropriate kill weight fluid;

and

(i) In areas where permafrost and/or

hydrate zones are present or may be

present, you must control drilling fluid

temperatures to drill safely through

those zones.

§ 250.457 What equipment must I have to

test and monitor drilling fluids?

(a) You must have and maintain

drilling fluid-testing equipment on the

drilling rig at all times. You must test

the drilling fluid at least once each tour,

or more frequently if conditions

warrant. You must perform the tests

according to industry-accepted

practices. Tests must include density,

viscosity, and gel strength; hydrogenion

38472 Federal Register / Vol. 65, No. 120 / Wednesday, June 21, 2000 / Proposed Rules

concentration; filtration; and any other

tests the District Supervisor requires.

You must record the results of these

tests in the drilling fluid report.

(b) Once you establish drilling fluid

returns, you must install and maintain

the following drilling fluid-system

monitoring equipment throughout

subsequent drilling operations. This

equipment must have the following

indicators on the rig floor:

(1) Pit level indicator to determine

drilling fluid-pit volume gains and

losses. This indicator must include both

a visual and an audible warning device;

(2) Volume measuring device to

accurately determine drilling fluid

volumes required to fill the hole on

trips;

(3) Return indicator devices that

indicate the relationship between

drilling fluid-return flow rate and pump

discharge rate. This indicator must

include both a visual and an audible

warning device; and

(4) Gas-detecting equipment to

monitor the drilling fluid returns. The

indicator may be located in the drilling

fluid-logging compartment or on the rig

floor. If the indicators are only in the

logging compartment, you must

continually man the equipment and

have a means of immediate

communication with the rig floor. If the

indicators are on the rig floor only, you

must install an audible alarm.

§ 250.458 What quantities of drilling fluids

are required?

(a) You must use, maintain, and

replenish quantities of drilling fluid and

drilling fluid materials at the drill site

as necessary to ensure well control. You

must determine those quantities based

on known or anticipated drilling

conditions, rig storage capacity, weather

conditions, and estimated time for

delivery.

(b) You must record the daily

inventories of drilling fluid and drilling

fluid materials, including weight

materials and additives in the drilling

fluid report.

(c) If you do not have sufficient

quantities of drilling fluid and drilling

fluid material to maintain well control,

you must suspend drilling operations.

§ 250.459 What are the safety

requirements for drilling fluid-handling

areas?

You must classify drilling fluidhandling areas according to API RP 500,

Recommended Practice for

Classification of Locations for Electrical

Installations at Petroleum Facilities. In

areas where dangerous concentrations of

combustible gas may accumulate, you

must install and maintain a ventilation

system and gas monitors. Drilling fluidhandling areas must have the following

safety equipment:

(a) A ventilation system capable of

replacing the air once every 5 minutes

or 1.0 cubic feet of air-volume flow per

minute, per square foot of area,

whichever is greater.

In addition:

(1) If natural means provide adequate

ventilation, then a mechanical

ventilation system is not necessary;

(2) If a mechanical system does not

run continuously, then it must activate

when gas detectors indicate the

presence of 1 percent or more of

combustible gas by volume; and

(3) If discharges from a mechanical

system may be hazardous, then you

must maintain the drilling fluidhandling area at a negative pressure.

You must protect the negative pressure

area by using at least one of the

following: a pressure-sensitive alarm,

open-door alarms on each access to the

area, automatic door-closing devices, air

locks, or other devices approved by the

District Supervisor;

(b) Gas detectors and alarms except in

open areas where adequate ventilation

is provided by natural means. You must

test and recalibrate gas detectors

quarterly. No more than 90 days may

elapse between tests;

(c) Explosion-proof or pressurized

electrical equipment to prevent the

ignition of explosive gases. Where you

use air for pressuring equipment, you

must locate the air intake outside of and

as far as practicable from hazardous

areas; and

(d) Alarms that activate when the

mechanical ventilation system fails.

Other Drilling Requirements

§ 250.460 What are the requirements for

well testing?

(a) You must determine the presence,

quantity, quality, and reservoir

characteristics of oil, gas, sulphur, and

water in the formations penetrated by

logging, formation sampling, or well

testing.

(b) If you intend to conduct a well

test, you must include your projected

plans for well testing with your APD

(form MMS–123) or as a Sundry Notice

and Reports on Wells (form MMS–124).

Your plans must include at least the

following information:

(1) Estimated flowing and shut-in

tubing pressures;

(2) Estimated flow rates and

cumulative volumes;

(3) Time duration of flow, buildup,

and drawdown periods;

(4) Description and rating of surface

and subsurface test equipment;

(5) Schematic drawing, showing the

layout of test equipment;

(6) Description of safety equipment,

including gas detectors and fire-fighting

equipment;

(7) Proposed methods to handle or

transport produced fluids; and

(8) Description of the test procedures.

(c) You must give the District

Supervisor at least 24-hours notice

before starting a well test.

§ 250.461 What are the requirements for

directional and inclination surveys?

For this subpart, MMS classifies a

well as vertical if the calculated average

of inclination readings does not exceed

3 degrees from the vertical.

(a) Survey requirements for a vertical

well: (1) You must conduct inclination

surveys on each vertical well and

digitally record the results. Survey

intervals may not exceed 1,000 feet

during the normal course of drilling;

(2) You must also conduct a

directional survey that provides both

inclination and azimuth:

(i) Within 500 feet of setting surface

or intermediate casing;

(ii) Within 500 feet of setting any

liner; and

(iii) When you reach total depth.

(b) Survey requirements for

directional well: You must conduct

directional surveys on each directional

well and digitally record the results.

Surveys must give both inclination and

azimuth at intervals not to exceed 500

feet during the normal course of

drilling. Intervals during angle-changing

portions of the hole may not exceed 100

feet.

(c) Measurement while drilling. You

may use measurement-while-drilling

technology if it meets the requirements

of this section.

(d) Composite survey requirements:

(1) Your composite directional survey

must show the interval from the bottom

of the conductor casing to total depth.

In the absence of conductor casing, the

survey must show the interval from the

bottom of the drive or structural casing

to total depth; and

(2) You must correct all surveys to

Universal-Transverse-Mercator-Gridnorth or Lambert-Grid-north after

making the magnetic-to-true-north

correction. Surveys must show the

magnetic and grid corrections used and

include a listing of the directionally

computed inclinations and azimuths.

(e) If you drill within 500 feet of an

adjacent lease, the Regional Supervisor

may require you to furnish a copy of the

well’s directional survey to the affected

leaseholder.

Federal Register / Vol. 65, No. 120 / Wednesday, June 21, 2000 / Proposed Rules 38473

§ 250.462 What are the requirements for

well-control drills?

You must conduct a weekly wellcontrol drill with each drilling crew.

Your drill must familiarize the crew

with its roles and functions so that all

crew members can perform their duties

promptly and efficiently.

(a) Well-control drill plan. You must

prepare a well control drill plan that is

applicable for the well. Your plan must

outline the assignments for each crew

member and establish times to complete

each portion of the drill. You must post

a copy of the well control drill plan on

the rig floor or bulletin board.

(b) Timing of drills. You must conduct

each drill during a period of activity

that minimizes the risk to drilling

operations. The timing of your drills

must cover a range of different

operations, including drilling with a

diverter, on-bottom drilling, and

tripping.

(c) Recordkeeping requirements. For

each drill, you must record the

following in the driller’s report:

(1) The time to be ready to close the

diverter or BOP system; and

(2) The total time to complete the

entire drill.

(d) MMS ordered drill. An MMS

authorized representative may require

you to conduct a well control drill

during an MMS inspection. The MMS

representative will consult with you

before requiring the drill.

§ 250.463 Who establishes field drilling

rules?

(a) The District Supervisor may

establish field drilling rules different

from the requirements of this subpart

when geological and engineering

information shows that specific

operating requirements are appropriate.

You must comply with field drilling

rules and nonconflicting requirements

of this subpart. The District Supervisor

may amend or cancel field drilling rules

at any time.

(b) You may request the District

Supervisor to establish, amend, or

cancel field drilling rules.

Sundry Notices and Well Records

§ 250.465 When must I submit sundry

notices to MMS?

(a) You must submit sundry notices

(form MMS–124) and other materials to

the Regional Supervisor as shown in the

following table. You must also submit a

public information copy of each form.

If you . . . then you must . . . and . . .

(1) Intend to revise plans, change

major drilling equipment, deepen,

plug-back, or sidetrack a well.

submit form MMS–124 or request

oral approval.

receive written or oral approval from the District Supervisor before

you begin the intended operation. If you get an oral approval, you

must submit form MMS–124 within 72 hours. In all cases, you

must meet the additional requirements in paragraph (b) of this section.

(2) Sidetrack .................................... submit a form MMS–124 ............... include the reason for the sidetrack, kickoff point, and applicable information as required for an APD (§§ 250.411 through 250.418)

(3) Determine that a well’s final surface location, water depth, or the

rotary kelly bushing elevation is

different than permitted.

immediately submit a form MMS–

124.

submit a plat that meets the requirements of § 250.412

(4) Move a drilling unit from a

wellbore before completing a well.

submit forms MMS–124 and

MMS–125 (Well Summary Report) within 30 days after the

suspension of wellbore operations.

submit appropriate copies of the well records.

(b) If you intend to perform any of the

actions specified in paragraph (a)(1) of

this section, you must meet the

following additional requirements:

(1) Your form MMS–124 must contain

a detailed statement of the proposed

work that will materially change from

the approved APD;

(2) Your form MMS–124 must include

the present status of the well, depth of

all casing strings set to date, well depth,

present production zones and

productive capability, and all other

information specified; and

(3) Within 30 days after completing

this work, you must submit form MMS–

124 with detailed information about the

work to the District Supervisor unless

you have already provided sufficient

information in a weekly Activity Report,

form MMS–133 (§ 250.467(c)).

§ 250.466 What well records must I keep?

You must keep complete, legible, and

accurate records for each well. You

must keep these records at your field

office nearest the OCS facility or at

another location conveniently available

to the District Supervisor. The records

must contain complete information on

all of the following:

(a) Well operations;

(b) Descriptions of formations

penetrated;

(c) Content and character of oil, gas,

water, and other mineral deposits in

each formation;

(d) Kind, weight, size, grade, and

setting depth of casing;

(e) All well logs and surveys run in

the wellbore;

(f) Any significant malfunction or

problem; and

(g) All other information required by

the District Supervisor.

§ 250.467 What well records may I be

required to submit?

The Regional or District Supervisor

may require you to submit copies of all

the well records listed in this section.

(a) Well operations as specified in

§ 250.466.

(b) Paleontological interpretations or

reports identifying microscopic fossils

by depth and/or washed samples of drill

cuttings that you normally maintain for

paleontological determinations. The

Regional Supervisor may issue a Notice

to Lessees that prescribes the manner

and format for this information.

(c) Daily drilling reports. For drilling

operations in the GOMR, you must

provide this information on a weekly

basis using form MMS–133, weekly

Activity Report.

(d) Service company reports on

cementing, perforating, acidizing,

testing, or other similar services.

(e) Other reports and records of

operations.

§ 250.468 How long must I keep drillingrelated records?

You must keep records for the time

periods shown in the following table.

38474 Federal Register / Vol. 65, No. 120 / Wednesday, June 21, 2000 / Proposed Rules

You must keep records relating to . . . until . . .

(a) Drilling .................................................................................................. 90 days after you complete drilling operations

(b) Casing and liner pressure tests, diverter tests, and BOP tests .......... 2 years after the completion of drilling operations

(c) Completion of a well or of any workover activity that materially alters

the completion configuration or affects a hydrocarbon-bearing zone.

you permanently plug and abandon the well or until you forward the

records with a lease assignment.

§ 250.469 Must I submit copies of well

logs?

You must submit copies (field or final

prints of individual runs) of logs or

charts of electrical, radioactive, sonic,

and other well-logging operations;

directional-and vertical-well surveys;

velocity profiles and surveys, and

analysis of cores to MMS. Each Region

will provide specific instructions for

submitting well logs and surveys.

* * * * *

4. In § 250.515, paragraph (b) is

revised to read as follows:

§ 250.515 Blowout prevention equipment.

* * * * *

(b) The minimum BOP system for

well-completion operations must meet

the appropriate standards from the

following table:

When . . . the minimum BOP stack must include . . .

(1) The expected pressure is less than 5,000 psi ................................... three preventers consisting of: an annular, one set of pipe rams, and

one set of blind or blind-shear rams.

(2) The expected pressure is 5,000 psi or greater or you use multiple

tubing strings.

four preventers consisting of: an annular, two sets of pipe rams, and

one set of blind or blind-shear rams.

(3) You handle multiple tubing strings simultaneously ............................ four preventers consisting of: an annular, one set of pipe rams, one set

of dual pipe rams, and one set of blind or blind-shear rams.

(4) You use a tapered drill string ............................................................. at least one set of pipe rams that are capable of sealing around each

size of drill string. If the expected pressure is greater than 5,000 psi,

then you must have at least two sets of pipe rams that are capable

of sealing around the larger size drill string. You may substitute one

set of variable bore rams for two sets of pipe rams.

(5) It is one year from the final rule effective date ................................... at least one set of blind-shear rams.

* * * * *

5. In § 250.615, paragraph (b) is

revised to read as follows:

§ 250.615 Blowout prevention equipment.

* * * * *

(b) The minimum BOP system for

well-workover operations with the tree

removed must meet the appropriate

standards from the following table:

When . . . the minimum BOP stack must include . . .

(1) The expected pressure is less than 5,000 psi ................................... three preventers consisting of: an annular, one set of pipe rams, and

one set of blind or blind-shear rams.

(2) The expected pressure is 5,000 psi or greater or you use multiple

tubing strings.

four preventers consisting of: an annular, two sets of pipe rams, and

one set of blind or blind-shear rams.

(3) You handle multiple tubing strings simultaneously ............................ four preventers consisting of: an annular, one set of pipe rams, one set

of dual pipe rams, and one set of blind or blind-shear rams.

(4) You use a tapered drill string ............................................................. at least one set of pipe rams that are capable of sealing around each

size of drill string. If the expected pressure is greater than 5,000 psi,

then you must have at least two sets of pipe rams that are capable

of sealing around the larger size drill string. You may substitute one

set of variable bore rams for two sets of pipe rams.

(5) It is one year from the final rule effective date ................................... at least one set of blind-shear rams.

Hydrogen Sulfide

* * * * *

[FR Doc. 00–15546 Filed 6–20–00; 8:45 am]

BILLING CODE 4310–MR–P

DEPARTMENT OF TRANSPORTATION

Coast Guard

33 CFR Part 166

[CGD08–00–012]

RIN 2115–AA98

Anchorage Regulation; Sabine Pass,

TX, Gulf of Mexico

AGENCY: Coast Guard, DOT.

ACTION: Notice of proposed rulemaking.

SUMMARY: The Coast Guard proposes to

create a new anchorage area on the

eastern side of the Sabine Pass Safety

Fairway, opposite the Sabine Bank

Offshore (North) Anchorage area in the

Gulf of Mexico south of Sabine Pass.

This will help alleviate the need for inbound deep draft vessels to cross the

Sabine Pass Safety Fairway and navigate

around a charted shallow area just to the

southeast of the North anchorage. This

proposal will allow deep draft vessels to

enter and depart Sabine Bank

anchorages on a safer, lower risk course.

DATES: Comments and related material

must reach the Coast Guard on or before

August 21, 2000.

ADDRESSES: You may mail comments

and related material to Commanding

Officer, U.S. Coast Guard Marine Safety