Blowout Preventer (BOP) Testing Requirements for Drilling and Completion Operations

DEPARTMENT OF THE INTERIOR

Minerals Management Service

30 CFR Part 250

RIN 1010-AC37

Blowout Preventer (BOP) Testing Requirements for Drilling and

Completion Operations

AGENCY: Minerals Management Service (MMS), Interior.

ACTION: Proposed rule.

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SUMMARY: MMS proposes to revise the testing requirements in its

regulations for blowout preventer (BOP) systems used in drilling and

completion operations. The revision would allow a lessee up to 14 days

between BOP pressure tests. MMS bases this revision on the results of a

recently completed study of BOP performance. This study concluded that

no statistical difference exists in failure rates for BOP's tested

between 0 and 7 day intervals and between 8- and 14-day intervals. MMS

estimates that the revised testing timeframe could save industry $35 to

$46 million a year without compromising safety.

DATES: MMS will consider all comments we receive by September 15, 1997.

We will begin reviewing comments then and may not fully consider

comments we receive after September 15, 1997.

ADDRESSES: Mail or hand-carry written comments to the Department of the

Interior; Minerals Management Service; Mail Stop 4700; 381 Elden

Street; Herndon, Virginia 20170-4817; Attention: Rules Processing Team.

FOR FURTHER INFORMATION CONTACT: Bill Hauser, Engineering and Research

Division, (703) 787-1613.

SUPPLEMENTARY INFORMATION:

I. Background

In 1992, the offshore oil and gas industry asked MMS to revise its

requirements for testing BOP systems and equipment. Specifically,

industry requested an extension of the minimum testing frequency for

BOP's and associated equipment to 14 days. Current regulations require

lessees to test BOP systems at least once a week, but not to exceed 7

days between tests. After reviewing the information and data submitted

by industry, MMS allowed lessees and operators to test BOP systems on a

14-day interval on a case-by-case basis. In addition, MMS decided that

we must examine BOP performance on the OCS before revising the

regulations.

MMS conducted two reviews of BOP performance. The initial review

examined BOP test results collected during inspections of drilling

activities in mid-1993. MMS inspectors reviewed BOP test charts and

noted equipment failures. This review showed higher failure rates than

those cited by industry. However, MMS decided this review did not

accurately assess BOP performance and that a more comprehensive study

was necessary.

The second review examined BOP test data from wells drilled during

1994. MMS collected this data from wells drilled between January and

October 1994. Lessees submitted copies of BOP test data after drilling

each well. Test data included BOP test charts, reports, and

observations about problems during the tests. Results of this study

also showed higher failure rates than those cited by industry. After

discussing the results of the second review with industry, MMS decided

another study of BOP performance was necessary. This study would have

industry involvement

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from the beginning and must provide sufficient information to make

regulatory decisions.

Industry and MMS formed a technical assessment group to set the

parameters for this performance study. This group would also select the

contractor, provide funding, and monitor progress of the study. The

following organizations participated in this group:

American Petroleum Institute

Independent Petroleum Association of America

International Association of Drilling Contractors

National Ocean Industries Association

Offshore Operators Committee

The group hired Tetrahedron Incorporated on February 13, 1996, to

conduct the study. After discussing data and study requirements with

the group, Tetrahedron began collecting data and analyzing BOP

performance data in April 1996. Tetrahedron completed the study in

December 1996 and presented its findings at MMS' BOP workshop on

January 15, 1997. The study found that no statistical difference in

failure rates existed between BOP systems tested on a 0- to 7-day

interval and those tested between an 8- to 14-day interval.

MMS determined that the study showed that BOP performance during a

longer test interval statistically equaled the performance under the

current requirement. Thus, this performance satisfied the criteria

(described in 30 CFR 250.3, Performance requirements) for allowing the

use of alternative procedures to those prescribed in the regulations.

Based on this finding, MMS issued a Notice to Lessees and Operators

(NTL) on January 31, 1997, informing lessees that they could begin

testing BOP systems on intervals up to 14 days. The new timeframe

applied to drilling, sidetrack, and completion activities.

II. Discussion of Proposed Rule

14-Day BOP Testing Timeframe

The major revision proposed by this rule allows a lessee up to 14

days between BOP pressure tests versus the weekly tests required by the

current regulations. These proposed changes are contained in

Secs. 250.57(a)(3) and 250.86(a)(2). This revision applies only to

drilling and completion operations. It does not apply to BOP testing

during workover activities because MMS did not address workover rigs in

the BOP performance study. MMS has determined that this new testing

timeframe will continue to provide the same level of BOP performance

and will not compromise the safety of drilling operations. As noted

above, MMS has already informed lessees via NTL of this revision.

One of the major advantages of the new 14-day testing timeframe is

improved drilling efficiency. Lessees can better plan the timing of BOP

tests to coincide with drilling operations. Under the 7-day testing

requirements, lessees often requested and received approval from

District Supervisors to test 2 or more days beyond the weekly test to

accommodate routine drilling operations. These operations included

dulling a bit, drilling to a casing point or total depth, and well

logging. Now lessees will have more time to fit BOP tests into the

overall drilling and completion activities.

MMS policy will be to deny any requests to extend testing beyond

the 14-day testing timeframe. The only exception to this policy will be

if a lessee has well control problems and cannot safely test the system

within the 14-day timeframe. The lessee must test the BOP system as

soon as possible after resolving the problem and before resuming normal

operations.

The proposed rule requires a lessee to begin testing the BOP system

prior to 12 p.m. (midnight) on the 14th day following the conclusion of

the previous test. This wording clearly tells lessees when they must

begin testing.

Test Pressures

The proposed rule continues to require a lessee to test BOP

components at their rated working pressures (70 percent for an annular

preventer) or as otherwise approved by the District Supervisor.

However, MMS is considering the use of maximum anticipated surface

pressure (MASP) in determining appropriate BOP test pressures. For many

wells, MMS has approved the use of MASP as the basis for determining

test pressures through an application for permit to drill (APD).

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 by MMS drilling engineers.

If the two calculations compare favorably, then 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.

A rule change to use MASP as the basis for setting test pressures

may be more consistent with current industry practice than requiring

testing at the rated working pressures. However, our main concern with

using MASP is the many different methods used by operators to calculate

anticipated surface pressures. If we use MASP as the basis for

determining test pressures, the final rule will need to include

appropriate guidelines. MMS requests comments on using MASP for

establishing required BOP-test pressures and we may include the MASP

requirements in the final rule if the comments support that approval.

Comments should include methodologies and criteria for calculating an

acceptable MASP.

Duration of a BOP Pressure Test

The proposed rule requires that each test must hold the required

pressure for 5 minutes. This is a new provision, but MMS has used 5

minutes as the standard for holding the required pressure for many

years. However, the rule allows a lessee to conduct a 3-minute test on

surface BOP systems and surface equipment for a subsea system if the

test is recorded on the outer most half of a 4-hour chart, on a 1-hour

chart, or on a digital recorder. MMS will accept a 3-minute test on the

outer half of the 4-hour chart or on a 1-hour chart because the length

of the line on these charts is sufficient to determine if the tested

component(s) held the required pressure. A 3-minute test using a

digital recorder provides sufficient information to determine if the

tested component held the required pressure. A 5-minute test is

required for subsea BOP equipment because of the larger volume of fluid

in the system. This use of a 3-minute test reflects the policy

discussed in a Letter to Lessees issued by the Gulf of Mexico Region on

January 14, 1994. These revisions apply to both drilling and completion

operations (Secs. 250.57 and 250.86).

BOP Testing at Casing and Liner Points

The proposed rule requires the lessee to test the BOP system before

drilling out each string of casing or a liner. This is similar to the

current requirement to test the system before drilling out each string.

However, with the advancement of drilling technology and new procedures

for installing casing strings, MMS agrees with industry comments that

it is not necessary to test the BOP system at all casing or liner

points.

MMS has identified one situation where a District Supervisor will

likely allow a lessee to not test before drilling out the string. This

situation occurs when the lessee does not remove the BOP stack to run

the string 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. Since there would be no

[[Page 37821]]

connections to test and test pressures do not increase, the test would

not be necessary. To skip testing in these situations, the lessee must

clearly indicate in its APD which casing strings and liners meet these

criteria. Test pressures less than the equipment's rated working

pressure must be approved by the District Supervisor (see discussion on

test pressures above).

The lessee must continue to test the BOP system before 14 days have

elapsed from the previous test. If a lessee runs casing or liner near

the end of the 14-day interval, MMS recommends that the lessee test the

BOP system at that time.

Weekly Actuation of Annular and Rams. The proposed rule requires a

lessee to actuate the annular and rams preventers at least once each

week. Weekly actuation will ensure that the preventers will function if

needed. It takes minimal time to conduct this simple test. This

requirement was unnecessary before because a lessee had to pressure

test the entire system on a weekly basis. This revision applies to both

drilling and completion operations (Secs. 250.57 and 250.86).

Format of the Proposed Rule. We have written this proposed rule in

a ``plain English'' format. We have tried to lay out these requirements

in a straightforward and uncomplicated manner. The plain English format

uses the term ``you'' which means that the lessee, or the approved

designated party, is responsible for ensuring that all requirements are

met. We encourage your comments on our use of the plain English format

in this proposed rule as well as future rulemaking.

III. Procedural Matters

Executive Order (E.O.) 12866

This rule is not a significant rule under Executive Order 12866 and

does not require Office of Management and Budget review. MMS estimates

that this proposed rule will save the oil and gas industry $34.5 to $46

million per year. The savings result from having to conduct fewer BOP

tests and increased drilling efficiency. Direct economic effects are

reduced drilling costs for each well drilled on the OCS. The rule does

not add any new costs to industry, and it will not reduce the level of

safety to personnel or the environment. Since the rule will have an

annual effect on the economy of less than $100 million, the rule does

not have a significant economic effect as defined by Executive Order

12866.

The proposed rule will not affect the level of drilling activity on

the OCS. It will reduce the number of BOP tests conducted, which should

result in reduced drilling time for each well. Once the lessee

completes a well, the rig will move on to the next well. This will not

have any adverse effects on employment, investment, productivity,

innovation, or on the ability of U.S.-based enterprises to compete with

foreign-based enterprises in other markets because the economic effects

are minor. The rule will have no effect on competition. Therefore, in

accordance with Executive Order (E.O.) 12866, a review by the Office of

Management and Budget (OMB) is not necessary.

Regulatory Flexibility Act

This proposed rule will not have any significant effects on a

substantial number of small entities. The rule will not have a

significant economic effect on any entities, small or large. This rule

will affect only two groups that operate on the OCS: (1) Lessees that

contract drilling operations and (2) drilling contractors. A lessee

that qualifies as a small entity could see a minor economic benefit

from this rule. The average annual cost savings per rig is from

$240,000 to $340,000, spread among all lessees that drill wells.

However, the savings would probably be offset by increased costs to

contract a drilling rig. While the savings to lessees could represent

lost income to contractors, the proposed rule should not have a

significant economic effect on these businesses. Rig utilization rates

are very high, leading to increased day rates for drilling rigs;

therefore, the contractors are not expected to have declining income as

a result of this proposed rule.

In general, entities that engage in offshore activities are not

small due to technical and financial resources and experience needed to

safely conduct such operations. Small entities are more likely to

operate onshore or in State waters--areas not covered by this rule.

When small entities do work in the OCS, they are likely to be

contractors and not owner/operators of OCS platforms or drilling rigs.

Paperwork Reduction Act

This proposed rule contains collections of information which MMS

has submitted to OMB for review and approval under section 3507(d) of

the Paperwork Reduction Act of 1995. As part of our continuing effort

to reduce paperwork and respondent burdens, MMS invites the public and

other Federal agencies to comment on any aspect of the reporting

burden. Submit your comments to the Office of Information and

Regulatory Affairs; OMB; Attention: Desk Officer for the Department of

the Interior (OMB control numbers 1010-0053 or 1010-0067); Washington,

D.C. 20503. Send a copy of your comments to the Rules Processing Team;

Mail Stop 4020; Minerals Management Service; 381 Elden Street; Herndon,

Virginia 20170-4817. You may obtain a copy of the supporting statements

for the collections of information by contacting the Bureau's

Information Collection Clearance Officer at (202) 208-7744.

The Paperwork Reduction Act of 1995 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 within 30 days of publication. This does

not affect the deadline for the public to comment to the Department on

the proposed regulations.

The titles of the collections of information affected by this

proposed rule are ``30 CFR 250, Subpart D, Oil and Gas Drilling

Operations'' (OMB Control Number 1010-0053) and ``30 CFR 250 Subpart E,

Oil and Gas Well-Completion Operations'' (OMB Control Number 1010-

0067).

The collections of information in these subparts consist of

reporting and recordkeeping requirements on the conditions of a

drilling site and well-completion operations in the OCS. MMS uses the

information to determine if lessees are properly providing for safe

operations and protection of human life or health and the environment.

The proposed rule does not actually revise any of the information

collection requirements in the current regulation. However, it will

reduce the recordkeeping burden by reducing the number of BOP tests

that a lessee must conduct. Respondents are approximately 130 Federal

OCS oil and gas or sulphur lessees. The frequency of response is on

occasion and varies by section in the subparts. The requirement to

respond is mandatory.

MMS estimates the total annual burden for subpart D (OMB control

number 1010-0053) is 108,581 hours. This reflects a decrease of 12,499

recordkeeping hours as a result of the proposed rule. The total annual

burden estimated for subpart E (OMB control number 1010-0067) is 4,841

hours. In developing the estimate for subpart E, MMS had to revise the

method of calculating some of the burden

[[Page 37822]]

requirements. Although the proposed rule will result in a decrease of

2,563 recordkeeping hours, it is offset by the revised calculations.

In calculating the burdens, MMS assumed that respondents perform

some of the requirements and maintain some of the records in the normal

course of their activities. MMS considers these to be usual and

customary and did not include them in the burden estimates. If

commenters disagree with this assumption, they should provide more

appropriate burden hours and costs.

MMS will summarize written responses to this notice and address

them in the final rule. All comments will become a matter of public

record.

1. MMS specifically solicits comments on the following questions:

(a) Is the proposed collection of information necessary for the

proper performance of MMS's 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 through the use of appropriate

automated electronic, mechanical, or other forms of information

technology?

2. In addition, the Paperwork Reduction Act of 1995 requires

agencies to estimate the total annual cost burden to respondents or

recordkeepers resulting from the collection of information. MMS needs

your comments on this item. 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 startup

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: before

October 1, 1995; to comply with requirements not associated with the

information collection; for reasons other than to provide information

or keep records for the Government; or as part of customary and usual

business or private practices.

Takings Implication Assessment

DOI certifies that the proposed rule does not represent a

governmental action capable of interference with constitutionally

protected property rights. Thus, a Takings Implication Assessment need

not be prepared pursuant to E.O. 12630, Governmental Actions and

Interference with Constitutionally Protected Property Rights.

Unfunded Mandates Reform Act of 1995

DOI has determined and certifies according to the Unfunded Mandates

Reform Act, 2 U.S.C. 1502 et seq., that this rule will not impose a

cost of $100 million or more in any given year on State, local, and

tribal governments, or the private sector.

E.O. 12988

DOI has certified to OMB that the rule meets the applicable reform

standards provided in sections 3(a) and 3(b)(2) of E.O. 12988, ``Civil

Justice Reform.''

National Environmental Policy Act

DOI has also determined that this action does not constitute a

major Federal action affecting the quality of the human environment;

therefore, an Environmental Impact Statement is not required.

List of Subjects in 30 CFR Part 250

Continental shelf, Environmental impact statements, Environmental

protection, Government contracts, Incorporation by reference,

Investigations, Mineral royalties, Oil and gas development and

production, Oil and gas exploration, Oil and gas reserves, Penalties,

Pipelines, Public lands--mineral resources, Public lands--rights-of-

way, Reporting and recordkeeping requirements, Sulphur development and

production, Sulphur exploration, Surety bonds.

Dated: July 2, 1997.

Bob Armstrong,

Assistant Secretary, Land and Minerals Management.

For the reasons stated in the preamble, 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: U.S.C. 1334.

2. Section 250.57 is revised to read as follows:

Sec. 250.57 Blowout preventer (BOP) system tests, inspections, and

maintenance.

(a) BOP pressure testing timeframes. You must pressure test your

BOP system:

(1) When installed;

(2) Before 14 days have elapsed since your last BOP pressure test.

You must begin to test your BOP system before 12 p.m. (midnight) on the

14th day following the conclusion of the previous test. However, the

District Supervisor may require testing every 7 days if conditions or

BOP performance warrant; and

(3) Before drilling out each string of casing or a liner.

(b) BOP test pressures. When you test the BOP system, you must

conduct a low pressure and a high pressure test for each BOP component.

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:

(1) 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.

You must conduct the low pressure test before the high pressure test.

(2) For ram-type BOP's, choke manifold, and other BOP equipment,

the high pressure test must equal the rated working pressure of the

equipment or the pressure otherwise approved by the District

Supervisor; and

(3) For annular-type BOP's, the high pressure test must equal 70

percent of the rated working pressure of the equipment or the pressure

otherwise approved by the District Supervisor.

(c) Duration of pressure test. Each test must hold the required

pressure for 5 minutes.

(1) 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.

(2) If the equipment does not hold the required pressure during a

test, you must remedy the problem and retest the affected component(s).

(d) Additional BOP testing requirements. You must:

(1) Use water to test a surface BOP system;

[[Page 37823]]

(2) Stump test a subsurface BOP system before installation. You

must use water to stump test a subsea BOP system. You may use drilling

fluids to conduct subsequent tests of a subsea BOP system;

(3) Alternate tests between control stations and pods. If a control

station or pod is not functional, you must suspend further drilling

operations until that station or pod is operable;

(4) Pressure test the blind or blind-shear ram during a stump test

and at all casing points. In addition, you must test the blind or

blind-shear ram at least once every 30 days;

(5) Function test annulars and rams every 7 days between pressure

tests;

(6) Pressure-test variable bore-pipe rams against all sizes of pipe

in use, excluding drill collars and bottom-hole tools;

(7) Test affected BOP components following the disconnection or

repair of any well-pressure containment seal in the wellhead or BOP

stack assembly;

(8) Actuate the casing safety valve before running casing; and

(9) Upon installation of casing rams, you must test the ram bonnet

before running casing.

(e) Postponing BOP tests. You may postpone a BOP test if you have

well-control problems such as lost circulation, formation fluid influx,

or stuck drill pipe. If this occurs, you must conduct the required BOP

test as soon as possible (i.e., first trip out of the hole) after the

problem has been remedied. You must record the reason for postponing

any test in the driller's report.

(f) BOP inspections. You must visually inspect your BOP system and

marine riser at least once each day if weather and sea conditions

permit. You may use television cameras to inspect this equipment. The

District Supervisor may approve alternate methods and frequencies to

inspect a marine riser. Casing risers on fixed structures and jackup

rigs are not subject to the daily underwater inspections.

(g) BOP maintenance. You must maintain your BOP system to ensure

that the equipment functions properly.

(h) BOP test records. 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:

(1) Record BOP test pressures on pressure charts;

(2) Have your onsite representative certify (sign and date) BOP

test charts and reports as correct;

(3) Document the sequential order of BOP and auxiliary equipment

testing and the pressure and duration of each test. You may reference a

BOP test plan if it is available at the facility;

(4) Identify the control station or pod used during the test;

(5) Identify any problems or irregularities observed during BOP

system testing and record actions taken to remedy the problems or

irregularities;

(6) Retain all records, including pressure charts, driller's

report, and referenced documents, pertaining to BOP tests, actuations,

and inspections at the facility for the duration of drilling; and

(7) After drilling is completed, you must retain all the records

listed in paragraph (h)(6) of this section for a period of two years at

the facility, at the lessee's field office nearest the Outer

Continental Shelf (OCS) facility, or at another location conveniently

available to the District Supervisor.

(i) Alternate methods. The District Supervisor may require, or

approve, more frequent testing, as well as different test pressures and

inspection methods, or other practices.

3. Section 250.86 is revised to read as follows:

Sec. 250.86 Blowout preventer system tests, inspections, and

maintenance.

(a) BOP pressure testing timeframes. You must pressure test your

BOP system:

(1) When installed; and

(2) Before 14 days have elapsed since your last BOP pressure test.

You must begin to test your BOP system before 12 p.m. (midnight) on the

14th day following the conclusion of the previous test. However, the

District Supervisor may require testing every 7 days if conditions or

BOP performance warrant.

(b) BOP test pressures. When you test the BOP system, you must

conduct a low pressure and a high pressure test for each BOP component.

Each individual pressure test must hold pressure long enough to

demonstrate that the tested component(s) holds the required pressure.

The District Supervisor may approve or require other test pressures or

practices. Required test pressures are as follows:

(1) 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.

You must conduct the low pressure test before the high pressure test.

(2) For ram-type BOP's, choke manifold, and other BOP equipment,

the high pressure test must equal the rated working pressure of the

equipment.

(3) For annular-type BOP's, the high pressure test must equal 70

percent of the rated working pressure of the equipment.

(c) Duration of pressure test. Each test must hold the required

pressure for 5 minutes.

(1) 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.

(2) If the equipment does not hold the required pressure during a

test, you must remedy the problem and retest the affected component(s).

(d) Additional BOP testing requirements. You must:

(1) Use water to test the surface BOP system;

(2) Stump test a subsurface BOP system before installation. You

must use water to stump test a subsea BOP system. You may use drilling

or completion fluids to conduct subsequent tests of a subsea BOP

system;

(3) Alternate tests between control stations and pods. If a control

station or pod is not functional, you must suspend further completion

operations until that station or pod is operable;

(4) Pressure test the blind or blind-shear ram at least every 30

days;

(5) Function test annulars and rams every 7 days;

(6) Pressure-test variable bore-pipe rams against all sizes of pipe

in use, excluding drill collars and bottom-hole tools; and

(7) Test affected BOP components following the disconnection or

repair of any well-pressure containment seal in the wellhead or BOP

stack assembly;

(e) Postponing BOP tests. You may postpone a BOP test if you have

well-control problems. You must conduct the required BOP test as soon

as possible (i.e., first trip out of the hole) after the problem has

been remedied. You must record the reason for postponing any test in

the driller's report.

(f) Weekly crew drills. You must conduct a weekly drill to

familiarize all personnel engaged in well-completion operations with

appropriate safety measures.

(g) BOP inspections. You must visually inspect your BOP system and

marine riser at least once each day if weather and sea conditions

permit. You may use television cameras to inspect this equipment. The

District Supervisor may approve alternate methods and frequencies to

inspect a marine riser.

[[Page 37824]]

(h) BOP maintenance. You must maintain your BOP system to ensure

that the equipment functions properly.

(i) BOP test records. You must record the time, date, and results

of all pressure tests, actuations, crew drills, and inspections of the

BOP system, system components, and marine riser in the driller's

report. In addition, you must:

(1) Record BOP test pressures on pressure charts;

(2) Have your onsite representative certify (sign and date) BOP

test charts and reports as correct;

(3) Document the sequential order of BOP and auxiliary equipment

testing and the pressure and duration of each test. You may reference a

BOP test plan if it is available at the facility;

(4) Identify the control station or pod used during the test;

(5) Identify any problems or irregularities observed during BOP

system and equipment testing and record actions taken to remedy the

problems or irregularities;

(6) Retain all records including pressure charts, driller's report,

and referenced documents pertaining to BOP tests, actuations, and

inspections at the facility for the duration of the completion

activity; and

(7) After completion of the well, you must retain all the records

listed in paragraph (i)(6) of this section for a period of two years at

the facility, at the lessee's field office nearest the OCS facility, or

at another location conveniently available to the District Supervisor.

(j) Alternate methods. The District Supervisor may require, or

approve, more frequent testing, as well as different test pressures and

inspection methods, or other practices.

[FR Doc. 97-18546 Filed 7-14-97; 8:45 am]

BILLING CODE 4310-MR-P