[Federal Register Volume 62, Number 135 (Tuesday, July 15, 1997)]
[Proposed Rules]
[Pages 37819-37824]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 97-18546]


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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

[[Page 37820]]

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