[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
