[Federal Register Volume 63, Number 104 (Monday, June 1, 1998)]
[Rules and Regulations]
[Pages 29604-29608]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 98-14294]
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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: Final rule.
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SUMMARY: This rule amends the regulations governing the testing
requirements for BOP systems used in drilling and completion operations
on the Outer Continental Shelf (OCS). The rule allows a lessee up to 14
days between BOP pressure tests. MMS based this rule on a study of BOP
performance which 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 14-day testing
requirement could save industry $35 to $46 million a year without
compromising safety.
EFFECTIVE DATE: The rule is effective on June 30, 1998.
FOR FURTHER INFORMATION CONTACT: Bill Hauser, Engineering and Research
Branch, at (703) 787-1613.
[[Page 29605]]
SUPPLEMENTARY INFORMATION: MMS proposed revising the regulations for
BOP testing in a notice of proposed rulemaking published in the Federal
Register (62 FR 37819) on July 15, 1997. We received five sets of
comments during the 60-day comment period, which closed on September
15, 1997. This final rule amends the regulations found at 30 CFR
250.407 and 250.516 and becomes effective on June 30, 1998. On that
date, MMS will rescind Notice to Lessees and Operators (NTL) 97-1N
because the new rule will be in effect. MMS issued NTL 97-1N on January
31, 1997, to inform lessees that they could begin testing BOP systems
on intervals up to 14 days.
Comments on the Rule
The five commenters consisted of four large oil companies and a
drilling contractor. All five commenters supported the proposed
revision to allow lessees up to 14 days between BOP pressures tests. In
addition, they commented on the following parts of the proposed rule:
testing frequency for workovers; testing of blind-shear rams; test
duration; and use of maximum anticipated surface pressure (MASP) for
determining BOP test pressures. Those comments and MMS'' responses are
discussed below.
BOP Testing Frequency During Workovers
Comment--One company stated that many workovers include completion
or re-completion operations and asked if the amended regulations apply
to the completion phase of a workover.
Response--The revised BOP testing requirements do not apply to the
completion phase of workover operations. According to the definition in
Sec. 250.601, workover operations mean the work conducted on wells
after the initial completion for the purpose of maintaining or
restoring the productivity of the well. After the initial completion,
you must test your BOP equipment according to the requirements of
subpart F, Oil and Gas Well-Workover Operations.
Comment--Another commenter asked MMS to consider similar changes in
testing frequency for workover operations after gathering necessary
data.
Response--MMS will consider similar changes to the regulations
after the completion of an appropriate study.
Testing of the Blind or Blind-Shear Ram
Comment--One commenter recommended that the requirement to test the
blind or blind-shear ram at least once every 30 days
(Sec. 250.407(d)(4)) should include an exclusion if the ram was tested
during a routine test.
Response--The intent of this requirement is to ensure that the
blind or blind-shear ram is tested at least once every 30 days. We
revised the second sentence in this paragraph to now read as follows:
``Additionally, the interval between any blind or blind-shear ram tests
may not exceed 30 days.'' The 30-day interval begins with any test.
Testing of a Casing Safety Valve
Comment--One commenter asked MMS to define what was meant by a
``casing safety valve.'' The commenter interpreted ``casing safety
valve'' as a valve installed on a casing swage to facilitate
circulation while running casing.
Response--We removed the term ``casing safety valve'' and have
revised the wording of the final rule to be closer to the current rule.
The new wording is ``You must actuate safety valves assembled with
proper casing connections prior to running casing.''
Weekly Crew Drills
Comment--One company commented that the new regulations required
weekly drills to familiarize personnel engaged in completion operations
but there was not a similar requirement for drilling personnel.
Response--MMS continues to require well-controls drills for each
drilling crew. The requirements for well-control drills during drilling
are found in Sec. 250.408. That section requires the lessee to conduct
a well-control drill for each drilling crew.
Test Duration
Comment--One company thought that MMS should require a 5-minute
test for large blowout preventers because of the larger fluid volumes
needed for testing and leak detection.
Response--MMS requires a 5-minute test for subsea BOP equipment
because of the larger volume of fluid in the system. MMS believes that
a 3-minute test is appropriate for surface blowout preventer equipment
provided the lessee measures the test pressures on the outermost half
of a 4-hour chart, on a 1-hour chart, or on a digital recorder.
Use of MASP in Determining Test Pressures
Comment--Three companies commented on the use of MASP for
determining test pressures for BOP equipment. One recommended using
MASP because it was more consistent with current industry practices and
would reduce undue stress, wear, and tear on BOP components. The
company recommended using a conservative method of determining MASP.
Another company recommended that MMS not use MASP for determining the
required BOP test pressure due to the variety of methods used by
operators to calculate MASP. The third company did not feel that
changing the test pressures to MASP will improve the reliability of BOP
equipment if the common definition of MASP is used. However that
company said that testing to the rated working pressure can be
excessive and that test pressures should be related to the design of
the well.
Response--MMS believes that these comments show industry's interest
in using MASP in determining BOP test pressures. They also show that
MMS and industry must reach a common methodology for determining MASP.
Therefore, MMS has decided not to require the use of MASP for
establishing BOP test pressures in this rule. The rule continues to
require the lessee to test BOP components at their rated working
pressures (70 percent for an annular preventer) or as otherwise
approved by the District Supervisor.
As discussed in the preamble of the proposed rule, District
Supervisors base the approval of alternate test pressures on a
comparison of the anticipated surface pressure calculations submitted
with the application for permit to drill (APD) to MASP calculations
made by MMS drilling engineers. If the two calculations compare
favorably, the District Supervisor approves the requested test
pressures. If the calculations for anticipated surface pressure are
less than those calculated by MMS, the District Supervisor advises the
lessee of any necessary revisions to the APD.
We are currently rewriting the regulations for Subpart D, Oil and
Gas Drilling Operations, so we will continue to examine the use of MASP
in determining BOP test pressures. We plan to publish the Notice of
Proposed Rulemaking for subpart D by the end of the summer.
Testing at Casing and Liner Points
MMS acknowledged in the preamble to the proposed rule that there
was at least one situation where it may not be necessary to test the
BOP system. MMS has added two sentences to Sec. 250.407(a)(3) that
explain when a lessee will be allowed to omit a test of the BOP system
at some casing and liner points. This addition is intended to clearly
describe in the regulatory text the circumstance when MMS will allow a
lessee to not test the BOP system. That circumstance occurs when a
lessee doesn't remove the BOP stack to run
[[Page 29606]]
casing or a liner, and the required BOP-test pressures for the next
section of the hole are not greater than the test pressures for the
previous BOP test. The lessee must clearly indicate in its APD which
casing strings and liners meet these criteria.
Recently, MMS published a final rule redesignating 30 CFR part 250.
The new numbering is used here as follows: Sec. 250.406 replaces
Sec. 250.56; Sec. 250.407 replaces Sec. 250.57; Sec. 250.408 replaces
Sec. 250.58; Sec. 250.516 replaces Sec. 250.86; and Sec. 250.601
replaces Sec. 250.91.
Procedural Matters
Executive Order (E.O.) 12866
MMS estimates that this final rule will save the oil and gas
industry $34.5 to $46 million per year. These 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 is not a significant regulatory
action.
The 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 E. O. 12866, a review by the Office of Management and Budget (OMB)
is not necessary.
Regulatory Flexibility Act
This final rule will not have any significant effects on a
substantial number of small entities. This rule affects 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,
positive economic benefit due to the cost savings from conducting fewer
BOP tests. However, any savings would probably be offset by increased
costs to contract a drilling rig. Day rates for offshore drilling rigs
are increasing due to high rig utilization.
In general, entities that engage in offshore activities are not
small due to technical and financial resources and experience needed to
safely conduct these 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 service
contractors and not owner/operators of OCS platforms or drilling rigs.
Your comments are important. The Small Business and Agriculture
Regulatory Enforcement Ombudsman and 10 Regional Fairness Boards were
established to receive comments from small business about Federal
agency enforcement actions. The Ombudsman will annually evaluate the
enforcement activities and rate each agency's responsiveness to small
business. If you wish to comment on the enforcement actions of MMS,
call toll-free (888) 734-3247.
Paperwork Reduction Act (PRA) of 1995
As part of the Notice of Proposed Rulemaking process, OMB approved
the proposed information collection requirements in 30 CFR Part 250,
Subpart D, Oil and Gas Drilling Operations (OMB Control Number 1010-
0053) and Subpart E, Oil and Gas Well-Completion Operations (OMB
Control Number 1010-0067), as required by the PRA of 1995 (44 U.S.C.
3501 et seq.). MMS did not receive any comments on the information
collection aspects in the notice of proposed rulemaking. The final rule
did not change any of the information collection requirements. PRA
provides that an agency may not conduct or sponsor, and a person is not
required to respond to, a collection of information unless it displays
a currently valid OMB control number.
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.
MMS estimated the total annual burden for subpart D to be 108,581
hours. This reflects a decrease of 12,499 recordkeeping hours as a
result of the rule. The estimated total annual burden for subpart E is
4,841 hours. MMS estimates that the rule reduced the annual burden for
subpart E by 2,563 recordkeeping hours.
Takings Implication Assessment
The Department of the Interior (DOI) certifies that this final rule
does not represent a governmental action capable of interference with
constitutionally protected property rights. Thus, MMS did not need to
prepare a Takings Implication Assessment pursuant to E.O. 12630,
Governmental Action 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 this rule meets the applicable civil
justice reform standards provided in sections 3(a) and 3(b)(2) of E.O.
12988.
National Environmental Policy Act
DOI has determined that this action does not constitute a major
Federal action significantly affecting the quality of the human
environment. Therefore, preparation of an Environmental Impact
Statement is not required.
List of Subjects in 30 CFR Part 250
Continental shelf, Environmental impact statements, Environmental
protection, Government contracts, 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: May 15, 1998.
Sylvia V. Baca,
Deputy Assistant Secretary, Land and Minerals Management.
For the reasons stated in the preamble, the Minerals Management
Service (MMS) amends 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. In Sec. 250.406, the fourth sentence in paragraph (d)(10)(i) is
revised to read as follows:
Sec. 250.406 Blowout preventer systems and system components.
* * * * *
(d) * * *
[[Page 29607]]
(10) * * *
(i) * * * All required manual and remotely controlled valves of a
kelly cock or comparable type in a top-drive system must be essentially
full-opening and tested according to the test pressure and test
frequency as stated in Sec. 250.407 of this part. * * *
3. Section 250.407 is revised to read as follows:
Sec. 250.407 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 a.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. The
District Supervisor may allow you to omit this test if you did not
remove the BOP stack to run the casing string or liner and the required
BOP-test pressures for the next section of the hole are not greater
than the test pressures for the previous BOP test. You must indicate in
your APD which casing strings and liners meet these criteria.
(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;
(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. Additionally, the interval between any blind
or blind-shear ram tests may not exceed 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 safety valves assembled with proper casing connections
prior to running casing, and
(9) If you install 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 on the first trip out of the hole. You must record the reason for
postponing any test in the driller's report.
(f) Visual inspections. You must visually inspect your surface and
subsea BOP systems and marine riser at least once each day if weather
and sea conditions permit. You may use television cameras to inspect
subsea 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 2 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.
4. Section 250.516 is revised to read as follows:
Sec. 250.516 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 a.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:
[[Page 29608]]
(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.
(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 2 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. 98-14294 Filed 5-29-98; 8:45 am]
BILLING CODE 4310-MR-P
