[Federal Register Volume 75, Number 198 (Thursday, October 14, 2010)]
[Rules and Regulations]
[Pages 63346-63377]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2010-25256]
[[Page 63345]]
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Part III
Department of the Interior
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Bureau of Ocean Energy Management, Regulation and Enforcement
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30 CFR Part 250
Oil and Gas and Sulphur Operations in the Outer Continental Shelf--
Increased Safety Measures for Energy Development on the Outer
Continental Shelf; Final Rule
Federal Register / Vol. 75 , No. 198 / Thursday, October 14, 2010 /
Rules and Regulations
[[Page 63346]]
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DEPARTMENT OF THE INTERIOR
Bureau of Ocean Energy Management, Regulation and Enforcement
30 CFR Part 250
[Docket ID BOEM-2010-0034]
RIN 1010-AD68
Oil and Gas and Sulphur Operations in the Outer Continental
Shelf--Increased Safety Measures for Energy Development on the Outer
Continental Shelf
AGENCY: Bureau of Ocean Energy Management, Regulation and Enforcement
(BOEMRE), Interior.
ACTION: Interim final rule with request for comments.
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SUMMARY: This interim final rule implements certain safety measures
recommended in the report entitled, ``Increased Safety Measures for
Energy Development on the Outer Continental Shelf'' (Safety Measures
Report), dated May 27, 2010. The President directed the Department of
the Interior to develop the Safety Measures Report to identify measures
necessary to improve the safety of oil and gas exploration and
development on the Outer Continental Shelf in light of the Deepwater
Horizon event on April 20, 2010, and resulting oil spill. To implement
the practices recommended in the Safety Measures Report, the Bureau of
Ocean Energy Management, Regulation and Enforcement is amending
drilling regulations related to well control, including: subsea and
surface blowout preventers, well casing and cementing, secondary
intervention, unplanned disconnects, recordkeeping, well completion,
and well plugging.
DATES: Effective Date: This rule becomes effective on October 14, 2010.
The incorporation by reference of the publication listed in the
regulations is approved by the Director of the Federal Register as of
October 14, 2010. Submit comments on the interim final rule by December
13, 2010. BOEMRE may not fully consider comments received after this
date. Submit comments to the Office of Management and Budget on the
information collection burden in this rule by December 13, 2010.
ADDRESSES: You may submit comments on the interim final rulemaking by
any of the following methods. Please use the Regulation Identifier
Number (RIN) 1010-AD68 as an identifier in your message. See also
Public Availability of Comments under Procedural Matters.
Federal eRulemaking Portal: http://www.regulations.gov. In
the entry titled ``Enter Keyword or ID,'' enter BOEM-2010-0034 then
click search. Follow the instructions to submit public comments and
view supporting and related materials available for this rulemaking.
BOEMRE will post all comments.
Mail or hand-carry comments to the Department of the
Interior; Bureau of Ocean Energy Management, Regulation and
Enforcement; Attention: Regulations and Standards Branch (RSB); 381
Elden Street, MS-4024, Herndon, Virginia 20170-4817. Please reference
``Increased Safety Measures for Energy Development on the Outer
Continental Shelf, 1010-AD68'' in your comments and include your name
and return address.
Send comments on the information collection in this rule
to: Department of the Interior; Bureau of Ocean Energy Management,
Regulation and Enforcement; Attention: Cheryl Blundon; 381 Elden
Street, MS-4024; Herndon, Virginia 20170-4817. Please reference
Information Collection 1010-0185 in your comment and include your name
and address.
FOR FURTHER INFORMATION CONTACT: Amy C. White, Office of Offshore
Regulatory Programs, Regulations and Standards Branch, Bureau of Ocean
Energy Management, Regulation and Enforcement, 703-787-1665,
[email protected].
SUPPLEMENTARY INFORMATION:
Table of Contents
I. Background
II. Request for Comments on Interim Final Rule and Effective Date
III. Overview of Requirements in the Interim Final Rule
IV. Source of Specific Provisions Addressed in the Interim Final
Rule
V. Justification for Interim Final Rulemaking
VI. Section-By-Section Discussion of Requirements in the Interim
Final Rule
VII. Additional Recommendations in the Safety Measures Report Not
Covered in This Interim Final Rule
I. Background
This interim final rule promulgated for the prevention of waste and
conservation of natural resources of the Outer Continental Shelf,
establishes regulations based on certain recommendations in the May 27,
2010, report from the Secretary of the Interior to the President
entitled, ``Increased Safety Measures for Energy Development on the
Outer Continental Shelf'' (Safety Measures Report). The President
directed that the Department of the Interior (DOI) develop this report
as a result of the Deepwater Horizon event on April 20, 2010. This
event, which involved a blowout of the BP Macondo well and an explosion
on the Transocean Deepwater Horizon mobile offshore drilling unit
(MODU), resulted in the deaths of 11 workers, an oil spill of national
significance, and the sinking of the Deepwater Horizon MODU. On June 2,
2010, the Secretary of the Interior directed the Bureau of Ocean Energy
Management, Regulation and Enforcement (BOEMRE) (formerly the Minerals
Management Service) to adopt the recommendations contained in the
Safety Measures Report and to implement them as soon as possible.
The Safety Measures Report recommended a series of steps to improve
the safety of offshore oil and gas drilling operations in Federal
waters. It outlined a number of specific measures designed to ensure
sufficient redundancy in blowout preventers (BOPs), promote well
integrity, enhance well control, and facilitate a culture of safety
through operational and personnel management.
The Safety Measures Report recommended that certain measures be
implemented immediately through a Notice to Lessees and Operators
(NTL). It identified other measures as being appropriate to address
through an emergency rulemaking process. The Safety Measures Report
recognized that other recommendations would require additional review
and refinement through technical reviews by the DOI, through
information supplied as a result of the numerous investigations into
the root causes of the Deepwater Horizon explosion, and through the
longer-term recommendations of DOI strike teams and inter-agency work
groups. The Safety Measures Report recommended that these other
measures be addressed through notice and comment rulemaking, as
appropriate.
On June 8, 2010, BOEMRE issued an NTL addressing those
recommendations identified in the Safety Measures Report as warranting
immediate implementation (NTL No. 2010-N05--Increased Safety Measures
for Energy Development on the OCS). This interim final rule clarifies
existing regulatory requirements that were addressed by certain
portions of NTL No. 2010-N05. This rule incorporates specific details
included in 2010-N05 by codifying these into regulations. The rule does
not codify the one-time requirements from NTL No. 2010-N05, such as the
one-time requirement for recertification of all BOP equipment used in
new floating operations, which will be evaluated and considered for
future rulemakings as appropriate.
This interim final rule also addresses measures identified in the
Safety Measures Report as appropriate for
[[Page 63347]]
implementation through emergency rulemaking, with certain exceptions
discussed later. It also includes other provisions from the Safety
Measures Report that BOEMRE considers appropriate for immediate
implementation in this interim final rule.
As provided for in the Safety Measures Report, BOEMRE will continue
to review other safety measures. These include items that may be
appropriate for rulemaking in the near future, as well as measures that
will require further study, whether through DOI-led strike teams,
inter-agency workgroups, or other means.
The following table provides a summary of the interim final rule
requirements, estimated annual costs to implement the requirements, and
the operator's ability to comply with the requirements. Additional
discussion on all the requirements follows in the remainder of the
preamble.
Summary of Interim Final Rule Compliance
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Operator cost to
Citation and requirement Recommendation Applies to implement per Operator ability to comply with
year * requirement
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Sec. 250.198(a)(3), All documents Based on NTL No. 2010 All operators........... ................. Administrative provision that does not
incorporated by reference ``should'' N05. impose compliance times beyond the
and ``shall'' mean ``must''. substantive provisions involved.
Sec. 250.198(h)(79), Incorporation Safety Measures Report: All applications for ................. Additional information provision does not
by Reference of API RP 65--Part 2 II.B.3.7: Enforce permit to drill (APDs) impose compliance times beyond the
Isolating Potential Flow Zones Tighter Primary **. substantive provisions involved.
During Well Construction. Cementing Practices.
Sec. 250.415(f), Written Safety Measures Report: Submitted with APD. ................. New engineering requirement. BOEMRE
description of how the operator II.B.3.7: Enforce Applies to all APDs. believes that most operators will be able
evaluated the best practices Tighter Primary to comply with this requirement with no
included in API RP 65-Part 2. The Cementing Practices. significant delays * * * because this can
description must identify mechanical be completed concurrently with other
barriers and cementing practices to tasks.
be used for each casing string.
Sec. 250.416(d), Include schematics Safety Measures Report: Submitted with APD. ................. Information is readily available. Should
of all control systems and control I.B.5: Secondary Applies to all APDs. not delay submission of the APD.
pods. Control System
Requirement and
Guidelines.
Sec. 250.416(e), Independent third Safety Measures Report: Submitted with APD. $1,200,000 Because there are multiple engineering
party verification that the blind- I.C.7: Develop New Applies to all APDs. firms available to do this work, and
shear rams installed are capable of Testing Requirements. because operators have had advance notice
shearing any drill pipe in the hole. Also in NTL No. N05. of this requirement in both the Safety
Measures Report and NTL No. N05, BOEMRE
believes that most operators will be able
to comply with this requirement with no
significant delay and provide information
in the APD.
Sec. 250.416(f), Independent third Safety Measures Report: Submitted with APD. All
party verification that subsea BOP I.B.2: Order BOP APDs for well with
is designed for specific equipment Equipment Compatibility subsea BOP stack.
on rig and specific well design. Verification for Each Subsea BOP stacks are
Floating Vessel and for usually employed in
Each New Well. Also in deepwater.
NTL No. N05.
Sec. 250.416(g), Qualification for Based on NTL No. 2010 N- All APDs................ ................. Related to requirements for independent
independent third parties. 05. third party certifications.
[[Page 63348]]
Sec. 250.420(a)(6), Certification Safety Measure Report: Submitted with APD. 6,000,000 Because there are multiple engineering
by a professional engineer that II.B.1.3: New Casing Applies to all APDs. firms available to do this work and
there are two independent tested and Cement Design because operators have had advance notice
barriers and that the casing and Requirements: Two of this requirement in both the Safety
cementing design are appropriate. Independent Barriers. Measures Report and NTL No. N05, BOEMRE
This requirement was believes operators will be able to comply
also addressed in NTL with this requirement with no significant
No. N05. delays and provide information in the
APD.
Sec. 250.420(b)(3), Installation of Safety Measure Report: Completed during the 10,300,000 Completed during the casing and cementing
dual mechanical barriers in addition II.B.1.3: New Casing casing and cementing of of the well. Compliance with this
to cement for final casing string. and Cement Design the well. It applies to requirement may minimally increase the
Requirements: Two all wells drilled. time to drill each well.
Independent Barriers.
This requirement was
also addressed in NTL
No. N05.
Sec. 250.423(b), The operator must Safety Measure Report: Complied with after the ................. Because operators had advance notice of
perform a pressure test on the II.B.2.5: New Casing installation of each this requirement in both the Safety
casing seal assembly to ensure Installation casing string or liner Measures Report and NTL No. N05, BOEMRE
proper installation of casing or Procedures. This for all wells drilled believes operators should be complying
liner. The operator must ensure that requirement was also with a subsea BOP with this requirement.
the latching mechanisms or lock down addressed in NTL No. stack. It is tested
mechanisms are engaged upon N05. after the installation
installation of each casing string of the casing or liner.
or liner.
Sec. 250.423(c), The operator must Safety Measure Report: Tested after running the 45,100,000 Compliance with this requirement will
perform a negative pressure test to II.B.2.6: Develop casing. All wells, increase the time to drill each subsea
ensure proper casing installation. Additional Requirements involves all rigs with well resulting in additional costs.
This test must be performed for the or Guidelines for surface and subsurface BOEMRE estimates several hours of
intermediate and production casing Casing. BOPs in all water additional drilling time for each well.
strings. depths.
Sec. 250.442(c), Sec. 250.515(e), Safety Measure Report: Applies to all subsea ................. All rigs should be able to comply with
Sec. 250.615(e). Have a subsea BOP I.B.5: Secondary BOP stacks. requirement. All rigs currently have ROV
stack equipped with remotely Control System intervention capability; approximately
operated vehicle (ROV) intervention Requirements and 80% of subsea BOP stacks currently have
capability. At a minimum, the ROV Guidelines. This all the specified capabilities. Other 20%
must be capable of closing one set requirement was also are expected to be able to comply
of pipe rams, closing one set of addressed in NTL No. promptly.
blind-shear rams, and unlatching the N05.
lower marine riser package.
Sec. 250.442(c), Sec. 250.515(e), Safety Measure Report: Ongoing requirement. All ................. BOEMRE believes all rigs operating on OCS
Sec. 250.615(e). Maintain an ROV I.B.6: New ROV subsea BOP stacks are already in compliance.
and have a trained ROV crew on each Operating Capabilities; regardless of water
floating drilling rig on a II.A.1: Establish depth.
continuous basis. Deepwater Well-Control
Procedure Guidelines.
Sec. 250.442(f), Sec. 250.515(e), Safety Measure Report: Anytime drilling occurs ................. BOEMRE believes all DP rigs operating on
Sec. 250.615(e). Provide autoshear I.B.5: Secondary with subsea BOP stacks OCS currently comply with this
and deadman systems for dynamically Control System on DP rigs. requirement.
positioned (DP) rigs. Requirements and
Guidelines.
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Sec. 250.442(e), Sec. 250.515(e), Safety Measure Report: Ongoing requirement. ................. Requires trained ROV crew; for rigs not
Sec. 250.615(e). Establish minimum II.A.1: Establish Applies to all already in compliance, additional
requirements for personnel Deepwater Well-Control personnel that operate training or hiring of new crew may be
authorized to operate critical BOP Procedure Guidelines. subsea BOP stacks. necessary. Additional training could take
equipment. Majority of drilling days to weeks, depending upon how well
rigs that use subsea existing crews are trained. However,
BOP stacks operate in BOEMRE believes no rigs should be
deepwater. operating without adequately trained
personnel.
Sec. 250.446(a), Sec. 250.516(h), Safety Measure Report: Ongoing requirement. All ................. All rigs should be able to comply with
Sec. 250.516(g), Sec. 250.617. I.B.5: Secondary BOP stacks. All water requirement.
Require documentation of BOP Control System depths.
inspections and maintenance Requirements and
according to API RP 53. Guidelines.
Sec. 250.449(j), Sec. Safety Measure Report: During the stump test 118,200,000 All rigs should be able to comply with
250.516(d)(8), Sec. 250.616(h)(1). I.B.5: Secondary and initial test on the requirement. This requirement not
Test all ROV intervention functions Control System seafloor. All subsea expected to result in significant delay.
on the subsea BOP stack during the Requirements and BOP stacks. All water Compliance with this requirement will
stump test. Test at least one set of Guidelines; I.C.7: depths. slightly increase the time to drill each
rams during the initial test on the Develop New Testing deepwater well drilled with a subsea BOP,
seafloor. Requirements. resulting in additional costs.
Sec. 250.449(k), Sec. Safety Measure Report:
250.516(d)(9), Sec. 250.616(h)(2). I.B.5: Secondary
Function test autoshear and deadman Control System
systems on the subsea BOP stack Requirements and
during the stump test. Test the Guidelines; I.C.7:
deadman system during the initial Develop New Testing
test on the seafloor. Requirements.
Sec. 250.451(i), If the blind-shear Safety Measure Report: Emergency activation of 2,600,000 Compliance with this requirement will
or casing shear rams are activated I.C.7: Develop New blind or casing shear increase drilling costs when such an
in a well control situation, the BOP Testing Requirements. rams. emergency occurs.
must be retrieved and fully This requirement was
inspected and tested. also addressed in NTL
No. N05.
Sec. 250.456(j), Before displacing Safety Measure Report: Submit with APD or ................. New requirement. Operator should be able
kill-weight drilling fluid from the II.A.2: New Fluid application for permit to provide this information in APD or APM
wellbore, the operator must receive Displacement Procedures. to modify (APM). All without significant delay.
approval from the District Manager. wells where the
The operator must submit the reasons operator wants to
for displacing the kill-weight displace kill-weight
drilling fluid and provide detailed fluids. This could
step-by-step procedures describing occur on all rigs that
how the operator will safely use either a surface or
displace these fluids. subsurface BOP stack.
Could occur with all
water depths.
Subpart O, Sec. Sec. 250.1500- Safety Measure Report: All wells drilled with ................. BOEMRE believes that the majority of
250.1510, Requires that rig II.A.1: Establish subsea BOP stack. operators have addressed this
personnel are trained in deepwater Deepwater Well-Control requirement. There should not be any
well control and the specific Procedure Guidelines. delay for this requirement.
duties, equipment, and techniques
associated with deepwater drilling.
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Sec. 250.1712(g), Sec. Safety Measure Report: Submitted with APM. All ................. Operator should be able to comply with no
250.1721(h). Certification by a II.B.1.3: New Casing abandonment operations significant delay and provide information
professional engineer of the well and Cement Design regardless of BOP type in application for permit to modify
abandonment design and procedures; Requirements: Two or water depth. (APM). Estimate that this could take an
that there will be at least two Independent Tested operator as much as several days to
independent tested barriers, Barriers. comply with new requirement. Depends on
including one mechanical barrier, operator's internal review process.
across each flow path during
abandonment activities; and that the
plug meets the requirements in the
table in Sec. 250.1715.
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* Costs that were not provided did not add a meaningful value in comparison of the cost of drilling a well.
** All APDs means all wells drilled with a surface BOP and all wells drilled with a subsurface BOP. Includes all water depths.
*** Requirements noted as ``no significant delay'' are anticipated to require no more than 1 week to achieve compliance. While individually each
activity could take a day and possibly up to 5 days to complete, it is anticipated that companies will build this into their schedules with no
resulting overall delay.
Total Estimates of Costs and Benefits
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Total Estimated Annual Compliance $183.1 million.
Costs.
Total Estimated Annual Avoided $631.4 million--B *.
Social Costs (Benefits).
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* DOI estimated the cost of a hypothetical spill in the future at $16.3
billion, and also estimated the baseline likelihood of a catastrophic
blowout event and spill occurring, based on historical trends and the
number of expected future wells, to be once every 26 years. These
estimates are necessarily uncertain, and are discussed in more detail
in the RIA. Combining the baseline likelihood of occurrence with the
cost of a hypothetical spill implies that the expected annualized
spill cost is about $631 million. This rulemaking will not reduce the
probability of a future spill to zero; therefore, ``B'' in the table
above represents the adjustment in annual avoided social costs
expected from this rulemaking based on the non-zero remaining
probability of a spill after this rule is put into place. Thus, the
difference between the avoided costs with and without their rule
represents its expected benefits. This remaining probability is
uncertain. For example, to balance the $183 million annual cost
imposed by these regulations with the expected benefits, the
reliability of the well control system needs to improve by about 29
percent ($183 million/$631 million). Although we have found no studies
that evaluate the degree of actual improvement that could be expected
from dual mechanical barriers, negative pressure tests, and a seafloor
ROV function test, we believe it reasonable to anticipate that such
measures will increase the reliability of the well control systems,
and therefore that the benefits of this rulemaking justify the costs.
II. Request for Comments on Interim Final Rule and Effective Date
This is an interim final rulemaking with request for comments; it
is effective immediately upon publication. The Administrative Procedure
Act (APA) requires that an agency publish a proposed rule in the
Federal Register with notice and an opportunity for public comment,
unless the agency, for good cause, finds that providing notice and
soliciting comments in advance of promulgating the rule would be
impracticable, unnecessary, or contrary to the public interest (5
U.S.C. 553(b)). BOEMRE determined that there is good cause for
publishing this interim final rule without prior notice and comment
based on its findings, consistent with preliminary information that is
available as a result of investigations into the Deepwater Horizon
event, that certain equipment, systems, and improved practices are
immediately necessary for the safety of offshore oil and gas drilling
operations on the Outer Continental Shelf (OCS), and that these
improved drilling practices are either not addressed or not
sufficiently detailed by current regulations. Immediate imposition of
the requirements contained in this interim final rule is necessary
because BOEMRE views strict adherence to improved safety practices set
forth herein as necessary to achieving safer conditions that, together
with other wild well control and oil spill response capabilities, will
allow it to permit future OCS drilling operations. Following notice and
comment procedures would be impracticable in these circumstances.
Furthermore, following notice and comment procedures would be
contrary to the public interest because the delay in implementation of
this interim final rule could result in harm to public safety and the
environment. Failure to adhere to the safety practices required by this
interim final rule increases the risk of a blowout and subsequent oil
spill, with serious consequences to the health and safety of workers
and the environment.
As discussed in Section 5, ``Justification for the Interim Final
Rulemaking,'' while investigation and information-gathering into the
Deepwater Horizon blowout and spill continues, preliminary evidence
suggests problems with the Macondo well's line of defense, which could
include blowout preventer (BOP) systems, casing and cementing programs,
and fluid displacement procedures. Evidence further suggests that it is
unlikely that these problems are unique to the Deepwater Horizon event;
for example, most BOPs used in drilling on the OCS are of similar
design and are produced by a limited number of manufacturers. The
interim final rule's provisions thus incorporate targeted measures to
promote the integrity of the well and enhance well control, including
provisions specifically identified by the Safety Measures Report as
warranting immediate implementation. For example, the requirement that
operators have all well casing designs and cementing systems/procedures
certified by a Professional Engineer.
Similarly, BOEMRE determined that the immediate necessity for
improved equipment, systems, and practices also provides good cause to
impose an immediate effective date. The APA requires an agency to
publish a rule not less than 30 days before its effective
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date, except as otherwise provided by the agency for good cause found
and published with the rule (5 U.S.C. 553(d)(3)). Just as BOEMRE found
that providing notice and an opportunity to comment is impracticable
and contrary to the public interest, BOEMRE finds that a 30-day delay
after publication of this interim final rule compromises the safety of
offshore oil and gas drilling. To the extent that the 30-day period is
intended to allow regulated parties to adjust to new requirements,
information gathered by BOEMRE in advance of this rulemaking indicates
that the oil and gas industry is well aware of the general provisions
in this interim final rule. Most of the provisions in the rule were
identified in the Safety Measures Report, and industry is already
working to implement them.
We note that in developing the Safety Measures Report on which this
interim final rule is based, the Department consulted with a wide range
of experts in state and Federal governments, academic institutions, and
industry and advocacy organizations. In addition, the draft
recommendations of the Safety Measure Report were peer reviewed by
seven experts identified by the National Academy of Engineering (NAE).
Further explanation of the justification for this interim final
rulemaking is provided in section V, ``Justification for Interim Final
Rulemaking.''
While BOEMRE will not solicit comments before the effective date,
BOEMRE will accept and consider public comments on this rule that are
submitted within 60 days of its publication in the Federal Register.
After reviewing the public comments, BOEMRE will publish a notice in
the Federal Register that will respond to comments and will either:
1. Confirm this rule as a final rule with no additional changes, or
2. Issue a revised final rule with modifications, based on public
comments.
III. Overview of Requirements in the Interim Final Rule
As recommended in the Safety Measures Report, this interim final
rule imposes a number of prescriptive, near-term requirements. Other
longer-term safety measures and performance-based standards recommended
in the Safety Measures Report will be analyzed for implementation in
future rulemakings. Information from the many investigations and other
information sources will also be analyzed and considered in future
rulemakings. In developing the Safety Measures Report on which this
interim final rule is based, the Department consulted with experts in
state and Federal government, academic institutions, and industry and
advocacy organizations. In addition, draft recommendations were peer
reviewed by seven experts identified by the NAE.
The primary purpose of this interim final rule is to clarify and
incorporate safeguards that will decrease the likelihood of a blowout
during drilling operations on the OCS. The safeguards address well bore
integrity and well control equipment, and this interim final rule
focuses on those two overarching issues. This rule will therefore
promulgate OCS-wide provisions that will:
1. Establish new casing installation requirements,
2. Establish new cementing requirements (incorporate American
Petroleum Institute (API) Recommended Practice (RP) 65--Part 2,
Isolating Potential Flow Zones During Well Construction),
3. Require independent third party verification of blind-shear ram
capability,
4. Require independent third party verification of subsea BOP stack
compatibility,
5. Require new casing and cementing integrity tests,
6. Establish new requirements for subsea secondary BOP
intervention,
7. Require function testing for subsea secondary BOP intervention,
8. Require documentation for BOP inspections and maintenance,
9. Require a Registered Professional Engineer to certify casing and
cementing requirements, and
10. Establish new requirements for specific well control training
to include deepwater operations.
As stated, the intent of this interim final rule is to improve
safety related to both well bore integrity and well control equipment.
Well bore integrity provides the first line of defense against a
blowout by preventing a loss of well control. Well bore integrity
includes appropriate use of drilling fluids and the casing and
cementing program. Drilling fluids and the casing and cementing program
are used to balance the pressure in the borehole against the fluid
pressure of the formation, preventing an uncontrolled influx of fluid
into the wellbore. The specific provisions in this rule that address
well bore integrity are:
1. Incorporating by reference API RP 65--Part 2, Isolating
Potential Flow Zones During Well Construction;
2. Submission of certification by a Registered Professional
Engineer that the casing and cementing program is appropriate for the
purpose for which it is intended under expected wellbore pressure;
3. Requirements for two independent test barriers across each flow
path during well completion activities (also certified by a Registered
Professional Engineer);
4. Ensuring proper installation of the casing or liner in the
subsea wellhead or liner hanger;
5. Approval from the District Manager before displacing kill-weight
drilling fluid; and
6. Deepwater well control training for rig personnel.
Well control equipment is the general term for the technologies
used to control a well by mechanical means in the event that other well
control mechanisms fail. Well control equipment includes control
systems that activate the BOPs, either through a control panel on the
drilling rig or through Remotely Operated Vehicles (ROVs) that directly
interface with the subsea BOP to activate the appropriate rams. The
provisions in this rule that address well control equipment include:
1. Submission of documentation and schematics for all control
systems;
2. A requirement for independent third party verification that the
blind-shear rams are capable of cutting any drill pipe in the hole
under maximum anticipated surface pressure (MASP);
3. A requirement for a subsea BOP stack equipped with ROV
intervention capability. At a minimum, the ROV must be capable of
closing one set of pipe rams, closing one set of blind-shear rams, and
unlatching the Lower Marine Riser Package (LMRP);
4. A requirement for maintaining an ROV and having a trained ROV
crew on each floating drilling rig on a continuous basis;
5. A requirement for autoshear and deadman systems for dynamically
positioned rigs;
6. Establishment of minimum requirements for personnel authorized
to operate critical BOP equipment;
7. A requirement for documentation of subsea BOP inspections and
maintenance according to API RP 53, Recommended Practices for Blowout
Prevention Equipment Systems for Drilling Wells;
8. Required testing of all ROV intervention functions on the subsea
BOP stack during the stump test and testing at least one set of rams
during the initial test on the seafloor;
9. Required function testing of autoshear and deadman systems on
the subsea BOP stack during the stump test and testing the deadman
system during the initial test on the seafloor; and
[[Page 63352]]
10. Required pressure testing if any shear rams are used in an
emergency.
The following table shows where recommendations from the Safety
Measures Report are implemented in the interim final rule.
----------------------------------------------------------------------------------------------------------------
Safety measures report
recommendation Interim final rule citation
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Subpart A--General
II.B.3.7: Enforce Tighter Sec. 250.198 Documents incorporated by reference.
Primary Cementing Practices.
Subpart D--Oil and Gas Drilling Operations
II.B.3.7: Enforce Tighter Sec. 250.415 What must my casing and cementing programs include?
Primary Cementing Practices.
I.A.2: Order BOP Equipment Sec. 250.416 What must I include in the diverter and BOP descriptions?
Compatibility Verification for
Each Floating Vessel and for
Each New Well.
I.B.5: Secondary Control System
Requirement and Guidelines
I.C.7: Develop New Testing
Requirements
II.B.1.3: New Casing and Cement Sec. 250.418 What additional information must I submit with my APD?
Design Requirements: Two
Independent Barriers.
I.C.7: Develop New Testing
Requirements
II.B.1.3: New Casing and Cement Sec. 250.420 What well casing and cementing requirements must I meet?
Design Requirements: Two
Independent Barriers.
II.B.1.3: New Casing and Cement Sec. 250.423 What are the requirements for pressure testing casing?
Design Requirements: Two
Independent Barriers.
II.B.2.5: New Casing
Installation Procedures
II.B.2.6: Develop Additional
Requirements or Guidelines for
Casing Installation
I.B.5: Secondary Control System Sec. 250.442 What are the requirements for a subsea BOP system?
Requirements and Guidelines.
I.B.6: New ROV Operating
Capabilities
II.A.1: Establish Deepwater Well-
Control Procedure Guidelines
I.B.5: Secondary Control System Sec. 250.446 What are the BOP maintenance and inspection requirements?
Requirements and Guidelines.
I.B.5: Secondary Control System Sec. 250.449 What additional BOP testing requirements must I meet?
Requirements and Guidelines.
I.C.7: Develop New Testing
Requirements
I.C.7: Develop New Testing Sec. 250.451 What must I do in certain situations involving BOP equipment or
Requirements systems?
II.A.2: New Fluid Displacement Sec. 250.456 What safe practices must the drilling fluid program follow?
Procedures.
Subpart E--Oil and Gas Well-Completion Operations
I.B.5: Secondary Control System Sec. 250.515 Blowout prevention equipment.
Requirements and Guidelines.
I.B.6: New ROV Operating
Capabilities
II.A.1: Establish Deepwater Well-
Control Procedure Guidelines
I.B.5: Secondary Control System
Requirements and Guidelines and
recommendation.
I.C.7: Develop New Testing
Requirements
Subpart F--Oil and Gas Well-Workover Operations
I.B.5: Secondary Control System Sec. 250.615 Blowout prevention equipment.
Requirements and Guidelines.
I.B.6: New ROV Operating
Capabilities
II.A.1: Establish Deepwater Well-
Control Procedure Guidelines
I.B.5: Secondary Control System Sec. 250.616 Blowout preventer system testing, records, and drills.
Requirements and Guidelines and
recommendation.
I.C.7: Develop New Testing
Requirements
I.B.5: Secondary Control System Sec. 250.617 What are my BOP inspection and maintenance requirements?
Requirements and Guidelines and
recommendation.
I.C.7: Develop New Testing
Requirements
Subpart O--Well Control and Production Safety Training
II.A.1: Establish Deepwater Well- Sec. Sec. 250.1500-250.1510.
Control Procedure Guidelines.
Sec. 250.1503 What are my general responsibilities for training?
Subpart Q--Decommissioning Activities
II.B.1.3: New Casing and Cement Sec. 250.1712 What information must I submit before I permanently plug a
Design Requirements: Two well or zone?
Independent Tested Barriers.
II.B.1.3: New Casing and Cement Sec. 250.1721 If I temporarily abandon a well that I plan to re-enter, what
Design Requirements: Two must I do?
Independent Tested Barriers.
----------------------------------------------------------------------------------------------------------------
IV. Source of Specific Provisions Addressed in the Interim Final Rule
This interim final rule clarifies existing regulatory requirements
that were addressed by certain portions of NTL No. 2010-N05 by
codifying the specific details into regulations. It also addresses
items in the Safety Measures Report either identified as appropriate
for implementation through emergency rulemaking, or which BOEMRE has
determined will significantly increase OCS drilling safety and with
which operators can readily comply. The following provides an
explanation of each of these sources and provisions.
Emergency Rulemaking Recommendations From Safety Measures Report
The Safety Measures Report identified four items for emergency
rulemaking:
1. Develop secondary control system requirements;
[[Page 63353]]
2. Establish new blind-shear ram redundancy requirements;
3. Establish new deepwater well control procedure requirements; and
4. Adopt safety case requirements for floating drilling operations
on the OCS.
Of these four items, this interim final rule addresses: 1.
Secondary control system requirements; and 3. deepwater well control
procedure requirements. This interim final rule does not include: 2.
New blind-shear ram redundancy requirements; and 4. safety case
requirements for floating drilling operations on the OCS.
BOEMRE determined that, while new blind-shear ram redundancy
requirements are important to offshore drilling safety, they are not
appropriate for inclusion in this interim final rule. Installation of a
second set of blind-shear rams will require major modifications to the
BOP stack for most rigs on the OCS. Compliance with such a requirement
is likely to take operators from 1 year to 18 months. Inclusion of a
requirement that will necessitate a period of 1 year or more to comply
is not appropriate for an interim final rule, the purpose of which is
to have immediate effect. Given the necessary compliance periods,
BOEMRE believes there will be sufficient opportunity to proceed through
a notice and comment rulemaking. Operators should be aware, however,
that BOEMRE intends to promptly initiate a notice and comment
rulemaking process to address this issue. Specifically, operators
should be aware that BOEMRE is considering regulations to require the
installation of a second set of blind-shear rams, appropriately spaced
to ensure that at least one blind-shear ram cuts any drill pipe in the
hole and seals the wellbore at any time. Operators should also be aware
that BOEMRE is likewise considering requiring, through a notice and
comment rulemaking, a set of casing shear rams capable of shearing any
casing in the hole.
This interim final rule addresses both new well bore integrity
requirements and well control equipment requirements. The well bore
integrity provisions impose requirements for casing and cementing
design and installation, tighter cementing practices, the displacement
of kill-weight fluids, and testing of independent well barriers. These
new requirements ensure that there are additional physical barriers in
the well to prevent oil and gas from escaping into the environment.
These new requirements related to well bore integrity will considerably
decrease the likelihood of a loss of well control. The well control
equipment requirements in this interim final rule will help ensure the
BOPs will operate in the event of an emergency and that the ROVs are
capable of activating the BOPs. Together, these new requirements will
help decrease the urgency of immediately requiring blind-shear ram
redundancy on BOPs, and have factored into BOEMRE's decision to address
such requirements through a standard rulemaking process.
BOEMRE also determined not to include safety case requirements for
floating drilling operations in this interim final rule. A safety case
is a comprehensive, structured documentation system to reduce operating
risks for offshore drilling. A drilling safety case would establish
risk assessment and mitigation processes to manage a drilling
contractor's controls related to health, safety, and environmental
aspects of operations. BOEMRE is evaluating how a drilling safety case
should be most appropriately integrated with an overall Safety and
Environmental Management System (SEMS) approach, which BOEMRE may
implement through a separate rulemaking process. As directed in the
Safety Measures Report, BOEMRE will work with offshore operators and
drilling contractors, appropriate government agencies, and other
appropriate stakeholders to consider the type of well construction
interfacing document that will best connect the requirements of a
safety case to existing well design and construction documents. BOEMRE
therefore intends to pursue adoption of appropriate safety case
requirements through a separate rulemaking process once the necessary
analyses have been completed.
Requirements From NTL No. 2010-N05
Of the requirements in this interim final rule, the following table
clarifies existing regulations by codifying provisions of NTL No. 2010-
N05:
----------------------------------------------------------------------------------------------------------------
NTL No. 2010-N05 provision Interim final rule citations
----------------------------------------------------------------------------------------------------------------
Documentation that the BOP has Sec. 250.446 What are the BOP maintenance and inspection requirements?
been maintained according to Sec. 250.516 Blowout preventer system tests, inspections, and maintenance.
the regulations at Sec. Sec. 250.617 What are my BOP inspection and maintenance requirements?
250.446(a), maintain these
records and make them available
upon request (safety report
rec. I.A.1).
Independent third party Sec. 250.416 What must I include in the diverter and BOP descriptions?
verification that the BOP stack
is designed for the specific
equipment on the rig and
compatible with the specific
well location, well design, and
well execution plan; that the
BOP stack has not been
compromised or damaged from
previous service; and that the
BOP stack will operate in the
conditions in which it will be
used (safety report rec. I.A.2).
Secondary control system with Sec. 250.442 What are the requirements for a subsea BOP system?
ROV intervention capabilities, Sec. 250.515 Blowout prevention equipment.
including the ability to close Sec. 250.615 Blowout prevention equipment.
one set of blind-shear rams and
one set of pipe rams and
unlatch the LMRP (safety report
rec. I.B.5).
Emergency shut-in system in the Sec. 250.442 What are the requirements for a subsea BOP system?
event that you lose power to Sec. 250.515 Blowout prevention equipment.
the BOP stack, have an Sec. 250.615 Blowout prevention equipment.
unplanned disconnection of the
riser from the BOP stack, or
experience another emergency
situation (safety report rec.
I.B.5).
Function test the hot stabs that Sec. 250.449 What additional BOP testing requirements must I meet?
would be used to interface with Sec. 250.516 Blowout preventer system tests, inspections, and maintenance.
the ROV intervention panel Sec. 250.616 Blowout preventer system testing, records, and drills.
during the stump test (safety
report rec. I.B.6).
Independent third party Sec. 250.416 What must I include in the diverter and BOP descriptions?
verification that provides
sufficient information showing
that the blind-shear rams
installed in the BOP stack are
capable of shearing the drill
pipe in the hole under maximum
anticipated surface pressures
(safety report rec. I.C.7).
[[Page 63354]]
If the blind-shear rams or Sec. 250.451 What must I do in certain situations involving BOP equipment or
casing shear rams are activated systems?
in a well control situation in
which pipe or casing was
sheared, operators must inspect
and test the BOP stack and its
components, after the situation
is fully controlled (safety
report rec. I.C.7).
Have all well casing designs and Sec. 250.420 What well casing and cementing requirements must I meet?
cementing program/procedures Sec. 250.1712 What information must I submit before I permanently plug a
certified by a Registered well or zone?
Professional Engineer, Sec. 250.1721 If I temporarily abandon a well that I plan to re-enter, what
verifying the casing design is must I do?
appropriate for the purpose for
which it is intended under
expected wellbore conditions
(safety report rec. II.B.3).
----------------------------------------------------------------------------------------------------------------
Certain measures in NTL No. 2010-N05 are not included in this
interim final rule. These are:
1. Verify compliance with existing BOEMRE regulations and with the
BOEMRE/U.S. Coast Guard National Safety Alert (safety report rec.
III.A.1).
2. Submit BOP and well control system configuration information for
a drilling rig that was being used on May 27, 2010 (safety report rec.
I.C.8).
3. Operator must submit the relevant information required in NTL
No. 2010-N05 prior to commencing operations if the operator had an
Application for Permit to Drill (APD) or Application for Permit to
Modify (APM) that was previously approved but drilling had not
commenced as of May 27, 2010, and operator may not commence drilling
without BOEMRE approval (general requirement for NTL not specified in
Safety Measures Report).
Other Provisions From the Safety Measures Report in This Interim Final
Rule
The following provisions in this interim final rule are not covered
in existing NTL No. 2010-N05 but are identified in the Safety Measures
Report as being appropriate to implement either immediately or through
an emergency rulemaking:
----------------------------------------------------------------------------------------------------------------
Safety measures report provision Interim final rule citations
----------------------------------------------------------------------------------------------------------------
Establish deepwater well control Sec. 250.442 What are the requirements for a subsea BOP system?
procedure guidelines (safety Sec. 250.515 Blowout prevention equipment.
report rec. II.A.1). Sec. 250.615 Blowout prevention equipment.
Sec. Sec. 250.1500 through 250.1510 Subpart O--Well Control and Production
Safety Training.
Establish new fluid displacement Sec. 250.456 What safe practices must the drilling fluid program follow?
procedures (safety report rec.
II.A.2).
Develop additional requirements Sec. 250.423 What are the requirements for pressure testing casing?
or guidelines for casing
installation (safety report
rec. II.B.2.6).
----------------------------------------------------------------------------------------------------------------
BOEMRE has also included the following provision in this interim
final rule from the Safety Measures Report:
----------------------------------------------------------------------------------------------------------------
Safety measures report provision Interim final rule
----------------------------------------------------------------------------------------------------------------
Enforce tighter primary Sec. 250.415 What must my casing and cementing programs include?
cementing practices (safety
report rec. II.B.3.7).
----------------------------------------------------------------------------------------------------------------
This provision is recommended in the Safety Measures Report,
although it is not specifically identified as requiring implementation
immediately or through emergency rulemaking (this provision was also
not addressed in NTL No. 2010-N05). BOEMRE has nonetheless determined
that it is appropriate for inclusion in this interim final rule because
it is consistent with the intent of the recommendations in the Safety
Measures Report. Tighter cementing practices will increase the safety
of offshore oil and gas drilling operations by improving cementing
practices; they also will support the other requirements in this
interim final rule.
V. Justification for Interim Final Rulemaking
Pursuant to the Outer Continental Shelf Lands Act (OCSLA), the
Secretary has an affirmative obligation to ensure that drilling
operations undertaken on the OCS are conducted in a manner that is safe
for the human, marine, and coastal environment (43 U.S.C. 1332(6),
1334(a), 1347, and 1348; and 30 CFR 250.106). The April 20, 2010,
blowout of the BP Macondo well and the explosion on the Deepwater
Horizon killed 11 workers and resulted in the Nation's largest oil
spill ever, with substantial environmental and economic impacts.
On May 28, 2010, the Secretary ordered the suspension of certain
oil and gas drilling operations in deepwater (greater than 500 feet).
On July 12, 2010, the Secretary rescinded that order and replaced it
with a new decision ordering the suspension in the Gulf of Mexico (GOM)
and Pacific regions of the drilling of wells using subsea BOPs or
surface BOPs on a floating facility, with certain exceptions for
intervention wells, injection and disposal wells, abandonments,
completions, and workovers. This suspension order applies by its terms
until November 30, 2010, although the order notes that it could be
lifted earlier than that date.
As mentioned previously, on April 30, 2010, the President also
directed the Secretary to conduct a thorough review of the Deepwater
Horizon event and to report within 30 days on additional
[[Page 63355]]
measures needed to improve the safety of oil and gas operations on the
OCS. On May 27, 2010, the Secretary delivered the Safety Measures
Report to the President. This Safety Measures Report incorporated
recommendations from BOEMRE, as well as from a wide range of experts
from government, academia, and industry. In developing the Safety
Measures Report on which this interim final rule is based, the
Department consulted with a wide range of experts in state and Federal
government, academic institutions, and industry and advocacy
organizations. In addition, draft recommendations were peer reviewed by
seven experts identified by the NAE.
Numerous investigations are ongoing, and the precise causes of the
well blowout and explosion are not fully known; however, the fact that
a blowout occurred clearly indicates problems with the well's line of
defense, which could include BOP systems, casing and cementing
programs, and fluid displacement procedures. Accordingly, it is not
necessary to await certainty regarding the cause of the blowout before
promulgating this interim final rule.
Circumstances suggest that, while a blowout and spill of this
magnitude have not occurred before on the OCS, it is unlikely that the
problems are unique to the Deepwater Horizon and BP's Macondo well. As
noted in the July 12, 2010, decision of the Secretary to suspend
certain offshore permitting and drilling activities, most BOPs used in
drilling on the OCS are of similar design and are produced by a limited
number of manufacturers. Furthermore, the BOPs for the relief wells
drilled to intercept the Macondo well encountered unexpected
performance problems, initially failing to pass new testing procedures
developed in response to the Safety Measures Report, including failure
of the deadman and autoshear functions. These multiple failures raise
red flags as to the reliability of BOPs to adequately safeguard the
lives of workers and protect the environment from oil spills in
response to a large blowout. They also suggest the need to review
regulations pertaining to well casing and design, the other area of
likely failure in the Deepwater Horizon event.
Even without the full results of the pending investigations, the
obvious failures of well intervention and blowout containment systems
demonstrate that previous regulatory assumptions concerning their
reliability are inaccurate. The importance of these systems in
preventing catastrophic blowouts and oil spills indicate that genuine
harm could result from delay and lead BOEMRE to conclude that immediate
regulations are needed to better ensure the reliability of these
systems, and to protect the lives of workers, human health, and the
environment.
This interim final rule therefore, specifically addresses measures
that will increase the safety of these systems. It imposes requirements
to give greater certainty that casing and cement design and fluid
displacement are adequate for well bore integrity, and to enhance the
reliability of well control equipment.
The casing and cementing program and fluid displacement procedures
are the first line of defense in preventing a loss of well control that
could lead to a blowout. Casing and cement and drilling fluids are used
to ensure the fluids in a formation do not enter the wellbore during
drilling and completion operations. When a well is completed and
production begins, the casing and cement continue to prevent
uncontrolled flow of fluids into the wellbore. The integrity of the
casing and cement are critical to proper well control. While the extent
to which cementing and casing failures contributed to the Macondo
blowout is not yet fully known, preliminary information suggests that
the operator may have failed to follow best industry cementing and
casing installation practices. The current regulations contain general
cementing and casing requirements, but they do not specifically address
best cementing and casing installation practices. This rulemaking will
provide greater assurance that all operators will follow these safer
practices, reducing the risk of a loss of well control.
This interim final rule also strengthens requirements for BOPs. In
the event of a loss of well control, rig operators use the BOPs to
regain control of the well. This is done by closing the various rams on
the BOP stack, which shut off the flow of formation fluids to the
surface. Secondary well control system requirements (i.e., ROV
intervention capabilities and emergency back-up BOP control systems)
ensure that rig operators are able to activate various BOP rams in the
event the control system on the rig fails (e.g., loss of power).
Requirements in this interim final rule impose new standards to enhance
BOP reliability, thereby lessening the possibility of failures that
could lead to an uncontrolled blowout and spill with potentially
catastrophic consequences for workers and the environment.
Given the Deepwater Horizon blowout and resulting spill, and
because of the potential for grave harm to workers and the human,
marine, and coastal environment from any additional events, BOEMRE
concludes that existing regulations must be strengthened to more fully
protect offshore workers, the environment, and the public, and that
this situation justifies immediate imposition of the requirements of
this interim final rule.
This interim final rule applies to ongoing operations not covered
by the Secretary's July 12, 2010, suspension decision in addition to
those operations that were suspended by that decision. Immediate
imposition of the requirements of this rule is necessary for both
ongoing and suspended operations to ensure that all operations proceed
in a more safe and reliable fashion in protection of human health and
the environment. The July 12, 2010, suspension expires by its terms on
November 30, 2010, and it could be lifted earlier. A standard APA
notice and comment rulemaking process would place the effective date of
these measures beyond the expiration date of the suspension, which
would mean that these operations could resume without the benefit of
the new safety measures being in place. Therefore, BOEMRE believes that
the delay associated with notice and comment has the potential to harm
worker and public health and safety and the environment, and further
justifies the immediate implementation of this interim final rule to
all OCS drilling operations. To act otherwise has the potential to risk
worker and environmental protection with inadequate regulatory
coverage.
BOEMRE is cognizant of the fact that the Secretary has the ability
to extend the suspension of operations covered by his July 12, 2010,
decision, or to apply the suspension to additional operations on the
OCS. Immediate application of the safety measures in this interim final
rule, however, will improve the reliability of well control systems,
thereby allowing all oil and gas operations on the OCS to proceed in a
more safe and environmentally sound manner.
BOEMRE believes that much of the oil and gas industry is already
well informed of the general provisions in this interim final rule,
most of which were identified in the Safety Measures Report.
Information gathered by BOEMRE in advance of this rulemaking indicates
that BOP equipment manufacturers, drilling contractors, and operators
are already working to address the recommendations. Establishing these
requirements via an interim final rule will allow these entities to
make
[[Page 63356]]
informed financial and operational decisions earlier.
As previously noted, these regulations were developed without the
benefit of the conclusive findings from the ongoing investigations into
the root causes of the explosions and fire on the Deepwater Horizon. In
the future, based on the comments we receive on this rule and the
additional findings of ongoing investigations, BOEMRE may issue
additional regulations or amendments to these regulations that will be
intended to further increase the safety of offshore oil and gas
operations.
VI. Section-By-Section Discussion of Requirements in the Interim Final
Rule
Documents Incorporated by Reference (Sec. 250.198)
Code of Federal Regulations, Title 30--MINERAL RESOURCES
BOEMRE is revising the title of Chapter II to, ``CHAPTER II--BUREAU
OF OCEAN ENERGY MANAGEMENT, REGULATION AND ENFORCEMENT, DEPARTMENT OF
THE INTERIOR.'' On June 18, 2010, the Secretary of the Interior changed
the name of the Minerals Management Service (MMS) to the Bureau of
Ocean Energy Management, Regulation and Enforcement (BOEMRE). This rule
updates the heading of Chapter II in Title 30, Volume 2, of the Code of
Federal Regulations to reflect this change.
Paragraph (a)(3) was added to clarify that the documents
incorporated by reference into the regulations are requirements. In the
National Technology Transfer and Advancement Act of 1995, Congress
directed Federal agencies to use technical standards that are developed
or adopted by voluntary consensus standards bodies. In Sec. 250.198,
BOEMRE incorporates by reference many consensus technical standards
including recommended practices, code requirements, and specifications.
The effect of incorporating these standards into Federal regulations is
confirmed in regulations issued by the Office of the Federal Register
(1 CFR 51.9(b)), which requires agencies to inform the user that an
incorporated publication is a requirement.
When BOEMRE incorporates a document by reference, any
recommendations in the document will be interpreted as requirements,
unless otherwise specified. For example, this section incorporates API
documents that recommend certain actions using the word should. In the
Foreword to its recommended practices, API explains that the word shall
indicates that the recommended practice has universal applicability to
the specific activity, while the word should denotes a recommended
practice where a safe comparable alternative practice is available.
Despite this explanation, for API documents incorporated by reference
into this part, the terms should and shall mean must. For example, API
RP 53, sections 17.10, 17.11, 17.12, 18.10, 18.11, and 18.12, are
currently incorporated by reference in Sec. 250.446(a). By adding
paragraph (a)(3) to this interim final rule, which explains that the
words should and shall both mean must, BOEMRE clarifies to the
operators that they must follow all of the provisions of these API RP
53 sections.
Paragraph (h)(79) was added to this section and incorporates by
reference API RP 65--Part 2, Isolating Potential Flow Zones During Well
Construction, First Edition, May 2010. This document contains best
practices for zone isolation in wells to prevent annular pressure and/
or flow through or past pressure-containment barriers that are
installed and verified during well construction. Barriers that seal
wellbore and formation pressures or flows may include temporary
pressure containment barriers like hydrostatic head pressure during
cement curing, and permanent ones such as mechanical seals, shoe
formations, and cement. Other well construction (well design, drilling,
leak-off tests, etc.,) practices that may affect barrier sealing
performance are addressed along with methods to help ensure positive
effects or to minimize any negative ones. The incorporation by
reference of API RP 65--Part 2 addresses the Safety Measures Report
recommendation II.B.3.7: Enforce Tighter Primary Cementing Practices.
The citations for API RP 53 in Sec. 250.198(h)(63) were updated to
include the requirements in Sec. 250.516 and new Sec. 250.617.
A consensus standard indicates acceptance and recognition across
the industry that this technology is feasible. For example, in its
recommended practice publications, including API RP 65--Part 2 and API
RP 53, API explains that its publications are intended to facilitate
the broad availability of proven, sound engineering, and operating
practices. The recommended practices are created with input from oil
and gas operators, drilling contractors, service companies,
consultants, and regulators; therefore, the recommended practices
reflect an agreement that the specified practices and technologies are
available and appropriate. Even though the development of a standard
does not represent a 100% agreement by the task group members, the
process provides a means for industry and regulatory bodies to develop
protocols for the highly specialized equipment and procedures used in
offshore oil and gas work. BOEMRE would not have the proper resources
to develop information included in standards on its own (e.g.
deepwater, High Pressure, High Temperature). BOEMRE regulatory program
benefits from using the expertise in industry on offshore operations
through the standards development process. Furthermore, in the National
Technology Transfer and Advancement Act of 1995, Congress directed
Federal agencies to use technical standards that are developed or
adopted by voluntary consensus standards bodies (http://standards.gov/standards_gov/nttaa.cfm).
When a copyrighted technical industry standard is incorporated by
reference into our regulations, BOEMRE is obligated to observe and
protect that copyright. BOEMRE provides members of the public with Web
site addresses where these standards may be accessed for viewing--
sometimes for free and sometimes for a fee. The decision to charge a
fee is decided by organizations developing the standard.
For the convenience of the viewing public who may not wish to
purchase these documents, they may be inspected at the Bureau of Ocean
Energy Management, Regulation and Enforcement, 381 Elden Street, Room
3313, Herndon, Virginia 20170; phone: 703-787-1587; or at the National
Archives and Records Administration. For information on the
availability of this material, call 202-741-6030, or go to: http://www.archives.gov/federal_register/code_of_federal_regulations/ibr_locations.html.
These documents will continue to be made available to the public
for viewing when requested. Specific information on where these
documents can be inspected or purchased can be found at Sec. 250.198,
Documents incorporated by reference.
In addition, the API has decided to provide free online public
access to 160 key industry standards, including a broad range of safety
standards once changes to the API website are complete. The standards
represent almost one-third of all API standards and will include all
that are safety-related or have been incorporated into Federal
regulations. The API will make these standards will be available online
for review and hardcopies and printable versions will continue to be
available for purchase. You may view or purchase
[[Page 63357]]
these API documents at: http://www.api.org/.
What must my casing and cementing programs include? (Sec. 250.415)
In this section, BOEMRE added a new paragraph (f) requiring the
operator to include in its APD an evaluation of the best practices
identified in API RP 65--Part 2, Isolating Potential Flow Zones During
Well Construction. We revised paragraphs (c), (d), and (e) to
accommodate the new paragraph. Incorporating this document by reference
will help ensure operators use best practices when designing their
casing and cementing programs and will help ensure the integrity of the
well, decreasing the risk of a loss of well control. Operators must
submit a written description of their evaluation to BOEMRE that
includes the mechanical barriers and cementing practices the operators
will use for each casing string. Operators must exercise due diligence
in understanding the variables involved when planning the casing and
cementing program.
The API RP 65--Part 2 addresses mechanical barriers in section 3. A
mechanical barrier, as defined by this document, is a verifiable seal
achieved by mechanical means between two casing strings or a casing
string and the borehole that isolates all potential flowing zones at or
below the wellhead, BOP, or diverter. The use of downhole mechanical
barriers is complementary to properly executed cementing and not a
replacement. The applications of subsurface mechanical barriers must be
chosen with care.
The API RP 65--Part 2, section 4, addresses cementing practices and
factors affecting cementing. This section requires that casing and
cementing programs address many of the key drilling issues that affect
the quality of a primary cementing operation. Section 4 includes the
best practices for the factors that must be considered and addresses
the interrelationship between drilling operations and cementing
success. BOEMRE is requiring operators to document how they evaluated
these best practices, to ensure operators consider them while
developing their casing and cementing programs.
BOEMRE believes that this is an appropriate document to incorporate
by reference. The key to successful use of this document for OCS
cementing operations is implementation. The regulations will require
that the operator address the document during the preparation of the
APD and describe the cementing practices and barriers used for casing
string. Including this information on the APD will help assure best
practices are used for a particular operation. Incorporating this
document will not address all issues associated with cementing
practices; however, doing so gives the agency the ability to evaluate
best cementing practices on a case by case basis. Additional cementing
requirements may be identified as results of the many investigations of
the Deepwater Horizon event but until then BOEMRE believes this is the
best approach to requiring best cementing practices. These additions
will allow BOEMRE to confirm that well construction is based on a
complete evaluation of all critical factors (including mechanical
barriers and cementing practices) involved in a casing and cementing
program. This new requirement addresses Safety Measures Report
recommendation II.B.3.7: Enforce Tighter Primary Cementing Practices.
What must I include in the diverter and BOP descriptions? (Sec.
250.416)
In this section, paragraph (d) was revised to include the
submission of a schematic of all control systems, including primary
control systems, secondary control systems, and pods for the BOP
system. This requirement applies to both surface and subsea BOP
systems. This will provide documentation for all control systems to
BOEMRE. The location of the controls must be included. Secondary
control systems include, but are not limited to, the following: ROV
intervention panels located on the BOP, autoshear and deadman systems,
power sources of each system, back up power sources, and acoustic
systems.
In this section, paragraph (e) was revised to require the operator
to submit independent third party verification and supporting
documentation that shows the blind-shear rams installed in the BOP
stack are capable of shearing any drill pipe in the hole under maximum
anticipated surface pressure, as recommended in the Safety Measures
Report and included in NTL No. 2010-N05. This requirement applies to
both surface and subsea BOP systems. The benefit of an independent
third party is that it provides an objective and technically-informed
review to properly verify capabilities of the blind-shear rams.
Requiring independent third party verification and information about
the blind-shear rams will help ensure that the appropriate shear rams
are installed in the BOP. The documentation must include test results
and calculations of shearing capacity of all pipe to be used in the
well including correction for maximum anticipated surface pressure.
Shearing capability tests can be performed on the drill pipe that
requires the highest shear pressure. The operator must include a
discussion on how the drill pipe used during the shear test required
the highest shear pressure and was the most difficult to shear. The
interim final rule will codify the section, ``Verification that Blind-
shear Rams Will Shear Pipe in the Hole'' in NTL No. 2010-N05.
Paragraph (f) was added to require independent third party
verification that a subsea BOP stack is designed for the specific
equipment used on the rig. The independent third party must verify that
the subsea BOP stack is compatible with the specific well location,
well design, and well execution plan. Information showing that the
shear rams are appropriate for the project must be included. The
independent third party must also verify that the subsea BOP stack has
not been damaged or compromised from previous service. Last, the
independent third party must verify that a subsea BOP stack will
operate in the conditions in which it will be used. This will ensure
that all factors of drilling with subsea BOPs are considered when
choosing well control equipment. This requirement applies to all APDs
that request to use a subsea BOP stack. It applies to completion,
workover, or abandonment operations. The interim final rule will codify
the section, ``BOP Compatibility Verification for All Wells'' in NTL
No. 2010-N05.
Paragraph (g) was added and describes the criteria and
documentation for an independent third party that must be submitted
with the APD to BOEMRE for review. This is to ensure that the
independent third party is capable of providing both an objective and a
technically informed validation of the subjects being reviewed. The
independent third party must be a technical classification society; an
API licensed manufacturing, inspection, certification firm; or licensed
professional engineering firm capable of providing the verifications
required under this part. The independent third party must not be the
original equipment manufacturer. The original equipment manufacturer is
excluded because it has a financial interest in equipment being
evaluated. Equipment manufacturers that do not have a financial
interest in the equipment being evaluated may serve as an independent
third party certifier if otherwise qualified. The operator must provide
evidence to BOEMRE that the firm it is using is reputable;
specifically, the firm or its employees hold appropriate licenses to
perform the verification in the appropriate jurisdiction, the firm
carries industry-
[[Page 63358]]
standard levels of professional liability insurance, and the firm has
no record of violations of applicable law. Prior to any shearing ram
tests or inspections, the operator must also notify the District
Manager 24 hours in advance. The operator must ensure an official
representative of BOEMRE access to the location to potentially witness
any testing or inspections, or to verify information submitted to
BOEMRE. This approach to document the qualifications of the independent
third party is the same approach being followed for the documenting the
independent third party required by NTL No. 2010-N05.
The revised requirements in paragraph (d) address Safety Measures
Report recommendation I.B.5: Secondary Control System Requirements and
Guidelines. The requirements in paragraph (e) address Safety Measures
Report recommendation I.C.7: Develop New Testing Requirements. The new
requirements in paragraph (f) address Safety Measures Report
recommendation I.A.2: Order BOP Equipment Compatibility Verification
for Each Floating Vessel and for Each New Well. The criteria required
for the independent third party are also addressed in NTL No. 2010-N05.
These requirements will help ensure that the rig operator has the
appropriate control systems in place, aiding the rig operator's ability
to regain control of a well in the event of a loss of well control.
What additional information must I submit with my APD? (Sec. 250.418)
In this section, new paragraph (h) was added that requires the
operator to submit certifications of their casing and cementing program
signed by a Registered Professional Engineer. The Registered
Professional Engineer must be registered in a State in the United
States but does not have to be a specific discipline. Certification by
a Registered Professional Engineer will increase the likelihood that
the casing and cementing program has been properly designed and
implemented, and will provide adequate well control. The Registered
Professional Engineer will certify that there will be at least two
independent tested barriers across each flow path during well
completion activities. The Registered Professional Engineer will also
certify that the casing and cementing design is appropriate for the
purpose for which it is intended under expected wellbore conditions.
The operator must submit this certification to BOEMRE along with the
APD. Paragraph (g) was revised to accommodate new paragraph (h). The
interim final rule will codify requirements addressed under the
section, ``Well Design and Construction for All Wells'' in NTL No.
2010-N05. These requirements for additional barriers, and the
certification of the cement design, will decrease the likelihood of a
blowout. These requirements apply to new wells, sidetracks, bypasses,
or deepened wells.
In this section, a new paragraph (i) was added requiring the
operator to submit a description of qualifications of any independent
third party. Operators must formally notify BOEMRE of their independent
third parties. The description must be submitted with the APD and may
include the following:
1. Name and address of the individual or organization;
2. Size and type of the organization or corporation;
3. Previous experience as a Certified Entity, Certified
Verification Agent (CVA), or similar third-party representative;
4. Experience in design, fabrication, or installation of BOPs and
related equipment;
5. Technical capabilities (including professional certifications
and organizational memberships) of the third party or the primary staff
to be associated with the certifying functions for the specific
project;
6. In-house availability of, or access to, appropriate technology
(i.e., computer modeling programs and hardware, testing materials, and
equipment);
7. Ability to perform and effectively manage certifying functions,
inspections, and tests for the specific project considering current
resource availability;
8. Previous experience with regulatory requirements and procedures;
9. Evidence that the third party is not owned or controlled by the
designer, manufacturer, or supplier of the system or its subsystems to
be inspected or tested under regulations applicable to this device or
any manufacturer of similar equipment or material;
10. The level of work to be performed by the third party; and
11. A list of documents and certifications expected to be furnished
to BOEMRE by the third party.
The new requirements address the Safety Measures Report
recommendation II.B.1.3: New Casing and Cement Design Requirements: Two
Independent Tested Barriers and recommendation I.C.7: Develop New
Testing Requirements.
What well casing and cementing requirements must I meet? (Sec.
250.420)
In this section, new paragraph (a)(6) was added that requires the
operators to submit certification of their casing and cementing program
signed by a Registered Professional Engineer (see discussion under
section 250.418, above). The Registered Professional Engineer must be
registered in a State in the United States. As mentioned previously,
the Registered Professional Engineer does not have to be from a
specific discipline, but must be capable of reviewing and certifying
that the casing design is appropriate for the purpose for which it is
intended under expected wellbore conditions. The Registered
Professional Engineer will certify that there will be at least two
independent tested barriers, including one mechanical barrier, across
each flow path during well completion activities. The Registered
Professional Engineer will also certify the casing and cementing design
is appropriate for the purpose for which it is intended under expected
wellbore conditions. The operator must submit this certification to
BOEMRE along with the APD. The operator should not deviate from the
certified procedure; if the operator deviates from the certified
procedures, they must contact the appropriate District Manager.
Paragraphs (a)(4) and (a)(5) were revised to accommodate the new
paragraph (a)(6). The interim final rule will codify the section,
``Well Design and Construction for All Wells'' in NTL No. 2010-N05. The
certification of the casing and cementing program will help ensure that
the appropriate program is used for the well and decrease the
likelihood of a blowout.
A new paragraph (b)(3) was also added, requiring the operator to
install dual mechanical barriers in addition to cement for the final
casing string (or liner if it is the final string), to prevent flow in
the event of a failure in the cement. These may include dual float
valves, or one float valve and a mechanical barrier. The operator must
document the installation of the dual mechanical barriers and submit
this documentation to BOEMRE 30 days after installation. References to
days in this rule are always in calendar days. The interim final rule
will codify the section, ``Well Design and Construction for All Wells''
in NTL No. 2010-N05.
These new requirements will help ensure that the best casing and
cementing design will be used for a specific well. The new requirements
in paragraphs (a)(6) and (b)(3) address the Safety Measures Report
recommendation II.B.1.3: New Casing
[[Page 63359]]
and Cement Design Requirements: Two Independent Tested Barriers.
What are the requirements for pressure testing casing? (Sec. 250.423)
This section was reorganized to accommodate new requirements: the
current regulations were redesignated as paragraph (a) and new
paragraphs (b) and (c) were added. Paragraph (b) requires the operator
to perform a pressure test on the casing seal assembly to ensure proper
installation of casing or liner in the subsea wellhead or liner hanger.
This must be done for intermediate and production casing strings or
liner. To install casing in the subsea wellhead, the operator runs and
lands the casing hanger tool, cements the casing, latches the casing
hanger in place, and finally pressure sets and tests the seal. This
test ensures that the casing hanger latching mechanism, or lockdown
mechanism, is engaged, ensuring the integrity of the casing. The
operator must submit the test procedures and criteria used for a
successful test with the APD to BOEMRE for approval. The operator must
record the test results and make the results available to BOEMRE upon
request. As required in Sec. 250.466, records for well operations must
be kept onsite while drilling activities continue. The interim final
rule will codify requirements addressed under the section, ``Well
Design and Construction for All Wells'' in NTL No. 2010-N05.
Paragraph (c) requires the operator to perform a negative pressure
test on all wells to ensure proper installation of casing for the
intermediate and production casing strings. The operator must submit
the procedures and criteria for a successful test with the APD for
approval. The operator must record the test results and make available
to BOEMRE upon request. A negative pressure test will help ensure that
the casing, along with the cement, provides a seal.
The new requirements in this section will help ensure proper casing
installation and evaluate the integrity of the casing and cement. The
new requirements in this section address the Safety Measures Report
recommendations II.B.1.3: New Casing and Cement Design Requirements:
Two Independent Tested Barriers; II.B.2.5: New Casing Installation
Procedures; and II.B.2.6: Develop Additional Requirements or Guidelines
for Casing Installation.
What are the requirements for a subsea BOP system? (Sec. 250.442)
This section requires that when drilling with a subsea BOP system,
the BOP system must be installed before drilling below the surface
casing. The table in this section outlines the requirements, including:
a. The minimum number of each type of BOP,
b. dual-pod control systems,
c. accumulator operations,
d. ROV intervention,
e. maintaining an ROV and ROV crew training,
f. autoshear and deadman capability and optional acoustic system
for dynamically positioned rigs,
g. accidental disconnect avoidance,
h. BOP control panel labels,
i. BOP management system,
j. personnel training for BOP equipment,
k. marine riser removal, and
l. avoiding ice scour.
Paragraph (a) was revised to clarify that the blind-shear rams must
be capable of shearing any drill pipe in the hole under maximum
anticipated surface pressures. When drilling with a subsea BOP stack,
the operator must have a minimum of four remote controlled
hydraulically operated BOPs. The BOPs must include one annular
preventer, two sets of pipe rams, and one set of blind-shear rams.
The requirement in paragraph (b) to have an operable dual-pod
control system and the requirement in paragraph (c) to follow API RP
53, Section 13.3, Accumulator Volumetric Capacity, were not revised.
The operator must meet the volume capacities for all subsea
accumulators and must meet the closing times specified in API RP 53,
Section 13.3.5, Accumulator Response Time: The BOP control system must
be capable of closing each ram BOP in 45 seconds or less; closing time
must not exceed 60 seconds for annular BOPs; operating response time
for choke and kill valves must not exceed the minimum observed ram BOP
close response time; and time to unlatch the LMRP must not exceed 45
seconds.
Requirements related to ROV intervention in paragraph (d) were
added. The subsea BOP stack must be equipped with ROV intervention
capability to operate one set of pipe rams and one set of blind-shear
rams as well as unlatch the LMRP. The BOP-ROV interface must allow
sufficient volume to actuate all required functions. This requirement
will ensure that the dedicated ROV has the capacity to close the BOP
functions and secure the well in sufficient time during a well control
event. The interim final rule will codify the section, ``ROV Hot Stab
Function Testing of the ROV Intervention Panel'' in NTL No. 2010-N05.
In paragraph (e), the operator is required to maintain an ROV and
have a trained ROV crew on each floating drilling rig on a continuous
basis. The crew must be trained in the operation of the ROV. The
training must include simulator training on stabbing into an ROV
intervention panel on a subsea BOP stack. This requirement will help
provide assurance that a properly trained crew is available for use
during an emergency situation.
Requirements related to autoshear and deadman systems in paragraph
(f) were added. Autoshear, deadman, and acoustic systems are all
emergency systems. Dynamically positioned rigs must have autoshear and
deadman systems. Autoshear system is defined as a safety system that is
designed to automatically shut in the wellbore in the event of an
unplanned disconnect of the LMRP. When the autoshear is armed, a
disconnect of the LMRP closes the shear rams. Deadman system is defined
as a safety system that is designed to automatically close the wellbore
in the event of a simultaneous absence of hydraulic supply and signal
transmission capacity in both subsea control pods. Both autoshear and
deadman are considered ``rapid discharge'' systems. Dynamically
positioned rigs may also use an acoustic system. An acoustic signal
transmission may be used as an emergency backup that controls critical
BOP functions. However, BOEMRE believes additional evaluation is
necessary to determine the reliability of acoustic signal transmission
as a mandatory backup control system. Industry, academics and other
stakeholders have raised concerns about how the differences in water
temperatures between water layers (deepwater thermocline) will affect
the transmission of the acoustic signal to the BOP stack when installed
in deepwater. Similar concerns were raised about how different
salinities between water layers, noise from a wild well, or other
subsea noise may interfere with the successful transmission of the
acoustic signals to the BOP stack. Further investigation of these
concerns is needed before deciding to require the installation of an
acoustic backup control system. The interim final rule will codify the
section, ``Secondary Control System Requirements and Guidelines for
Subsea BOP Stacks'' in NTL No. 2010-N05.
In paragraph (g), the operator is required to have operational or
physical barrier(s) on BOP control panels to prevent accidental use of
disconnect functions. The operator must incorporate enable buttons on
control panels to ensure two-handed operation for all critical
functions. The new requirements in this paragraph will
[[Page 63360]]
reduce the chances of an accidental disconnect by requiring two
separate actions to activate all critical functions.
In paragraph (h), the operator is required to clearly label all
control panels for the subsea BOP system. The operator must include all
BOP controls such as hydraulic control panels and ROV interface on the
BOP. The new requirements in this paragraph will help to ensure that
the correct function is executed. The labeling of all functions will
also assist in proper usage in an emergency situation.
In paragraph (i), the operator is required to develop and use a
management system for operating the BOP system. This includes guidance
to prevent accidental or unplanned disconnects of the system. This
management system must include written procedures for operating the BOP
stack and LMRP, and minimum knowledge requirements for personnel
authorized to operate and maintain BOP components. A copy of these
written procedures should be maintained on the drilling rig and in
other readily accessible locations. These procedures must be made
available to all relevant personnel. The new requirements in this
paragraph will help to ensure that the correct function is executed in
an emergency situation.
Paragraph (j) requires the operator to establish minimum
requirements for personnel authorized to operate critical BOP
equipment. This training must include deepwater well control theory and
practice in accordance with 30 CFR part 250, subpart O, and a
comprehensive knowledge of BOP hardware and control systems.
Paragraphs (k) and (l) are currently required, but were reformatted
into the table. Paragraph (k) requires the operator to displace the
fluid in the riser with seawater before removing the marine riser;
while conducting this operation, the operator must maintain sufficient
hydrostatic pressure on the well or take other suitable precautions to
compensate for the reduction in pressure to maintain well control.
Paragraph (l) requires that when drilling in an ice-scour area, the BOP
stack must be installed in a glory hole (a depression deep enough that
the equipment is protected).
These requirements help ensure enhanced operability of subsea BOP
systems. These requirements will also help to ensure that the proper
personnel are trained to have a comprehensive knowledge of well control
equipment, maintain well control equipment, operate essential well
control equipment, and manage a well control situation.
The ROV intervention capability and autoshear and deadman
requirements in this section address Safety Measures Report
recommendation I.B.5: Secondary Control System Requirements and
Guidelines, and recommendation I.B.6: New ROV Operating Capabilities.
The new requirements also meet Safety Measures Report recommendation
II.A.1: Establish Deepwater Well-Control Procedure Guidelines.
What are the BOP maintenance and inspection requirements? (Sec.
250.446)
Paragraph (a) of this section was changed to require the operator
to document the maintenance and inspections of their BOP system. The
requirement that BOP maintenance and inspections must meet or exceed
the provisions of Sections 17.10 and 18.10, Inspections; Sections 17.11
and 18.11, Maintenance; and Sections 17.12 and 18.12, Quality
Management; described in API RP 53, Recommended Practices for Blowout
Prevention Equipment Systems for Drilling Wells (incorporated by
reference as specified in Sec. 250.198) was not changed. The operator
must document the procedures used, record the results, and make the
results available to BOEMRE upon request. The operator must maintain
the records on the rig for 2 years or from the date of the last major
inspection, whichever is longer.
The BOP maintenance, inspections, and quality management are
essential components to ensuring BOP integrity and operability.
According to API RP 53, Section 17.10 (surface BOPs) and Section 18.10
(subsea BOPs), operators must perform a between-well inspection, a
visual inspection of flexible choke and kill lines, and a major 3-5
year inspection. According to API RP 53, Section 17.11 (surface BOPs)
and Section 18.11 (subsea BOPs), operators are required to maintain BOP
manuals, connections, replacement parts, torque requirements, equipment
storage, lubricants and hydraulic fluids, weld repairs, and mud/gas
separators. According to API RP 53, Section 17.12 (surface BOPs) and
Section 18.12 (subsea BOPs), operators are required to have a planned
maintenance system, with equipment identified, tasks specified, and the
time intervals between tasks stated. Records of maintenance performed
and repairs made must be retained on file at the rig site or readily
available.
The interim final rule will codify the section, ``BOP Inspection,
Maintenance, and Repair for All Wells'' in NTL No. 2010-N05. The
documentation for BOP maintenance, repairs, and inspections meet the
Safety Measures Report recommendation I.B.5: Secondary Control System
Requirements and Guidelines.
What additional BOP testing requirements must I meet? (Sec. 250.449)
New paragraphs (j) and (k) were added and paragraphs (h) and (i)
were revised to accommodate the new paragraphs. New paragraph (j)
requires the testing of ROV intervention functions on a subsea BOP
stack. The ROV intervention functions must be tested during the stump
test. This test must include ensuring that the hot stabs are function
tested and are capable of actuating one set of pipe rams and one set of
blind-shear rams, as well as unlatching the LMRP. The operator must
also test at least one set of rams during the initial test on the
seafloor. The BOP-ROV interface must allow sufficient volume to actuate
all required functions. The operator must document the test results and
make them available to BOEMRE upon request. This will help to ensure
that the ROV and hot stabs are capable of actuating the BOP rams and
LMRP disconnect. The interim final rule will codify requirements
addressed under the section, ``ROV Hot Stab Function Testing of the ROV
Intervention Panel'' in NTL No. 2010-N05; which required testing of ROV
intervention functions during the stump test. The interim final rule
will also require function testing during the initial test on the
seafloor. A successful test will help ensure that the ROV and BOP are
capable of operating as designed under conditions at water depth.
New paragraph (k) requires function testing of the autoshear and
deadman systems on the BOP stack during the stump test. The operator
must submit the testing procedures for these requirements with the APD
or APM for BOEMRE approval. This should include the sequence of BOP
functions that will activate when the autoshear and deadman systems are
triggered. These requirements will help to ensure that a well is
secured in an emergency situation, loss of power, or accidental
disconnect, preventing the possible loss of well control. The ROV
intervention capability and autoshear and deadman requirements in this
section address Safety Measures Report recommendation I.B.5: Secondary
Control System Requirements and Guidelines and recommendation I.C.7:
Develop New Testing Requirements.
[[Page 63361]]
What must I do in certain situations involving BOP equipment or
systems? (Sec. 250.451)
A new item was added to the table, requiring the operator to
perform a full pressure test when the blind-shear rams or casing shear
rams are used in an emergency. Following activation of the blind-shear
rams or casing shear rams, in which pipe or casing is sheared during a
well control situation, the operator must retrieve and physically
inspect the BOP and conduct a full pressure test of the BOP stack,
after the situation is fully controlled. This will help ensure the
integrity of the BOP and that the BOP will fully function and hold
pressure after the event. If rams, sealing elements, or other equipment
are damaged, they must be replaced or repaired.
The interim final rule will codify the section, ``BOP Inspection
Testing after Well Control Event for All Wells'' in NTL No. 2010-N05.
The tests required after a well control event in this section addresses
Safety Measures Report recommendation I.C.7: Develop New Testing
Requirements.
What safe practices must the drilling fluid program follow? (Sec.
250.456)
A new paragraph (j) was added, the current (j) was redesignated to
paragraph (k) and paragraph (i) was revised to accommodate the new
paragraph. The new paragraph (j) requires approval from the District
Manager before displacing kill-weight drilling fluid from the wellbore.
The operator must submit with the APD or APM the reasons for displacing
the kill-weight drilling fluid and provide detailed step-by-step
written procedures describing how the operator will safely displace
these fluids. The step-by-step displacement procedures must address the
following:
1. Number and type of independent barriers that are in place for
each flow path;
2. Tests to ensure integrity of independent barriers;
3. BOP procedures used while displacing kill weight fluids; and
4. Procedures to monitor fluids entering and leaving the wellbore.
These new requirements better ensure that well control is not
compromised when displacing kill-weight fluid out of the wellbore. The
requirement to submit procedures for kill-weight drilling fluid
displacement in this section addresses Safety Measures Report
recommendation II.A.2: New Fluid Displacement Procedures.
Blowout prevention equipment. (Sec. 250.515)
This section added requirements of Sec. 250.442 in subpart D, Oil
and Gas Drilling Operations, to the requirements for well completion
operations using a subsea BOP stack.
Blowout preventer system tests, inspections, and maintenance. (Sec.
250.516)
Paragraph (d)(8) was added to require tests for ROV intervention
functions during the stump test. Paragraph (d)(9) was added to require
a function test of the autoshear and deadman system. Paragraph (d)(6)
was revised to accommodate the new paragraphs. This section adds the
requirements of Sec. 250.449 in subpart D, Oil and Gas Drilling
Operations, to the requirements for well completion operations using a
subsea BOP stack. The interim final rule will require successful
testing of both systems during the stump test. Successful tests will
ensure the autoshear and deadman system are operating as designed. A
function test of the deadman system is also required during the initial
test on the seafloor. Successful testing the deadman system during the
initial test on the seafloor will ensure the system is capable of
operating as designed under conditions at water depth.
Paragraphs (g) and (h) were revised to expand and clarify the
requirements for inspections and maintenance. The BOP maintenance,
inspections, and quality management are essential to BOP operability.
This section adds requirements of Sec. 250.446 in subpart D, Oil and
Gas Drilling Operations, to the requirements for well completion
operations using a subsea BOP stack. The operator must maintain the
records on the rig for 2 years or from the date of the last major
inspection, whichever is longer.
The documentation for BOP maintenance, repairs, and inspections
meets the Safety Measures Report recommendation I.B.5: Secondary
Control System Requirements and Guidelines and recommendation I.C.7:
Develop New Testing Requirements.
Blowout prevention equipment. (Sec. 250.615)
This section added requirements of Sec. 250.442 in subpart D, Oil
and Gas Drilling Operations, to the requirements for well workover
operations using a subsea BOP stack.
Blowout preventer system testing, records, and drills. (Sec. 250.616)
Paragraph (h)(1) was added to require tests for ROV intervention
functions during the stump test. Paragraph (h)(2) was added to require
a function test of the autoshear and deadman systems. Paragraph (h)(3)
was added to require the use of water to stump test a subsea BOP
system. This section adds the requirements of Sec. 250.449 in subpart
D, Oil and Gas Drilling Operations, to the requirements for well
workover operations using a subsea BOP stack. The interim final rule
will require testing of both systems during the stump test. Successful
tests will ensure the autoshear and deadman systems are operating as
designed. A function test of the deadman system is also required during
the initial test on the seafloor. Testing the deadman system during the
initial test on the seafloor will help ensure the system is capable of
operating as designed under conditions at water depth.
What are my BOP inspection and maintenance requirements? (Sec.
250.617)
This section was added to apply the requirements of Sec. 250.446
in subpart D, Oil and Gas Drilling Operations, to the requirements for
well workover operations using a subsea BOP stack.
Definitions. (Sec. 250.1500)
BOEMRE revised the definition of well control by creating separate
definitions for the terms well servicing and well completion/well
workover.
A new definition for deepwater well control was added. The rule
adds deepwater well control throughout subpart O as one of the subjects
for employee and contract personnel training. This clarification helps
ensure that rig personnel are trained in deepwater well control and the
specific duties, equipment, and techniques associated with deepwater
drilling.
What are my general responsibilities for training? (Sec. 250.1503)
In this section, new paragraph (b) was added and current paragraphs
(b) and (c) were redesignated as (c) and (d). The operator is required
to ensure that employees and contract personnel are trained in
deepwater well control when conducting operations with a subsea BOP
stack. They must have a comprehensive knowledge of deepwater well
control equipment, practices, and theory. This clarification of
existing requirements addresses Safety Measures Report recommendation
II.A.1: Establish Deepwater Well-Control Procedure Guidelines.
[[Page 63362]]
What information must I submit before I permanently plug a well or
zone? (Sec. 250.1712)
In this section, new paragraph (g) was added and paragraphs (e) and
(f)(14) were revised to accommodate the new paragraph. New paragraph
(g) requires operators to submit certification by a Registered
Professional Engineer of the well abandonment design and procedures.
The Registered Professional Engineer must be registered in a State in
the United States. The Registered Professional Engineer does not have
to be a specific discipline, but must be capable of reviewing and
certifying that the casing design is appropriate for the purpose for
which it is intended under expected wellbore conditions. The Registered
Professional Engineer will certify that there will be at least two
independent tested barriers, including one mechanical barrier, across
each flow path during well abandonment activities. The Registered
Professional Engineer will also certify that the plug meets the
requirements in the table in Sec. 250.1715. This will help ensure the
integrity of the well. The operator must submit this certification
along with the APM. The operator should not deviate from the certified
procedure; if the operator deviates from the certified procedures, they
must contact the appropriate District Manager. The interim final rule
will codify the section, ``Well Design and Construction for All Wells''
in NTL No. 2010-N05. This new requirement addresses Safety Measures
Report recommendation II.B.1.3: New Casing and Cement Design
Requirements: Two Independent Tested Barriers.
If I temporarily abandon a well that I plan to re-enter, what must I
do? (Sec. 250.1721)
In this section, new paragraph (h) was added to require operators
to submit certification by a Registered Professional Engineer of the
well abandonment design and procedures. The Registered Professional
Engineer does not have to be a specific discipline. The Registered
Professional Engineer must be registered in a State in the United
States. As mentioned previously, the Registered Professional Engineer
does not have to be a specific discipline, but must be capable of
reviewing and certifying that the casing design is appropriate for the
purpose for which it is intended under expected wellbore conditions.
The Registered Professional Engineer will certify that there will be at
least two independent tested barriers, including one mechanical
barrier, across each flow path during well abandonment activities. This
will help ensure the integrity of the well. The operator must submit
this certification to BOEMRE along with the APM, as required in Sec.
250.1712 and is responsible for ensuring that the approved well
abandonment design and procedures are followed. The operator should not
deviate from the certified procedure, if the operator deviates from the
certified procedures they must contact the appropriate District
Manager. Paragraphs (e) and (g)(3) were revised to accommodate the new
paragraph. The interim final rule will codify requirements addressed
under the section, ``Well Design and Construction for All Wells'' in
NTL No. 2010-N05. This new requirement addresses Safety Measures Report
recommendation II.B.1.3: New Casing and Cement Design Requirements: Two
Independent Tested Barriers.
VII. Additional Recommendations in the Safety Measures Report Not
Covered in This Interim Final Rule
As discussed previously, this interim final rule incorporates some,
but not all items from the Safety Measures Report. The following tables
specifically identify which measures from the Safety Measures Report
are not covered in the interim final rule. BOEMRE anticipates it will
be able to address these measures in notice and comment rulemakings in
the future.
Items in the Safety Measures Report that are not covered in this
interim final rule, and which BOEMRE anticipates addressing either in
the near future, or at a later time after further review and analysis,
are as follows:
Items for Future Rulemaking
------------------------------------------------------------------------
Number Recommendation
------------------------------------------------------------------------
I.A.3............................. Develop Formal Equipment
Certification Requirements.
I.B.4............................. New Blind Shear Ram Redundancy
Requirement.
II.B.3.8.......................... Develop Additional Requirements or
Guidelines for Evaluation of Cement
Integrity.
II.C.9............................ Increase Federal Government Wild-
Well Intervention Capabilities.
II.C.10........................... Study Innovative Wild-Well
Intervention, Response Techniques,
and Response Planning.
III.C.2........................... Adopt Safety Case Requirements for
Floating Drilling Operations on the
OCS.
III.C.4........................... Study Additional Safety Training and
Certification Requirements.
------------------------------------------------------------------------
There are also certain items which, although they are included in
this interim final rule, BOEMRE anticipates expanding upon in the
future. BOEMRE is specifically considering additional rulemaking
activity concerning the following:
Items Included in This Rule Under Consideration for Expansion
------------------------------------------------------------------------
Number Recommendation
------------------------------------------------------------------------
I.B.5............................. Secondary Control System
Requirements and Guidelines.
I.B.6............................. New ROV Operating Capabilities.
II.A.1............................ Establish Deepwater Well-Control
Procedure Guidelines.
II.B.1.4.......................... Study Formal Personnel Training
Requirements for Casing and
Cementing Operations.
II.B.2.6.......................... Develop Additional Requirements or
Guidelines for Casing Installation.
II.B.3.7.......................... Enforce Tighter Primary Cementing
Practices.
------------------------------------------------------------------------
Additionally, as discussed further, BOEMRE is examining a variety
of other well control issues related to OCS drilling to determine how
to improve future safety on the OCS in light of the Deepwater Horizon
event.
BOEMRE recognizes that this interim final rule does not fully
address all issues associated with OCS drilling operations, although it
is a critical step. We anticipate future rulemakings as we learn more
about the causes of the Deepwater Horizon event and other issues
associated with deepwater drilling operations. Future rulemakings will
be based on recommendations in the Safety Measures Report that require
further development, the results of the joint USCG-BOEMRE
investigation, other investigations and inquiries, and findings from
technology-focused research led by DOI strike teams and interagency
workgroups. Some of the issues that are addressed by this rulemaking,
such as cementing and casing design, will be considered for additional
rulemaking in the future. We will consider additional measures, after
we have more thoroughly studied these issues and assessed the best
approaches.
BOEMRE has identified the following issues as likely topics for
both near-term and future rulemakings:
Well Control Issues
While the content of these future rulemakings will depend in part
on the findings of the various investigations, BOEMRE anticipates that
future rules will focus on well control issues. More specifically this
will include:
1. Cementing and casing--BOEMRE anticipates examining the need for
additional cement evaluation
[[Page 63363]]
procedures and training needs for personnel involved in cementing and
casing operations, and intends to incorporate findings as appropriate
from the investigations related to the Deepwater Horizon event.
2. Fluid displacement--BOEMRE intends to further evaluate the
effectiveness of new fluid displacement requirements to determine if it
needs to establish different or enhanced fluid displacement procedures.
3. BOPs--BOEMRE anticipates rulemaking to address BOP
recommendations resulting from the joint BOEMRE and United States Coast
Guard investigation of the Deepwater Horizon event. Rulemaking will
also likely address the requirement to have two sets of blind shear
rams as recommended in the Safety Measures Report and discussed
previously. Rulemakings will also likely consider requirements for
casing shear rams, minimum number of pipe rams, second annular
preventer for subsea BOP stacks, and electronic BOP logs. Another area
mentioned in the Safety Measures Report is the need for periodic
certification of the BOP stack or specific BOP components. BOEMRE
wishes to undertake additional research on how these certifications
should be done and how often they should occur.
4. Secondary control systems and ROVs--Future rulemaking may
address autoshear and deadman requirements for all rigs with subsea BOP
stacks, enhanced ROV intervention capability, and subsea accumulator
volumes to ensure fast closure of BOPs and choke and kill lines. The
need for effective tertiary control systems, such as an acoustic
system, will also be examined and addressed as appropriate.
5. Wild-well intervention techniques--BOEMRE will conduct research
on this topic and evaluate the progress industry has made to establish
deepwater wild-well intervention as it moves forward with rulemaking on
wild well intervention.
6. Industry training--BOEMRE will investigate safety training
requirements for deepwater drilling operations and determine the
appropriate manner to regulate the training of personnel.
7. Oil spill response--BOEMRE anticipates future rulemaking to
address the capture and disposition of oil released from a deepwater
well blowout at the seafloor.
8. Organization and safety management--The Safety Measures Report
recommended that the DOI evaluate the need to require all or part of
the International Association of Drilling Contractors' Health, Safety,
and Environmental Case Guidelines for Mobile Drilling Units. BOEMRE
will evaluate the guidelines and determine how they will best fit with
SEMS regulations that are being considered by BOEMRE for final
publication in a separate rulemaking. BOEMRE published a notice of
proposed rulemaking on SEMS requirements on June 17, 2009 (74 FR
28639).
Technical Consensus Standards
BOEMRE is aware that various organizations which support the
offshore oil and gas industry are also studying the possible causes of
the Deepwater Horizon event. Based on their findings, these
organizations may make recommendations to their members on practices to
increase the safety of offshore oil and gas operations in general with
specific recommendations related to deepwater drilling operations.
BOEMRE is reviewing the following subjects:
1. API Documents Concerning Cementing Practices
In Sec. 250.198 of this interim final rule, BOEMRE incorporates
API RP 65--Part 2, Isolating Potential Flow Zones During Well
Construction, which summarizes best practices and addresses basic
issues associated with cementing practices. The API has additional
documents that address cementing practices in more detail.
2. Discussion of Additional Specifications and Recommended Practices
API Spec 16A: Specification for Drill-Through Equipment
This standard specifies requirements for performance, design,
materials, testing and inspection, welding, marking, handling, storing,
and shipping of drill-through equipment used for drilling for oil and
gas. It also defines service conditions in terms of pressure,
temperature, and wellbore fluids for which the equipment will be
designed. This standard is applicable to, and establishes requirements
for, the following specific equipment: ram BOPs; ram blocks, packers,
and top seals; annular BOPs; annular packing units; hydraulic
connectors; drilling spools; adapters; loose connectors; and clamps.
API Spec 16D: Specification for Control Systems for Drilling Well
Control Equipment and Control Systems for Diverter Equipment
This specification provides design standards for systems used to
control the BOP and associated valves that control well pressure during
drilling operations. Diverter control systems are included in this
specification because they are included in the BOP control system. This
specification addresses the following categories: control systems for
surface BOP stacks, control systems for subsea BOP stacks, discrete
hydraulic control systems for subsea BOP stacks, electro-hydraulic/
multiplex control systems for subsea BOP stacks, control systems for
diverter equipment, auxiliary equipment control systems and interfaces,
emergency disconnect sequenced systems (EDS), backup systems, and
special deepwater/harsh environment features.
Certain standards in API Spec. 16D are of particular interest.
These include optional sections--5.7 Emergency Disconnect Sequenced
Systems (EDS), 5.8 Backup Control Systems, and 5.9 Special Deepwater/
Harsh Environment Features. The EDS systems are required for floating
drilling rigs in order to quickly disconnect the riser in the event of
an inability to maintain rig position within a prescribed watch circle.
Backup Control Systems include standards on acoustic systems, ROV
control systems, LMRP recovery systems, and backup power supply. The
Deepwater/Harsh Environment features give specifications for autoshear
and deadman systems.
API Spec 17D: Specification for Subsea Wellhead and Christmas Tree
Equipment
This specification was formulated to provide for the availability
of safe, dimensionally, and functionally interchangeable subsea
wellhead, mudline, and tree equipment. The technical content provides
requirements for performance, design, materials, testing, inspection,
welding, marking, handling, storing, and shipping. Critical components
are those parts having a requirement specified in this document. Rework
and repair of used equipment are beyond the scope of this
specification.
API Recommended Practice 17H; ISO 13628-8: Remotely Operated Vehicle
(ROV) Interfaces on Subsea Production Systems
This recommended practice gives functional requirements and
guidelines for ROV interfaces on subsea production systems for the
petroleum and natural gas industries. It is applicable to both the
selection and use of ROV interfaces on subsea production equipment, and
provides guidance on design as well as the operational requirements for
maximizing the potential of standard equipment and design principles.
The auditable information for subsea systems this document offers
allows
[[Page 63364]]
interfacing and actuation by ROV-operated systems, while it identifies
issues that have to be considered when designing interfaces on subsea
production systems. The framework and detailed specifications set out
enable the user to select the correct interface for a specific
application.
API Recommended Practice 53: Recommended Practices for Blowout
Prevention Equipment Systems for Drilling Wells
This recommended practice provides guidance for installation and
testing of surface and subsea BOP equipment systems. This equipment
system consists of a BOP, choke and kill lines, marine riser, and
auxiliary equipment. The primary function of a BOP equipment system is
to confine wellbore fluids, provide a means to add fluids, and allow
controlled volumes to be withdrawn from the wellbore. This recommended
practice also addresses diverter systems.
Other Items for Consideration
BOEMRE is also studying the following issues:
1. Following the certification of the BOP to meet the one-time
requirement of NTL No. 2010-N05, frequency and conditions for
recertification requirements.
2. Requirements for BOP equipment and other components of the BOP
stack such as control panels, communication pods, accumulator systems,
and choke and kill lines and the adequacy of API Spec 16A.
3. Standardization of the BOP-ROV interface to improve intervention
capabilities.
4. Issues related to requiring a subsea isolation device that is
independent of the BOP stack that is capable of operating critical
functions that will shut in a well in emergency situations.
Procedural Matters
Regulatory Planning and Review (Executive Order (E.O.) 12866)
This interim final rule is a significant rule as determined by the
Office of Management and Budget (OMB) and is subject to review under
E.O. 12866.
1. This rule will have an annual effect of $100 million or more on
the economy. The following discussion summarizes a detailed cost-
benefit analysis that is available on http://www.Regulations.gov. Use
the keyword/ID ``BOEM-2010-0034'' to locate the docket for this rule.
Various events around the world as well as the US over the years
demonstrate that catastrophic oil spills can and do occur. The costs
associated with such spills can be tremendous. As a matter of policy,
BOEMRE has decided that any reasonable measures to reduce the risks of
another catastrophic spill occurring on the OCS should be put in place
and enforced. The requirements included in this rulemaking are such
measures. They were identified in the May 27, 2010 report, Increased
Safety Measures for Energy Development on the Outer Continental Shelf,
for which the draft recommendations were peer-reviewed by seven experts
identified by the National Academy of Engineering., or identified by
industry or academic experts in materials presented to BOEMRE. While
the estimated costs of this rulemaking, as reflected in the compliance
costs of the enumerated requirements of approximately $180 million per
year, have a strong foundation and are based on surveys of public and
industry sources, quantification of the benefits is uncertain. The
benefits are represented by the avoided costs of a catastrophic spill,
which are estimated under the stipulated scenario as being $16.3
billion per spill avoided. These regulations will reduce the likelihood
of another blowout and associated spill, but the risk reduction
associated with the specific provisions of this rulemaking cannot be
quantified because there are many complex factors that affect the risk
of a blowout event. As noted by the Secretary of the Interior in his
July 12 decision memo suspending certain drilling activities, drilling
accidents can have a profound, devastating impact on the economic and
environmental health of a region. The measures codified in this rule
will reduce the likelihood of such an event in the future, at a cost
that is not prohibitive, and therefore this rulemaking is justified.
The purpose of a benefit-cost analysis is to provide policy makers
and others with detailed information on the economic consequences of
the regulatory requirements. The benefit-cost analysis for this rule
was conducted using a scenario analysis. The benefit-cost analysis
considers a regulation designed to reduce the likelihood of a
catastrophic oil spill. The costs are the compliance costs of imposed
regulation. If another catastrophic oil spill is prevented, the
benefits are the avoided costs associated with a catastrophic oil spill
(e.g., reduction in expected natural resource damages owing to the
reduction in likelihood of failure).
Avoided cost is an approximation of the ``true'' benefits of
avoiding a catastrophic oil spill. A benefits transfer approach is used
to estimate the avoided costs. The benefits transfer method estimates
economic values by transferring existing benefit calculations from
studies already completed for another location or issue to the case at
hand. Accordingly, none of the avoided costs used for a hypothetical
catastrophic spill rely upon, or should be taken to represent, our
estimate for the BPDH event commencing on April 20, 2010.
Three new requirements account for virtually all of the compliance
costs imposed by this regulation (1) use of dual mechanical barriers in
addition to cement barriers in the final casing string to prevent
hydrocarbon flow in the event of cement failure, (2) application of
negative pressure tests to all intermediate and the production casing
strings to ensure their proper installation, and (3) maintenance of
standby ROV capability to close BOP rams and testing that capability
after the BOP has been installed on the sea floor. BOEMRE estimates
that these three requirements will impose compliance costs of
approximately $174 million per year, representing 95 percent of the
total annual compliance costs of $183 million associated with this
rulemaking. These cost estimates were developed by BOEMRE based on
public data sources and confidential information provided by several
offshore operators and drilling companies.
On the benefit side, the avoided costs for a hypothetical deepwater
blowout resulting in a catastrophic oil spill are estimated to be about
$16.3 billion (in 2010 dollars). Most of this amount derives from
detailed cleanup estimates developed using damage costs per barrel
measures found in historical spill data (from all sources including
pipeline, tanker, and shallow water as well as deepwater wells) and
from aggregate damage measures contained in the legal settlement
documents for past spills applied to a catastrophic deepwater spill of
hypothetical size. The rest of the avoided cost amount represents the
private costs for blowout containment operations. In sum, three
components account for nearly the entire avoided spill cost total: (1)
Natural resource damage to habitat and creatures, (2) infrastructure
salvage and cleanup operations of areas soiled by oil, and (3)
containment and well-plugging actions plus lost hydrocarbons.
The estimate of compliance costs is somewhat uncertain. This is the
case primarily because the $183 million annual estimate is perhaps
higher than the actual costs that will be incurred by society from this
rule because industry is voluntarily undertaking some steps following
the BPDH event that overlap
[[Page 63365]]
those in this regulation. The Joint Industry Task Force draft
recommendations include use of mechanical barriers and negative
pressure tests. Voluntary action, perhaps spurred on as well by revised
liability expectations and increased insurance prospects, means the
incremental costs associated with these overlapping measures are not
truly imposed solely by the new regulations. Less incremental required
costs reduce the improvement in reliability necessary for expected
benefits to cover the cost of complying with the new regulations. On
the benefit side, the total avoided cost estimate of $16.3 billion
(representing a measure of expected benefits for avoiding a future
catastrophic oil spill) is highly uncertain because of the limited
historical data upon which to judge the cost of failure, the disparity
between the damages associated with spills of different sizes,
locations, and season of occurrence, and owing to the fact that the
measure employed reflects only those outlays that we have been able to
calculate based primarily upon factors derived from past oil spills.
Possible losses from human health effects or reduced property values
have not been quantified in this analysis. Moreover, the likelihood of
a future blow out leading to a catastrophic oil spill is difficult to
quantify because of limited historical data on catastrophic offshore
blowouts.
Benefit-Cost Result: Based on the occurrence of only a single
catastrophic blowout, the number of GOM deepwater wells drilled
historically (4,123), and the forecasted future drilling activity in
the GOM (160 deepwater wells per year), the baseline risk of a
catastrophic blowout is estimated to be about once every 26 years.
Combining the baseline likelihood of occurrence with the cost of a
hypothetical spill implies that the expected annualized spill cost is
about $631 million ($16.3 billion once in 26 years, equally likely in
any 1 year). To balance the $183 million annual cost imposed by these
regulations with the expected benefits, the reliability of the well
control system needs to improve by about 29 percent ($183 million/$631
million). We have found no studies that evaluate the degree of actual
improvement that could be expected from dual mechanical barriers,
negative pressure tests, and a seafloor ROV function test. We request
comment with supporting evidence on the reliability improvement likely
from these new provisions.
2. This interim final rule will not adversely affect competition or
State, local, or tribal governments or communities.
3. This interim final rule will not create a serious inconsistency
or otherwise interfere with an action taken or planned by another
agency.
4. This interim final rule will not alter the budgetary effects of
entitlements, grants, user fees, or loan programs or the rights or
obligations of their recipients.
5. This interim final rule will not raise novel legal or policy
issues arising out of legal mandates, the President's priorities, or
the principles set forth in E.O. 12866.
Regulatory Flexibility Act: Initial Regulatory Flexibility Analysis
Given the emergency nature of these rules, BOEMRE has not yet
prepared a detailed Initial Regulatory Flexibility Analysis for this
rule; however, BOEMRE intends to publish a supplemental Initial
Regulatory Flexibility Analysis in the near future which will examine
the impact of this regulation on small entities in greater detail than
provided below. BOEMRE continues to be interested in all potential
impacts of the interim final rule on small entities and welcomes
comments on issues related to such impacts. These comments will assist
BOEMRE in conducting further analysis than provided below regarding the
economic impact of these regulations on small entities, as well as an
opportunity to examine regulatory alternatives that can accomplish
BOEMRE's safety goals at a lower cost to small entities.
This rulemaking affects lessees, operators of leases and drilling
contractors on the OCS; thus this rule directly impacts small entities.
This could include about 130 active Federal oil and gas lessees and
more than a dozen drilling contractors and their suppliers. Small
entities that operate under this rule are coded under the Small
Business Administration's North American Industry Classification System
(NAICS) codes 211111, Crude Petroleum and Natural Gas Extraction, and
213111, Drilling Oil and Gas Wells. For these NAICS code
classifications, a small company is one with fewer than 500 employees.
Based on these criteria, approximately 70 percent of companies
operating on the OCS (91) are considered small companies. Therefore,
BOEMRE has determined that this proposed rule will have an impact on a
substantial number of small entities.
The ownership share of deepwater leases for small entities is
estimated to only be 12 percent. While a larger percentage of the oil
service industry supporting the deepwater operators are small
businesses, the lessees that hire and direct these support businesses
will bear the burden of this rule. Small companies hold 55 percent of
shallow water leases but a smaller portion of the costs of these
regulations will affect drilling operations in shallow water.
This rule will affect every new well on the OCS. Tighter regulatory
standards for drilling operations and the increased cost of meeting
these requirements as a result of regulations for extra tests and well
standards will now be required. We estimate that this rulemaking will
impose a recurring cost of $183 million each year for drilling OCS
wells. Every operator and drilling contractor both large and small must
meet the same criteria for drilling operations regardless of company
size. However, the overwhelming share of the cost imposed by these
regulations will fall on companies drilling deepwater wells, which are
predominately the larger companies. In fact, 90 percent of the total
costs will be imposed on deepwater lessees and operators where small
businesses only hold 12 percent of the leases. Less than 10 percent of
the total costs will apply to shallow water leases where a 55 percent
lease ownership share is held by small companies. Furthermore, these
compliance costs only impact drilling operations. Drilling costs are
only a share of the total costs incurred by a company operating on the
OCS.
Nonetheless, small companies as both lease-holders, and contractors
serving lease-holders, will bear meaningful costs under these
regulations. Of the annual $183 million in annual cost imposed by the
rule, we estimate that the $20 million will apply to small businesses
in deepwater and $9 million in shallow water. In total we estimate that
$29 million or 15.8 percent of these regulations' cost will be borne by
small businesses.
Fiscal year 2009 aggregate annual Gulf of Mexico OCS oil and gas
revenues were $31.3 billion. Using the same percentages of leases held
as a proxy for production value in deep and shallow water, we estimate
that 74 percent ($23.3 billion) of the OCS revenues are ultimately
received by large companies and 26 percent ($8.1 billion) by small
companies. As a share of fiscal year 2009 revenues this interim final
rule would cost approximately 0.67 percent of OCS revenue for large
companies and only 0.36 ($0.029/$8.1) percent for small companies.
Even though this rule may not have a significant economic impact on
small businesses, alternatives to ease impacts on small business were
considered. One alternative is to exempt small businesses from the
requirements of this interim final rule. A second alternative is to
delay the implementation timelines
[[Page 63366]]
to comply with the regulation. Both of these alternatives are being
rejected by BOEMRE for this interim final rule because of the
overriding need to reduce the chance of a catastrophic blowout event.
We do not believe it is responsible for a regulator to compromise the
safety of offshore personnel and the environment for any entity
including small businesses. Offshore drilling is highly technical and
can be hazardous, any delay may increase the interim risk of OCS
drilling operations.
Small Business Regulatory Enforcement Fairness Act
This interim final rule is a major rule under the Small Business
Regulatory Enforcement Fairness Act (5 U.S.C. 801 et seq.). This
interim final rule:
a. Will have an annual effect on the economy of $100 million or
more. This rule will affect every new well on the OCS, and every
operator, both large and small must meet the same criteria for well
construction regardless of company size. This rulemaking may have a
significant economic effect on a substantial number of small entities
and the impact on small businesses will be analyzed more thoroughly in
an Initial Regulatory Flexibility Analysis. While large companies will
bear the majority of these costs, small companies as both leaseholders
and contractors supporting OCS drilling operations will be affected.
Considering the new requirements for redundant barriers and new
tests, we estimate that this rulemaking will add an average of about
$1.42 million to each new deepwater well drilled and completed with a
MODU, $170 thousand for each new deepwater well drilled with a platform
rig, and $90 thousand for each new shallow water well. While not an
insignificant amount, we note this extra recurring cost is less than 2
percent of the cost of drilling a well in deepwater and around 1
percent for most shallow water wells.
b. Will not cause a major increase in costs or prices for
consumers, individual industries, Federal, State, or local government
agencies, or geographic regions. The impact on domestic deepwater
hydrocarbon production as a result of these regulations is expected to
be negative, but the size of the impact is not expected to materially
impact the world oil markets. The deepwater GOM is an oil province and
the domestic crude oil prices are set by the world oil markets.
Currently there is sufficient spare capacity in OPEC to offset a
decrease in GOM deepwater production that could occur as a result of
this rule. Therefore, the increase in the price of hydrocarbon products
to consumers from the increased cost to drill and operate on the OCS is
expected to be minimal. However, more of the oil for domestic
consumption may be purchased from overseas markets because the cost of
OCS oil and gas production will rise relative to other sources of
supply. This shift would contribute negatively to our balance of trade.
c. Will not have significant adverse effects on competition,
innovation, or the ability of U.S.-based enterprises to compete with
foreign-based enterprises.
d. May have adverse effects on employment, investment, and
productivity. A meaningful increase in costs as a result of more
stringent regulations and increased drilling costs may result in a
reduction in the pace of deepwater drilling activity on marginal
offshore fields, and reduce investment in our domestic energy resources
from what it otherwise would be, thereby reducing employment in OCS and
related support industries. The additional regulatory requirements in
this rulemaking will increase drilling costs and add to the time it
takes to drill deepwater wells. The resulting reduction in
profitability of drilling operations may cause some declines in related
investment and employment. A typical deepwater well drilled by a MODU
may cost $90-$100 million. The added cost of these regulations for a
deepwater well is expected to be about $1.42 million; this is less than
a 2 percent decrease in productivity for drilling a deepwater well as a
result of these regulations.
e. Accommodations for small business have not been made to avoid
the risk of compromising the safety and environmental protections
addressed in this rulemaking. Small businesses actively invest in
offshore operations, owning a 12 percent interest in deepwater leases,
most often as a minority partner. These regulations will make it more
expensive for all interest holders in OCS leases, and we do not expect
a disproportionate impact on small businesses. However, we anticipate
that the costs in this rule may contribute to one or more of the
following:
1. Reduce the small business ownership share in individual
deepwater leases.
2. Cause small businesses to target their investments more in
shallow water leases.
3. Cause small businesses to target their investments more in
onshore oil and gas operations or other natural resources.
4. Small businesses may choose to invest or partner in overseas
natural resource operations.
f. There are many small businesses that support offshore oil and
gas drilling operations including service, supply, and consulting
companies. They will also be affected by this rule. Because we can
reasonably anticipate an overall decrease in deepwater drilling
activity due to the increased cost and regulatory burden, some
businesses that support drilling operations may experience reduced
business activity. Some small businesses may therefore decide to focus
more on shallow water or other oil and gas offshore provinces overseas.
g. There are some small businesses that may benefit from this
rulemaking. Companies that are involved with inspecting and certifying
this equipment, as well as consulting companies specializing in safety
and offshore drilling, could see long-term growth.
Unfunded Mandates Reform Act of 1995
This rule will impose an unfunded mandate on State, local, or
tribal governments or the private sector of more than $100 million per
year. The rule will not have a significant or unique effect on State,
local, or tribal governments or the private sector. A statement
containing the information required by the Unfunded Mandates Reform Act
(2 U.S.C. 1501 et seq.) is not required.
Takings Implication Assessment (E.O. 12630)
Under the criteria in E.O. 12630, this rule does not have
significant takings implications. The rule is not a governmental action
capable of interference with constitutionally protected property
rights. A Takings Implication Assessment is not required.
Federalism (E.O. 13132)
Under the criteria in E.O. 13132, this rule does not have
federalism implications. This rule will not substantially and directly
affect the relationship between the Federal and State governments. To
the extent that State and local governments have a role in OCS
activities, this rule will not affect that role. A Federalism
Assessment is not required.
Civil Justice Reform (E.O. 12988)
This rule complies with the requirements of E.O. 12988.
Specifically, this rule:
a. Meets the criteria of section 3(a) requiring that all
regulations be reviewed to eliminate errors and
[[Page 63367]]
ambiguity and be written to minimize litigation; and
b. Meets the criteria of section 3(b)(2) requiring that all
regulations be written in clear language and contain clear legal
standards.
Consultation With Indian Tribes (E.O. 13175)
Under the criteria in E.O. 13175, we have evaluated this rule and
determined that it has no substantial effects on federally recognized
Indian tribes.
Paperwork Reduction Act (PRA)
This rule contains a collection of information that was submitted
to and approved by OMB under the Paperwork Reduction Act of 1995 (44
U.S.C. 3501 et seq.). The rule expands existing requirements, as well
as adds new requirements in 30 CFR part 250, subparts D, E, and F. The
OMB approved these requirements and their respective burden hours under
an emergency request, OMB Control Number 1010-0185, 44,731 hours
(expiration 04/30/2011). We will be accepting comments on the
information collection (IC) aspects and burdens of this rulemaking
until 60 days after October 14, 2010.
The title of the collection of information for this rule is 30 CFR
part 250, Increased Safety Measures for Oil and Gas Drilling, Well-
Completion, and Well-Workover Operations.
Respondents primarily are the Federal OCS lessees and operators.
The frequency of response varies depending upon the requirement.
Responses to this collection of information are mandatory. BOEMRE will
protect proprietary information according to the Freedom of Information
Act (5 U.S.C. 552), its implementing regulations (43 CFR part 2), 30
CFR 250.197, Data and information to be made available to the public or
for limited inspection, and 30 CFR part 252, OCS Oil and Gas
Information Program. Even though this rulemaking becomes effective
immediately, BOEMRE will be accepting comments, see the DATES section,
including the IC aspects of the rulemaking. See the ADDRESSES section
for how to submit comments.
As discussed earlier in the preamble, this interim final rulemaking
is a revision to various sections of the 30 CFR part 250 regulations
that will amend drilling regulations in subparts D, E, F, O, and Q.
This includes requirements that will implement various safety measures
that pertain to drilling operations. The information collected will
ensure sufficient redundancy in the BOPs; promote the integrity of the
well and enhance well control; and facilitate a culture of safety
through operational and personnel management. This rule will promote
human safety and environmental protection.
Under Sec. 250.198, this section lists all of the documents
incorporated by reference in the 30 CFR part 250 regulations. This
rulemaking revises this section to include the new 30 CFR part 250
document we are incorporating and the document already incorporated
that we are updating. Under the PRA (5 CFR part 1320), information and
recordkeeping produced during customary and usual business activities
are excluded from agency IC burdens. Information submitted or reported
to the Federal Government that goes beyond these practices does count
as burdens and is required to have OMB approval under the PRA. We
consider all of the activities and operations performed in accordance
with the documents incorporated by reference involved in this
rulemaking to be customary and usual business activities because they
are consensus standards developed by working task force groups. These
groups are comprised of subject matter experts from the industry and
government in the following fields: Blowout preventer equipment,
cementing, and well design. Any information and recordkeeping produced
during the conduct of operations or activities performed under those
standards, therefore, do not count as new or additional IC burdens.
The rulemaking clarifies requirements, but does not change the hour
burdens in 30 CFR part 250, subpart O (1010-0128, expiration 11/30/
2012). This rulemaking also references, but does not change, the
requirements and burdens in 30 CFR part 250, subpart Q (1010-0142,
expiration 11/30/2010). However, the rule does change and add new
requirements to those already approved for 30 CFR part 250, subparts D,
E, and F, as explained in the following paragraphs.
The current regulations on Oil and Gas Drilling Operations and
associated IC are located in 30 CFR part 250, subpart D. The OMB
approved the IC burden of the current subpart D regulations under
control number 1010-0141 (expiration 11/30/2011). This interim final
rule expands the current regulatory requirements and adds new
requirements that pertain to subsea and surface BOPs, well casing and
cementing, secondary intervention, unplanned disconnects,
recordkeeping, well completion, and well plugging (+24,144 burden
hours).
The current regulations on Oil and Gas Well-Completion Operations
and associated IC are located in 30 CFR part 250, subpart E. The OMB
approved the IC burden of the current subpart E regulations under
control number 1010-0067 (expiration 12/31/2010). This interim final
rule adds new regulatory requirements to this subpart that pertain to
subsea and surface BOPs, secondary intervention, and well-completions
(+4,669 burden hours).
The current regulations on Oil and Gas Well-Workover Operations and
associated IC are located in 30 CFR part 250, subpart F. The OMB
approved the IC burden of the current subpart F regulations under
control number 1010-0043 (expiration 12/31/2010). This interim final
rule adds new regulatory requirements to this subpart that pertain to
subsea and surface BOPs, secondary intervention, unplanned disconnects,
and well-workers (+15,918 burden hours).
When this rulemaking becomes effective, the additional 30 CFR part
250, subparts D, E, and F paperwork burdens will be incorporated into
their respective primary collections; 1010-0141, 1010-0067, and 1010-
0043, respectively.
The following table provides a breakdown of the new burdens.
[[Page 63368]]
----------------------------------------------------------------------------------------------------------------
Reporting and Annual
Citation 30 CFR 250 recordkeeping Hour burden Average number of burden
requirement annual responses hours
----------------------------------------------------------------------------------------------------------------
Subpart D
----------------------------------------------------------------------------------------------------------------
408, 409; 410-418; 420(a)(6); Apply for permit to 6.................. MMS-123........... 4,200
423(b)(3), (c)(1); 449(j), drill/revised APD that 700...............
(k)(1); plus various references includes any/all
in subparts A, B, D, E, H, P, Q. supporting
documentation/evidence
[test results,
calculations,
verifications,
procedures, criteria,
qualifications, etc.]
and requests for
various approvals
required in subpart D
(including Sec. Sec.
250.423, 424, 427, 432,
442(c), 447, 448(c),
449(j), (k), 451(g),
456(a)(3), (f), 460,
490(c)(1), (2)) and
submitted via Form MMS-
123 (Application for
Permit to Drill).
416(g)(2)....................... Provide 24 hour advance 10 mins............ 6 notifications... 1
notice of location of
shearing ram tests or
inspections; allow
BOEMRE access to
witness testing,
inspections and
information
verification.
420(b)(3)....................... Submit dual mechanical 30 mins............ 700 submissions... 350
barrier documentation
after installation.
-----------------------------------------
423(a).......................... Request approval of Burden covered under 1010-0141. 0
other pressure casing
test pressures per
District Manager.
-----------------------------------------
423(b)(4), (c)(2)............... Perform pressure casing 30 mins............ 700 drilling ops x 1,750
test; document results 5 tests per ops =
and make available to 3,500 tests.
BOEMRE upon request.
-----------------------------------------
442(c).......................... Request alternative Burden covered under 1010-0141. 0
method for the
accumulator system.
-----------------------------------------
442(h).......................... Label all functions on 30 mins............ 30 panels......... 15
all panels.
442(i).......................... Develop written 4.................. 30 procedures..... 120
procedures for
management system for
operating the BOP stack
and LMRP.
-----------------------------------------
442(j).......................... Establish minimum Burden covered under 1010-0128. 0
requirements for
authorized personnel to
operate BOP equipment;
require training.
-----------------------------------------
446(a).......................... Document BOP maintenance 1.................. 105 rigs.......... 105
and inspection
procedures used; record
results of BOP
inspections and
maintenance actions;
maintain records for 2
years; make available
to BOEMRE upon request.
-----------------------------------------
449; 450; 467................... Function test annular Burden covered under 1010-0141. 0
and rams; document
results every 7 days
between BOP tests
(biweekly). Note: part
of BOP test.
-----------------------------------------
449(j)(2)....................... Test all ROV 10................. 110 wells......... 1,100
intervention functions
on your subsea BOP
stack; document all
test results; make
available to BOEMRE
upon request.
449(k)(2)....................... Function test autoshear 30 mins............ 110 wells......... 55
and deadman on your
subsea BOP stack during
stump test; document
all test results; make
available to BOEMRE
upon request.
-----------------------------------------
456(i).......................... Record results of Burden covered under 1010-0141. 0
drilling fluid tests in
drilling report.
-----------------------------------------
456(j).......................... Submit detailed step by 2.................. 110 wells......... 220
step procedures
describing displacement
of fluids with your APD/
APM [this submission
obtains District
Manager approval].
460; 465; 449(j), (k)(1); Submit revised plans, 4.................. MMS-124........... 16,228
516(d)(8), (d)(9); 616(h)(1), changes, well/drilling 4,057.............
(2); plus various references in records, procedures,
subparts A, D, E, F, H, P, and certifications that
Q. include any/all
supporting
documentation etc.,
submitted on Form MMS-
124 (Application for
Permit to Modify).
-------------------------------------------------------------------------------
Subtotal.................... ........................ ................... 9,458 responses... 24,144
----------------------------------------------------------------------------------------------------------------
Subpart E
----------------------------------------------------------------------------------------------------------------
516(d)(8)....................... Submit test procedures Burden covered under 1010-0141. 0
with your APM for
approval.
-----------------------------------------
516(d)(8)....................... Function test ROV 10................. 110 wells......... 1,100
interventions on your
subsea BOP stack;
document all test
results; make available
to BOEMRE upon request.
[[Page 63369]]
516(d)(9)....................... Function test autoshear 30 mins............ 1,048 completions. 524
and deadman on your
subsea BOP stack during
stump test; document
all test results; make
available to BOEMRE
upon request.
516(g)(l)....................... Document the procedures 7 days x 12 hrs/day 105 rigs/once 2,940
used for BOP = 84. every 3 years =
inspections; record 35 per year.
results; maintain
records for 2 years;
make available to
BOEMRE upon request.
-----------------------------------------
516(g)(2)....................... Request alternative Burden covered under 1010-0067. 0
method to inspect a
marine riser.
-----------------------------------------
516(h).......................... Document the procedures 1.................. 105 rigs.......... 105
used for BOP
maintenance; record
results; maintain
records for 2 years;
make available to
BOEMRE upon request.
-------------------------------------------------------------------------------
Subtotal.................... ........................ ................... 1,298 responses... 4,669
----------------------------------------------------------------------------------------------------------------
Subpart F
----------------------------------------------------------------------------------------------------------------
616(h)(l)....................... Test all ROV 10 hours........... 1,226 workovers... 12,260
intervention functions
on your subsea BOP
stack; document all
test results; make
available to BOEMRE
upon request.
616(h)(2)....................... Function test autoshear 30 mins............ 1,226 workovers... 613
and deadman on your
subsea BOP stack during
stump test; document
all test results; make
available to BOEMRE
upon request.
617(a)(l)....................... Document the procedures 7 days x 12 hrs/day 105 rigs/once 2,940
used for BOP = 84. every 3 years =
inspections; record 35 per year.
results; maintain
records for 2 years;
make available to
BOEMRE upon request.
-----------------------------------------
617(a)(2)....................... Request approval to use Burden covered under 1010-0067. 0
alternative method to
inspect a marine riser.
-----------------------------------------
617(b).......................... Document the procedures 1.................. 105 rigs.......... 105
used for BOP
maintenance; record
results; maintain
records for 2 years;
make available to
BOEMRE upon request.
-------------------------------------------------------------------------------
Subtotal.................... ........................ ................... 2,592 responses... 15,918
----------------------------------------------------------------------------------------------------------------
Subpart Q
----------------------------------------------------------------------------------------------------------------
1712(f), (g); 1721(h)........... Submit with your APM, Burden covered under 1010-0141. 0
archaeological and
sensitive biological
features; Registered
Professional Engineer
certification.
1721(e)......................... Identify and report USCG requirements. 0
subsea wellheads,
casing stubs, or other
obstructions.
-------------------------------------------------------------------------------
Total....................... ........................ ................... 13,348 responses.. 44,731
----------------------------------------------------------------------------------------------------------------
BOEMRE plans to follow this interim final rule with a request for a
standard, 3-year approval by OMB. The request will be processed under
OMB's normal clearance procedures in accordance with the provisions of
OMB regulation 5 CFR 1320.10. To facilitate processing of the normal
clearance submission to OMB, BOEMRE invites the general public to
comment on: (1) Whether this collection of information is necessary for
the proper performance of BOEMRE's functions, including whether the
information has practical utility; (2) the accuracy of the estimates of
the burden of the information collection, including the validity of the
methodologies and assumptions used; (3) ways to enhance the quality,
utility, and clarity of the information to be collected; (4) ways to
minimize the burden of the information collection on respondents,
including through the use of automated collection techniques or other
forms of information technology; and (5) estimates of capital or start
up costs, and costs of operation, maintenance and purchase of services
to provide the information.
An agency may not conduct or sponsor, and you are not required to
respond to, a collection of information unless it displays a currently
valid OMB control number. The public may comment, at any time, on the
accuracy of the IC burden in this rule and may submit any comments to
the Department of the Interior; Bureau of Ocean Energy Management,
Regulation and Enforcement; Attention: Regulations and Standards
Branch; Mail Stop 4024; 381 Elden Street; Herndon, Virginia 20170-4817.
National Environmental Policy Act of 1969
We have prepared an environmental assessment to determine whether
this rule will have a significant impact on the quality of the human
environment under the National Environmental Policy Act of 1969. This
rule does not constitute a major Federal action significantly affecting
the quality of the human environment. A detailed statement under the
National Environmental Policy Act of 1969 is not required because we
reached a Finding of No Significant Impact. A copy of the Environmental
Assessment can be viewed at http://www.Regulations.gov (type in
``environmental assessment'' for
[[Page 63370]]
the document type and use the keyword/ID ``BOEM-2010-0034'').
Data Quality Act
In developing this rule, we did not conduct or use a study,
experiment, or survey requiring peer review under the Data Quality Act
(Pub. L. 106-554, app. C Sec. 515, 114 Stat. 2763, 2763A-153-154).
Effects on the Energy Supply (E.O. 13211)
This rule is a significant rule and is subject to review by the
Office of Management and Budget under E.O. 12866. The rule does have an
effect on energy supply, distribution, or use because its provisions
may delay development of some OCS oil and gas resources. The delay
stems from the extra drill time and cost imposed on new wells which
will somewhat slow exploration and development operations. We estimate
an average delay of 2 days and cost of $1.42 million for most deepwater
wells in the GOM.
Increased imports or inventory drawdowns should compensate for most
of the delay or reduction in domestic production. The recurring costs
imposed on new drilling by this rule are very small (2 percent)
relative to the cost of drilling a well in deepwater. In view of the
high risk-reward associated with deepwater exploration in general, we
do not expect this small regulatory surcharge from this rule to result
in meaningful reduction in discoveries. Thus, we expect the net change
in supply associated with this rule will cause only a slight increase
in oil and gas prices relative to what they otherwise would have been.
Normal volatility in both oil and gas market prices overshadow these
rule related price effects, so we consider this an insignificant effect
on energy supply and price.
Clarity of This Regulation
We are required by E.O. 12866, E.O. 12988, and by the Presidential
Memorandum of June 1, 1998, to write all rules in plain language. This
means that each rule we publish must:
a. Be logically organized;
b. Use the active voice to address readers directly;
c. Use clear language rather than jargon;
d. Be divided into short sections and sentences; and
e. Use lists and tables wherever possible.
If you feel that we have not met these requirements, send us
comments by one of the methods listed in the ADDRESSES section. To
better help us revise the rule, your comments should be as specific as
possible. For example, you should tell us the numbers of the sections
or paragraphs that you find unclear, which sections or sentences are
too long, the sections where you feel lists or tables would be useful,
etc.
Public Availability of Comments
Before including your address, phone number, email address, or
other personal identifying information in your comment, you should be
aware that your entire comment--including your personal identifying
information--may be made publicly available at any time. While you can
ask us in your comment to withhold your personal identifying
information from public review, we cannot guarantee that we will be
able to do so.
Appendix A
BOEMRE Response to the Deepwater Horizon Event and Resulting Oil Spill
I. Description
On April 20, 2010, the crew of the Transocean drilling rig
Deepwater Horizon was preparing to temporarily abandon BP's
discovery well at the Macondo prospect, 52 miles from shore in 4,992
feet of water in the GOM. An explosion and subsequent fire on the
rig caused 11 fatalities and several injuries. The rig sank 2 days
later, resulting in an uncontrolled release of oil that was declared
a spill of national significance.
II. Status of BOEMRE/USCG Joint Investigation
The DOI and USCG are undertaking a joint investigation into the
causes of the explosions and fire on the Deepwater Horizon. This
joint investigation includes members of BOEMRE and the USCG and
involves issuing subpoenas for documents and testimony, obtaining
expert analyses of data and reports, holding public hearings,
calling witnesses, and taking any other steps necessary to determine
the cause of the spill. The purpose of this joint investigation is
to develop conclusions about the cause and recommendations for
preventing a similar event. The facts collected at the public
hearings, along with the lead investigators' conclusions and
recommendations, will be forwarded to USCG Headquarters and BOEMRE
for approval. Once approved, the final investigative report will be
made available to the public and the media. The team has been given
9 months, from the date of the convening order (April 27, 2010), to
submit the final report.
III. DOI and BOEMRE actions
In response to the Deepwater Horizon event, DOI and BOEMRE have
taken several actions, as outlined below. Numerous other
investigations and reviews have been commenced, including an
investigation by the DOI Safety Oversight Board; an investigation by
the President's National Commission on the BP Deepwater Horizon Oil
Spill and Offshore Drilling; the USCG incident Specific Preparedness
Review; a review by the National Academy of Engineering; a review by
the U.S. Chemical Safety Board; and others. This Appendix addresses
only BOEMRE actions. These are as follows:
1. Issued a Joint Safety Alert with USCG on April 30, 2010.
2. Published the Safety Measures Report on May 27, 2010, at the
request of the President.
3. Issued National NTL No. 2010-N05, ``Increased Safety Measures
for Energy Development on the OCS,'' to implement the immediate
recommendations from the Safety Measures Report.
4. Issued National NTL No. 2010-N06, ``Information Requirements
for Exploration Plans, Development and Production Plans, and
Development Operations Coordination Documents on the OCS.''
5. Implemented Secretarial Decision dated July 12, 2010,
ordering the suspensions of drilling activities that use a subsea
BOP stack and drilling from floating facilities with a surface BOP
stack.
6. Held public meetings to collect information and views about
deepwater drilling safety reforms, blowout containment, and oil
spill response.
1. Joint USCG-BOEMRE Safety Alert
On April 30, 2010, USCG and BOEMRE issued a National Safety
Alert No. 2 concerning the Deepwater Horizon event and resulting oil
spill. BOEMRE and the USCG included the following safety
recommendations to operators and drilling contractors:
(1) Examine all well control equipment (both surface and subsea)
currently being used to ensure that it has been properly maintained
and is capable of shutting in the well during emergency operations.
Ensure that the ROV hot-stabs are function-tested and are capable of
actuating the BOP.
(2) Review all rig drilling/casing/completion practices to
ensure that well control contingencies are not compromised at any
point while the BOP is installed on the wellhead.
(3) Review all emergency shutdown and dynamic positioning
procedures that interface with emergency well control operations.
(4) Inspect lifesaving and firefighting equipment for compliance
with Federal requirements.
(5) Ensure that all crew members are familiar with emergency/
firefighting equipment, as well as participate in an abandon ship
drill. Operators are reminded that the review of emergency equipment
and drills should be conducted after each crew change out.
(6) Exercise emergency power equipment to ensure proper
operation.
(7) Ensure that all personnel involved in well operations are
properly trained and capable of performing their tasks under both
normal drilling and emergency well control operations.
2. Safety Measures Report
a. Summary
On April 30, 2010, the President ordered the Secretary of the
Interior to conduct a
[[Page 63371]]
thorough review of this event and to report, within 30 days, on
what, if any, additional precautions and technologies should be
required to improve the safety of oil and gas exploration and
production operations on the OCS. The Safety Measures Report was
presented to the President on May 27, 2010. A copy of the report is
available at: http://www.doi.gov/news/pressreleases/loader.cfm?csModule=security/getfile&PageID=33646.
The Safety Measures Report was developed without the benefit of
the findings from the ongoing investigations into the root causes of
the explosions and fire on the Deepwater Horizon and the resulting
oil spill. In the coming months, those investigations will likely
suggest refinements to some of this report's recommendations, as
well as additional safety measures.
The Safety Measures Report includes a history of OCS production,
spills, and blowouts; a review of the existing U.S. regulatory and
enforcement structure; a survey of other countries' regulatory
approaches; and a summary of existing BOEMRE-sponsored studies on
technologies that could reduce the risk of blowouts. The report
examines all aspects of drilling operations, including equipment,
procedures, personnel management, and inspections and verification
in an effort to identify safety and environmental protection
measures that would reduce the risk of a catastrophic event. In
particular, this report examines several issues highlighted by the
Deepwater Horizon event regarding operational and personnel safety
while conducting drilling operations in deepwater environments.
The Safety Measures Report includes a number of recommendations
to improve the safety of oil and gas drilling operations on the OCS.
These recommendations address:
Well-control and well abandonment operations;
Specific requirements for devices, such as BOPs and
their testing;
Industry practices;
Worker training;
Inspection protocol and operator oversight; and
The responsibility of the Department for safety and
enforcement.
The draft recommendations were peer reviewed by seven experts
identified by the National Academy of Engineering.
b. Implementation teams. To inform the efforts related to
implementation of some of the recommendations from the Safety
Measures Report, the DOI Safety Oversight Board Report, the
recommendations to be developed by the President's bipartisan
National Commission and other investigative and reviewing bodies,
DOI is establishing Department-led implementation teams. These
teams, initially described as ``strike teams'' in the Safety
Measures Report, will evaluate various issues, both highly technical
and non-technical.
The implementation teams will seek input as appropriate from
academia, industry, and other technical experts and stakeholders.
They will develop and present their recommendations for further
actions to address additional environmental protection and safety
measures. The Department may use the recommendations from these
implementation teams to:
(1) Inform future rulemaking,
(2) Develop internal policy for inspections and enforcement of
regulations,
(3) Identify future research needs.
3. NTL No. 2010-N05--Increased Safety Measures for Energy Development
on the OCS
The NTL No. 2010-N05, ``Increased Safety Measures for Energy
Development on the OCS,'' addressed the recommendations from the
Safety Measures Report that warranted immediate implementation. The
link to this NTL is: http://www.gomr.boemre.gov/homepg/regulate/regs/ntls/2010NTLs/10-n05.pdf.
BOEMRE issued this NTL on June 8, 2010, as a result of the
Deepwater Horizon event. The NTL addresses the recommendations in
the report to the President entitled, ``Increased Safety Measures
for Energy Development on the Outer Continental Shelf'' dated May
27, 2010, and details under then-existing regulations the
requirements lessees and operators must meet to operate on the OCS.
Following are the specific items included in the NTL:
Operators are required to:
Verify compliance with existing regulations and Safety
Alert issued on April 30, 2010.
Submit BOP and well control system configuration
information for the drilling rig that was being used.
Recertify all BOP equipment before resuming drilling.
Have documentation showing that the BOP has been
maintained according to the regulations at 30 CFR 250.446(a). The
operators are required to maintain records and make them available
upon request.
Obtain independent third party verification that the
BOP stack is designed for the specific equipment on the rig and
compatible with the specific well location, well design, and well
execution plan; the BOP stack has not been compromised or damaged
from previous service; and the BOP stack will operate in the
conditions in which it will be used.
Have a secondary control system with ROV intervention
capabilities, including the ability to close one set of blind-shear
rams and one set of pipe rams and unlatch the LMRP.
Have an emergency shut-in system in the event that you
lose power to the BOP stack, have an unplanned disconnection of the
riser from the BOP stack, or experience another emergency situation.
Function test the hot stabs that would be used to
interface with the ROV intervention panel during the stump test.
Obtain an independent third party verification that
provides sufficient information showing that the blind-shear rams
installed in the BOP stack are capable of shearing the drill pipe in
the hole under maximum anticipated surface pressures.
If the blind-shear rams or casing shear rams are
activated in a well control situation in which pipe or casing was
sheared, operators must inspect and test the BOP stack and its
components, after the situation is fully controlled.
Have all well casing designs and cementing program/
procedures certified by a Professional Engineer, verifying the
casing design is appropriate for the purpose for which it is
intended under expected wellbore conditions.
Submit the relevant information discussed in the NTL
prior to commencing those operations, and drilling may not commence
without BOEMRE approval.
4. NTL No. 2010-N06--Information Requirements for Exploration Plans,
Development and Production Plans, and Development Operations
Coordination Documents on the OCS
The link to this NTL is: http://www.gomr.boemre.gov/homepg/regulate/regs/ntls/2010NTLs/10-n06.pdf.
BOEMRE issued this NTL on June 18, 2010. This NTL provides
guidance to lessees and operators regarding the blowout and oil
spill information required in the exploration and development plan
documents submitted to BOEMRE, including:
A blowout scenario as required by 30 CFR 250.213(g) and
250.243(h), including:
Highest volume of liquid hydrocarbons;
Estimated flow rate, total volume, and maximum duration;
Potential for the well to bridge over;
Likelihood for surface intervention to stop the blowout;
Availability of a rig to drill a relief well;
Time frame to drill a relief well.
A description of the assumptions and calculations used to
determine the volume of the worst case discharge scenario,
including:
Well design;
Reservoir characteristics;
Fluid characteristics;
Pressure, volume, and temperature characteristics;
Analog reservoir assumptions;
Supporting calculations and models used in determining worst
case scenario.
5. Secretarial Decision Suspending Drilling Activities That Use Subsea
BOP Stacks and Drilling From Floating Facilities With a Surface BOP
Stack
On July 12, 2010, the Secretary issued a decision directing
BOEMRE to suspend the drilling of wells using subsea BOPs or surface
BOPs on floating facilities, and to cease approval of pending and
future applications for permits to drill using subsea BOPs or
surface BOPs on floating facilities. These directives apply in the
GOM and Pacific regions through November 30, 2010, subject to
modification if the Secretary determines that the significant
threats to life, property, and the environment set forth in his
decision have been sufficiently addressed. This includes additional
information about the causes of the Deepwater Horizon Oil Spill.
Several investigations and reviews are being undertaken to identify
the root causes of the disaster, including a joint BOEMRE-USCG
investigation, a review by the NAE, on-going Congressional
inquiries, and the National Commission on the BP Deepwater Horizon
Oil Spill and Offshore Drilling (Presidential Commission). The
results of these will better inform DOI decision-making and longer-
term rulemaking.
Following this decision, on July 12, 2010, BOEMRE issued
suspension orders of most
[[Page 63372]]
deepwater drilling operations on the OCS through November 30, 2010.
BOEMRE stopped approval of pending and future deepwater drilling
applications in the GOM and Pacific regions.
6. Held Public Meetings to Collect Information and Views About
Deepwater Drilling Safety Reforms, Blowout Containment, and Oil Spill
Response
As directed by the Secretary in the Decision of July 12, 2010,
the BOEMRE Director led a series of public meetings to collect
information and views about deepwater drilling safety reforms,
blowout containment, and oil spill response. The Director solicited
input from the general public, state, and local leaders, experts
from academia, the environmental community, and the oil and gas
industry. The link to the Public Forums on Offshore Drilling is:
http://www.boemre.gov/forums/. The webpage provides information and
presentations from each meeting. The meetings were held in August
and September in the following cities: New Orleans, Louisiana;
Mobile, Alabama; Pensacola, Florida; Santa Barbara, California;
Anchorage, Alaska; Houston, Texas; Biloxi, Mississippi; Lafayette,
Louisiana.
List of Subjects in 30 CFR Part 250
Administrative practice and procedure, Continental shelf,
Incorporation by reference, Oil and gas exploration, Public lands--
mineral resources, Public lands--rights-of-way, Reporting and
recordkeeping requirements.
Dated: October 1, 2010.
Wilma A. Lewis,
Assistant Secretary--Land and Minerals Management.
0
For the reasons stated in the preamble, under the authority of 43
U.S.C. 1334 and Section 2 or Reorganization Plan No. 3 of 1950, 64
Stat. 1262, as amended, the Bureau of Ocean Energy Management,
Regulation and Enforcement (BOEMRE) is amending 30 CFR chapter II as
follows:
Title 30--Mineral Resources
CHAPTER II--BUREAU OF OCEAN ENERGY MANAGEMENT, REGULATION AND
ENFORCEMENT, DEPARTMENT OF THE INTERIOR
PART 250--OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER
CONTINENTAL SHELF
0
1. The authority citation for part 250 continues to read as follows:
Authority: 31 U.S.C. 9701, 43 U.S.C. 1334.
0
2. Amend Sec. 250.198 by:
0
a. Adding a new paragraph (a)(3),
0
b. Revising paragraph (h)(63), and
0
c. Adding new paragraph (h)(79) to read as follows:
Sec. 250.198 Documents incorporated by reference.
(a) * * *
(3) The effect of incorporation by reference of a document into the
regulations in this part is that the incorporated document is a
requirement. When a section in this part incorporates all of a
document, you are responsible for complying with the provisions of that
entire document, except to the extent that section provides otherwise.
When a section in this part incorporates part of a document, you are
responsible for complying with that part of the document as provided in
that section. If any incorporated document uses the word should, it
means must for purposes of these regulations.
* * * * *
(h) * * *
(63) API RP 53, Recommended Practices for Blowout Prevention
Equipment Systems for Drilling Wells, Third Edition, March 1997;
reaffirmed September 2004, Order No. G53003; incorporated by reference
at Sec. 250.442(c); Sec. 250.446(a); Sec. 250.516(g)(1); Sec.
250.516(h); and Sec. 250.617(a)(1), and (b);
* * * * *
(79) API RP 65-Part 2, Isolating Potential Flow Zones During Well
Construction; First Edition, May 2010; Product No. G65201; incorporated
by reference at Sec. 250.415(f).
* * * * *
0
3. Amend Sec. 250.415 as follows:
0
a. Revise paragraphs (c), (d), and (e)(2), and
0
b. Add new paragraph (f) to read as follows:
Sec. 250.415 What must my casing and cementing programs include?
* * * * *
(c) Type and amount of cement (in cubic feet) planned for each
casing string;
(d) * * * Your program must provide protection from thaw subsidence
and freezeback effect, proper anchorage, and well control;
(e) * * *
(2) An ``area known to contain a shallow water flow hazard'' is a
zone or geologic formation for which drilling has confirmed the
presence of shallow water flow; and
(f) A written description of how you evaluated the best practices
included in API RP 65-Part 2, Isolating Potential Flow Zones During
Well Construction (incorporated by reference as specified in Sec.
250.198). Your written description must identify the mechanical
barriers and cementing practices you will use for each casing string
(reference API RP 65-Part 2, Sections 3 and 4).
0
4. Amend Sec. 250.416 by revising paragraphs (d) and (e) and adding
new paragraphs (f) and (g) to read as follows:
Sec. 250.416 What must I include in the diverter and BOP
descriptions?
* * * * *
(d) A schematic drawing of the BOP system that shows the inside
diameter of the BOP stack, number and type of preventers, all control
systems and pods, location of choke and kill lines, and associated
valves;
(e) Independent third party verification and supporting
documentation that show the blind-shear rams installed in the BOP stack
are capable of shearing any drill pipe in the hole under maximum
anticipated surface pressure. The documentation must include test
results and calculations of shearing capacity of all pipe to be used in
the well including correction for MASP;
(f) When you use a subsea BOP stack, independent third party
verification that shows:
(1) the BOP stack is designed for the specific equipment on the rig
and for the specific well design;
(2) The BOP stack has not been compromised or damaged from previous
service;
(3) The BOP stack will operate in the conditions in which it will
be used; and
(g) The qualifications of the independent third party referenced in
paragraphs (e) and (f) of this section:
(1) The independent third party in paragraph (e) in this section
must be a technical classification society; an API-licensed
manufacturing, inspection, or certification firm; or a licensed
professional engineering firm capable of providing the verifications
required under this part. The independent third party must not be the
original equipment manufacturer (OEM).
(2) You must:
(i) Include evidence that the firm you are using is reputable, the
firm or its employees hold appropriate licenses to perform the
verification in the appropriate jurisdiction, the firm carries
industry-standard levels of professional liability insurance, and the
firm has no record of violations of applicable law.
(ii) Ensure that an official representative of BOEMRE will have
access to the location to witness any testing or inspections, and
verify information submitted to BOEMRE. Prior to any shearing ram tests
or inspections, you must notify the District Manager at least 24 hours
in advance.
0
5. Amend Sec. 250.418 as follows:
0
a. Revise paragraph (g),
[[Page 63373]]
0
b. Redesignate paragraph (h) as paragraph (j), and
0
c. Add new paragraphs (h) and (i) to read as follows:
Sec. 250.418 What additional information must I submit with my APD?
* * * * *
(g) A request for approval if you plan to wash out or displace some
cement to facilitate casing removal upon well abandonment;
(h) Certification of your casing and cementing program as required
in Sec. 250.420(a)(6);
(i) Description of qualifications required by Sec. 250.416(f) of
any independent third party; and
* * * * *
0
6. Amend Sec. 250.420 as follows:
0
a. Revise paragraphs (a)(4) and (a)(5),
0
b. Add new paragraph (a)(6),
0
c. Add new paragraph (b)(3) to read as follows:
Sec. 250.420 What well casing and cementing requirements must I meet?
* * * * *
(a) * * *
(4) Protect freshwater aquifers from contamination;
(5) Support unconsolidated sediments; and
(6) Include certification signed by a Registered Professional
Engineer that there will be at least two independent tested barriers,
including one mechanical barrier, across each flow path during well
completion activities and that the casing and cementing design is
appropriate for the purpose for which it is intended under expected
wellbore conditions. The Registered Professional Engineer must be
registered in a State in the United States. Submit this certification
with your APD (Form MMS-123).
(b) * * *
(3) For the final casing string (or liner if it is your final
string), you must install dual mechanical barriers in addition to
cement, to prevent flow in the event of a failure in the cement. These
may include dual float valves, or one float valve and a mechanical
barrier. You must submit documentation to BOEMRE 30 days after
installation of the dual mechanical barriers.
* * * * *
0
7. Revise Sec. 250.423 to read as follows:
Sec. 250.423 What are the requirements for pressure testing casing?
(a) The table in this section describes the minimum test pressures
for each string of casing. You may not resume drilling or other down-
hole operations until you obtain a satisfactory pressure test. If the
pressure declines more than 10 percent in a 30-minute test, or if there
is another indication of a leak, you must re-cement, repair the casing,
or run additional casing to provide a proper seal. The District Manager
may approve or require other casing test pressures.
----------------------------------------------------------------------------------------------------------------
Casing type Minimum test pressure
----------------------------------------------------------------------------------------------------------------
(1) Drive or Structural............... Not required.
(2) Conductor......................... 200 psi.
(3) Surface, Intermediate, and 70 percent of its minimum internal yield.
Production.
----------------------------------------------------------------------------------------------------------------
(b) You must ensure proper installation of casing or liner in the
subsea wellhead or liner hanger.
(1) You must ensure that the latching mechanisms or lock down
mechanisms are engaged upon installation of each casing string or
liner.
(2) You must perform a pressure test on the casing seal assembly to
ensure proper installation of casing or liner. You must perform this
test for the intermediate and production casing strings or liner.
(3) You must submit for approval with your APD, test procedures and
criteria for a successful test.
(4) You must document all your test results and make them available
to BOEMRE upon request.
(c) You must perform a negative pressure test on all wells to
ensure proper casing installation. You must perform this test for the
intermediate and production casing strings.
(1) You must submit for approval with your APD, test procedures and
criteria for a successful test.
(2) You must document all your test results and make them available
to BOEMRE upon request.
0
8. Amend Sec. 250.442 by revising the section heading and the section
to read as follows:
Sec. 250.442 What are the requirements for a subsea BOP system?
When you drill with a subsea BOP system, you must install the BOP
system before drilling below the surface casing. The District Manager
may require you to install a subsea BOP system before drilling below
the conductor casing if proposed casing setting depths or local geology
indicate the need. The table in this paragraph outlines your
requirements.
------------------------------------------------------------------------
When drilling with a subsea BOP
system, you must: Additional requirements
------------------------------------------------------------------------
(a) Have at least four remote- You must have at least one annular
controlled, hydraulically operated BOP, two BOPs equipped with pipe
BOPs. rams, and one BOP equipped with
blind-shear rams. The blind-shear
rams must be capable of shearing
any drill pipe in the hole under
maximum anticipated surface
pressures.
(b) Have an operable dual-pod ...................................
control system to ensure proper
and independent operation of the
BOP system.
(c) Have an accumulator system to The accumulator system must meet or
provide fast closure of the BOP exceed the provisions of Section
components and to operate all 13.3, Accumulator Volumetric
critical functions in case of a Capacity, in API RP 53,
loss of the power fluid connection Recommended Practices for Blowout
to the surface. Prevention Equipment Systems for
Drilling Wells (incorporated by
reference as specified in Sec.
250.198). The District Manager may
approve a suitable alternate
method.
(d) Have a subsea BOP stack At a minimum, the ROV must be
equipped with remotely operated capable of closing one set of pipe
vehicle (ROV) intervention rams, closing one set of blind-
capability. shear rams and unlatching the
LMRP.
(e) Maintain an ROV and have a The crew must be trained in the
trained ROV crew on each floating operation of the ROV. The training
drilling rig on a continuous must include simulator training on
basis. The crew must examine all stabbing into an ROV intervention
ROV related well control equipment panel on a subsea BOP stack.
(both surface and subsea) to
ensure that it is properly
maintained and capable of shutting
in the well during emergency
operations.
[[Page 63374]]
(f) Provide autoshear and deadman (1) Autoshear system means a safety
systems for dynamically positioned system that is designed to
rigs. automatically shut in the wellbore
in the event of a disconnect of
the LMRP. When the autoshear is
armed, a disconnect of the LMRP
closes the shear rams. This is
considered a ``rapid discharge''
system.
(2) Deadman System means a safety
system that is designed to
automatically close the wellbore
in the event of a simultaneous
absence of hydraulic supply and
signal transmission capacity in
both subsea control pods. This is
considered a ``rapid discharge''
system.
(3) You may also have an acoustic
system.
(g) Have operational or physical Incorporate enable buttons on
barrier(s) on BOP control panels control panels to ensure two-
to prevent accidental disconnect handed operation for all critical
functions. functions.
(h) Clearly label all control Label other BOP control panels such
panels for the subsea BOP system. as hydraulic control panel.
(i) Develop and use a management The management system must include
system for operating the BOP written procedures for operating
system, including the prevention the BOP stack and LMRP (including
of accidental or unplanned proper techniques to prevent
disconnects of the system. accidental disconnection of these
components) and minimum knowledge
requirements for personnel
authorized to operate and maintain
BOP components.
(j) Establish minimum requirements Personnel must have:
for personnel authorized to
operate critical BOP equipment.
(1) Training in deepwater well
control theory and practice
according to the requirements
of 30 CFR 250, subpart O; and
(2) A comprehensive knowledge of
BOP hardware and control
systems.
(k) Before removing the marine You must maintain sufficient
riser, displace the fluid in the hydrostatic pressure or take other
riser with seawater. suitable precautions to compensate
for the reduction in pressure and
to maintain a safe and controlled
well condition.
(l) Install the BOP stack in a Your glory hole must be deep enough
glory hole when in ice-scour area. to ensure that the top of the
stack is below the deepest
probable ice-scour depth.
------------------------------------------------------------------------
0
9. Amend Sec. 250.446 by revising paragraph (a) to read as follows:
Sec. 250.446 What are the BOP maintenance and inspection
requirements?
(a) You must maintain and inspect your BOP system to ensure that
the equipment functions properly. The BOP maintenance and inspections
must meet or exceed the provisions of Sections 17.10 and 18.10,
Inspections; Sections 17.11 and 18.11, Maintenance; and Sections 17.12
and 18.12, Quality Management, described in API RP 53, Recommended
Practices for Blowout Prevention Equipment Systems for Drilling Wells
(incorporated by reference as specified in Sec. 250.198). You must
document the procedures used, record the results of your BOP
inspections and maintenance actions, and make available to BOEMRE upon
request. You must maintain your records on the rig for 2 years or from
the date of your last major inspection, whichever is longer;
* * * * *
0
10. Amend Sec. 250.449, by revising paragraphs (h) and (i) and adding
new paragraphs (j) and (k) to read as follows:
Sec. 250.449 What additional BOP testing requirements must I meet?
* * * * *
(h) Function test annular and ram BOPs every 7 days between
pressure tests;
(i) Actuate safety valves assembled with proper casing connections
before running casing;
(j) Test all ROV intervention functions on your subsea BOP stack
during the stump test. You must also test at least one set of rams
during the initial test on the seafloor. You must submit test
procedures with your APD or APM for District Manager approval. You
must:
(1) ensure that the ROV hot stabs are function tested and are
capable of actuating, at a minimum, one set of pipe rams and one set of
blind-shear rams and unlatching the LMRP; and
(2) document all your test results and make them available to
BOEMRE upon request;
(k) Function test autoshear and deadman systems on your subsea BOP
stack during the stump test. You must also test the deadman system
during the initial test on the seafloor.
(1) You must submit test procedures with your APD or APM for
District Manager approval.
(2) You must document all your test results and make them available
to BOEMRE upon request.
0
11. Amend Sec. 250.451 by adding new paragraph (i) to the table to
read as follows:
Sec. 250.451 What must I do in certain situations involving BOP
equipment or systems?
* * * * *
------------------------------------------------------------------------
If you encounter the following
situation: Then you must * * *
------------------------------------------------------------------------
* * * * * * *
(i) You activate blind-shear rams or Retrieve, physically inspect,
casing shear rams during a well and conduct a full pressure
control situation, in which pipe or test of the BOP stack after
casing is sheared. the situation is fully
controlled.
* * * * * * *
------------------------------------------------------------------------
0
12. Amend Sec. 250.456 by:
0
a. Revising the last sentence in paragraph (i),
0
b. Redesignating paragraph (j) as (k), and
[[Page 63375]]
0
c. Adding a new paragraph (j) to read as follows:
Sec. 250.456 What safe practices must the drilling fluid program
follow?
* * * * *
(i) * * * You must record the results of these tests in the
drilling fluid report;
(j) Before displacing kill-weight drilling fluid from the wellbore,
you must obtain prior approval from the District Manager. To obtain
approval, you must submit with your APD or APM your reasons for
displacing the kill-weight drilling fluid and provide detailed step-by-
step written procedures describing how you will safely displace these
fluids. The step-by-step displacement procedures must address the
following:
(1) number and type of independent barriers that are in place for
each flow path,
(2) tests you will conduct to ensure integrity of independent
barriers,
(3) BOP procedures you will use while displacing kill weight
fluids, and
(4) procedures you will use to monitor fluids entering and leaving
the wellbore; and
* * * * *
0
13. Amend Sec. 250.515 by adding new paragraphs (b)(5) and (e) to read
as follows:
Sec. 250.515 Blowout prevention equipment.
* * * * *
(b) * * *
------------------------------------------------------------------------
The minimum BOP stack must
When include
------------------------------------------------------------------------
* * * * * * *
(5) You use a subsea BOP stack......... The requirements in Sec.
250.442(a) of this part.
* * * * * * *
------------------------------------------------------------------------
* * * * *
(e) The subsea BOP system for well-completions must meet the
requirements in Sec. 250.442 of this part.
0
14. Amend Sec. 250.516 by:
0
a. Revising (d)(6);
0
b. Adding new paragraphs (d)(8) and (d)(9); and
0
c. Revising paragraphs (g) and (h) to read as follows:
Sec. 250.516 Blowout preventer system tests, inspections, and
maintenance.
* * * * *
(d) * * *
(6) Pressure-test variable bore-pipe rams against all sizes of pipe
in use, excluding drill collars and bottom-hole tools;
* * * * *
(8) Test all ROV intervention functions on your subsea BOP stack
during the stump test. You must also test at least one set of rams
during the initial test on the seafloor. You must submit test
procedures with your APM for District Manager approval. You must:
(i) Ensure that the ROV hot stabs are function tested and are
capable of actuating, at a minimum, one set of pipe rams and one set of
blind-shear rams and unlatching the LMRP;
(ii) Document all your test results and make them available to
BOEMRE upon request; and
(9) Function test autoshear and deadman systems on your subsea BOP
stack during the stump test. You must also test the deadman system
during the initial test on the seafloor.
(i) You must submit test procedures with your APM for District
Manager approval.
(ii) You must document all your test results and make them
available to BOEMRE upon request.
* * * * *
(g) BOP inspections. (1) You must inspect your BOP system to ensure
that the equipment functions properly. The BOP inspections must meet or
exceed the provisions of Sections 17.10 and 18.10, Inspections,
described in API RP 53, Recommended Practices for Blowout Prevention
Equipment Systems for Drilling Wells (incorporated by reference as
specified in Sec. 250.198). You must document the procedures used,
record the results, and make them available to BOEMRE upon request. You
must maintain your records on the rig for 2 years or from the date of
your last major inspection, whichever is longer.
(2) 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 Manager 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. The BOP maintenance must meet or
exceed the provisions of Sections 17.11 and 18.11, Maintenance; and
Sections 17.12 and 18.12, Quality Management, described in API RP 53,
Recommended Practices for Blowout Prevention Equipment Systems for
Drilling Wells (incorporated by reference as specified in Sec.
250.198). You must document the procedures used, record the results,
and make available to BOEMRE upon request. You must maintain your
records on the rig for 2 years or from the date of your last major
inspection, whichever is longer.
* * * * *
0
15. Amend Sec. 250.615 by:
0
a. Adding new paragraph (b)(5),
0
b. Redesignating paragraphs (e) through (g) as (f) through (h), and
0
c. Adding new paragraph (e) to read as follows:
Sec. 250.615 Blowout prevention equipment.
* * * * *
(b) * * *
------------------------------------------------------------------------
The minimum BOP stack must
When include
------------------------------------------------------------------------
* * * * * * *
(5) You use a subsea BOP stack......... The requirements in Sec.
250.442(a) of this part.
* * * * * * *
------------------------------------------------------------------------
[[Page 63376]]
(e) The subsea BOP system for well-workover operations must meet
the requirements in Sec. 250.442 of this part.
* * * * *
0
16. Amend Sec. 250.616 by adding new paragraph (h) to read as follows:
Sec. 250.616 Blowout preventer system testing, records, and drills.
* * * * *
(h) Stump test a subsea BOP system before installation. You must:
(1) Test all ROV intervention functions on your subsea BOP stack
during the stump test. You must also test at least one set of rams
during the initial test on the seafloor. You must submit test
procedures with your APM for District Manager approval. You must:
(i) Ensure that the ROV hot stabs are function tested and are
capable of actuating, at a minimum, one set of pipe rams and one set of
blind-shear rams and unlatching the LMRP;
(ii) Document all your test results and make them available to
BOEMRE upon request; and
(2) Function test autoshear and deadman systems on your subsea BOP
stack during the stump test. You must also test the deadman system
during the initial test on the seafloor. You must:
(i) Submit test procedures with your APM for District Manager
approval.
(ii) Document the results of each test and make them available to
BOEMRE upon request.
(3) 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.
Sec. Sec. 250.617 and 250.618 [Redesignated as Sec. Sec. 250.618 and
250.619]
0
17. Redesignate Sec. Sec. 250.617 and 250.618 to Sec. Sec. 250.618
and 250.619, respectively.
0
18. Add new Sec. 250.617 to read as follows:
Sec. 250.617 What are my BOP inspection and maintenance requirements?
(a) BOP inspections.
(1) You must inspect your BOP system to ensure that the equipment
functions properly. The BOP inspections must meet or exceed the
provisions of Sections 17.10 and 18.10, Inspections, described in API
RP 53, Recommended Practices for Blowout Prevention Equipment Systems
for Drilling Wells (incorporated by reference as specified in Sec.
250.198). You must document the procedures used, record the results,
and make them available to BOEMRE upon request. You must maintain your
records on the rig for 2 years or from the date of your last major
inspection, whichever is longer.
(2) 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 Manager may
approve alternate methods and frequencies to inspect a marine riser.
(b) BOP maintenance. You must maintain your BOP system to ensure
that the equipment functions properly. The BOP maintenance must meet or
exceed the provisions of Sections 17.11 and 18.11, Maintenance; and
Sections 17.12 and 18.12, Quality Management, described in API RP 53,
Recommended Practices for Blowout Prevention Equipment Systems for
Drilling Wells (incorporated by reference as specified in Sec.
250.198). You must document the procedures used, record the results,
and make them available to BOEMRE upon request. You must maintain your
records on the rig for 2 years or from the date of your last major
inspection, whichever is longer.
0
19. In Sec. Sec. 250.1500:
0
a. Amend the definition of ``Contractor and contract personnel'' and
the definition of ``Employee'' by removing the phrase ``well control or
production safety'', and in its place add the phrase ``well control,
deepwater well control, or production safety''; and
0
b. Add definitions for ``Deepwater well control'', ``Well completion/
well workover'', Well control'', and ``Well servicing'' in alphabetical
order to read as follows:
Sec. 250.1500 Definitions.
* * * * *
Deepwater well control means well control when you are using a
subsea BOP system.
* * * * *
Well completion/well workover means those operations following the
drilling of a well that are intended to establish or restore
production.
Well control means methods used to minimize the potential for the
well to flow or kick and to maintain control of the well in the event
of flow or a kick during drilling, well completion, well workover, and
well servicing operations.
Well servicing means snubbing, coiled tubing, and wireline
operations.
Sec. 250.1501 [Amended]
0
20. In Sec. Sec. 250.1501, remove the phrase ``well control or
production safety'', and in its place add the phrase ``well control,
deepwater well control, or production safety''.
Sec. 250.1503 [Amended]
0
21. In Sec. Sec. 250.1503:
0
a. Redesignating paragraphs (b) and (c) as paragraphs (c) and (d);
0
b. Amending paragraphs (a), (c)(1), (c)(3) and (d)(1) by removing the
phrase ``well control or production safety'', and in its place adding
the phrase ``well control, deepwater well control, or production
safety'';
0
c. Amend paragraph (a) by removing the phrase ``well control and
production safety'', and in its place adding the phrase ``well control,
deepwater well control, and production safety''; and
0
d. Adding new paragraph (b) to read as follows:
Sec. 250.1503 What are my general responsibilities for training?
* * * * *
(b) If you conduct operations with a subsea BOP stack, your
employees and contract personnel must be trained in deepwater well
control. The trained employees and contract personnel must have a
comprehensive knowledge of deepwater well control equipment, practices,
and theory.
Sec. 250.1506 [Amended]
0
22. In Sec. Sec. 250.1506, amend paragraphs (a), (b), and (c) by
removing the phrase ``well control or production safety'', and in its
place adding the phrase ``well control, deepwater well control, or
production safety''.
Sec. 250.1507 [Amended]
0
23. In Sec. Sec. 250.1507, amend paragraphs (c) and (d) by removing
the phrase ``well control and production safety'', and in its place
adding the phrase ``well control, deepwater well control, and
production safety''.
0
24. Amend Sec. 250.1712 by,
0
a. Revising paragraph (e) and (f)(14); and
0
b. Adding new paragraph (g) to read as follows:
Sec. 250.1712 What information must I submit before I permanently
plug a well or zone?
* * * * *
(e) A description of the work;
(f) * * *
(14) Your plans to protect archaeological and sensitive biological
features, including anchor damage during plugging operations, a brief
assessment of the environmental impacts of the plugging operations, and
the procedures and mitigation measures you will take to minimize such
impacts; and
(g) Certification by a Registered Professional Engineer of the well
abandonment design and procedures; that there will be at least two
[[Page 63377]]
independent tested barriers, including one mechanical barrier, across
each flow path during abandonment activities; and that the plug meets
the requirements in the table in Sec. 250.1715. The Registered
Professional Engineer must be registered in a State in the United
States. You must submit this certification with your APM (Form MMS-
124).
0
25. Amend Sec. 250.1721 by:
0
a. Revising paragraphs (e) and (g)(3), and
0
b. Adding new paragraph (h) to read as follows:
Sec. 250.1721 If I temporarily abandon a well that I plan to re-
enter, what must I do?
* * * * *
(e) Identify and report subsea wellheads, casing stubs, or other
obstructions that extend above the mud line according to U.S. Coast
Guard (USCG) requirements;
* * * * *
(g) * * *
(3) A description of any remaining subsea wellheads, casing stubs,
mudline suspension equipment, or other obstructions that extend above
the seafloor; and
(h) Submit certification by a Registered Professional Engineer of
the well abandonment design and procedures; that there will be at least
two independent tested barriers, including one mechanical barrier,
across each flow path during abandonment activities; and that the plug
meets the requirements in the table in Sec. 250.1715. The Registered
Professional Engineer must be registered in a State in the United
States. You must submit this certification with your APM (Form MMS-124)
required by Sec. 250.1712.
[FR Doc. 2010-25256 Filed 10-7-10; 11:15 am]
BILLING CODE 4310-MR-P