Interim Final Rule

Thursday,
October 14, 2010

Part III

Department of the
Interior
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

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Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations

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
Bureau of Ocean Energy
Management, Regulation and
Enforcement (BOEMRE), Interior.
ACTION: Interim final rule with request
for comments.
AGENCY:

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

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SUMMARY:

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‘‘Enter Keyword or ID,’’ enter BOEM2010-0034 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,
amy.white@boemre.gov.
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

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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 onetime 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

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Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations
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, interagency workgroups, or other means.

63347

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
Citation and requirement

Recommendation

Applies to

Operator cost to
implement per
year *

Operator ability to comply
with requirement

§ 250.198(a)(3), All documents incorporated by reference ‘‘should’’ and ‘‘shall’’
mean ‘‘must’’.

Based on NTL No. 2010 N05

All operators ..........................

..............................

§ 250.198(h)(79), Incorporation by Reference of API
RP 65—Part 2 Isolating
Potential Flow Zones During Well Construction.
§ 250.415(f), Written description of how the operator
evaluated the best practices included in API RP
65–Part 2. The description
must identify mechanical
barriers and cementing
practices to be used for
each casing string.
§ 250.416(d), Include schematics of all control systems and control pods.

Safety Measures Report:
II.B.3.7: Enforce Tighter
Primary Cementing Practices.

All applications for permit to
drill (APDs) **.

..............................

Safety Measures Report:
II.B.3.7: Enforce Tighter
Primary Cementing Practices.

Submitted with APD. Applies
to all APDs.

..............................

Safety Measures Report:
I.B.5: Secondary Control
System Requirement and
Guidelines.
Safety Measures Report:
I.C.7: Develop New Testing Requirements. Also in
NTL No. N05.

Submitted with APD. Applies
to all APDs.

..............................

Administrative provision
that does not impose
compliance times beyond
the substantive provisions involved.
Additional information provision does not impose
compliance times beyond
the substantive provisions involved.
New engineering requirement. BOEMRE believes
that most operators will
be able to comply with
this requirement with no
significant delays * * *
because this can be
completed concurrently
with other tasks.
Information is readily available. Should not delay
submission of the APD.

Submitted with APD. Applies
to all APDs.

$1,200,000

Because there are multiple
engineering firms available to do this work, and
because operators have
had advance notice 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.

Safety Measures Report:
I.B.2: Order BOP Equipment Compatibility
Verification for Each Floating Vessel and for Each
New Well. Also in NTL No.
N05.
Based on NTL No. 2010 N–
05.

Submitted with APD. All
APDs for well with subsea
BOP stack. Subsea BOP
stacks are usually employed in deepwater.

..............................

Related to requirements for
independent third party
certifications.

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§ 250.416(e), Independent
third party verification that
the blind-shear rams installed are capable of
shearing any drill pipe in
the hole.

§ 250.416(f), Independent
third party verification that
subsea BOP is designed
for specific equipment on
rig and specific well design.

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§ 250.416(g), Qualification for
independent third parties.

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All APDs ................................

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SUMMARY OF INTERIM FINAL RULE COMPLIANCE—Continued
Operator cost to
implement per
year *

Operator ability to comply
with requirement

Citation and requirement

Recommendation

Applies to

§ 250.420(a)(6), Certification
by a professional engineer
that there are two independent tested barriers and
that the casing and cementing design are appropriate.

Safety Measure Report:
II.B.1.3: New Casing and
Cement Design Requirements: Two Independent
Barriers. This requirement
was also addressed in NTL
No. N05.

Submitted with APD. Applies
to all APDs.

6,000,000

§ 250.420(b)(3), Installation of
dual mechanical barriers in
addition to cement for final
casing string.

Safety Measure Report:
II.B.1.3: New Casing and
Cement Design Requirements: Two Independent
Barriers. This requirement
was also addressed in NTL
No. N05.
Safety Measure Report:
II.B.2.5: New Casing Installation Procedures. This requirement was also addressed in NTL No. N05.

Completed during the casing
and cementing of the well.
It applies to all wells drilled.

10,300,000

Complied with after the installation of each casing
string or liner for all wells
drilled with a subsea BOP
stack. It is tested after the
installation of the casing or
liner.

..............................

Because operators had advance notice of this requirement in both the
Safety Measures Report
and NTL No. N05,
BOEMRE believes operators should be complying
with this requirement.

Safety Measure Report:
II.B.2.6: Develop Additional
Requirements or Guidelines for Casing.

Tested after running the casing. All wells, involves all
rigs with surface and subsurface BOPs in all water
depths.

45,100,000

Safety Measure Report:
I.B.5: Secondary Control
System Requirements and
Guidelines. This requirement was also addressed
in NTL No. N05.

Applies to all subsea BOP
stacks.

..............................

Compliance with this requirement will increase
the time to drill each
subsea well resulting in
additional costs.
BOEMRE estimates several hours of additional
drilling time for each well.
All rigs should be able to
comply with requirement.
All rigs currently have
ROV intervention capability; approximately 80%
of subsea BOP stacks
currently have all the
specified capabilities.
Other 20% are expected
to be able to comply
promptly.

Safety Measure Report:
I.B.6: New ROV Operating
Capabilities; II.A.1: Establish Deepwater Well-Control Procedure Guidelines.

Ongoing requirement. All
subsea BOP stacks regardless of water depth.

..............................

BOEMRE believes all rigs
operating on OCS are already in compliance.

Safety Measure Report:
I.B.5: Secondary Control
System Requirements and
Guidelines.

Anytime drilling occurs with
subsea BOP stacks on DP
rigs.

..............................

BOEMRE believes all DP
rigs operating on OCS
currently comply with this
requirement.

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§ 250.423(b), The operator
must perform a pressure
test on the casing seal assembly to ensure proper installation of casing or liner.
The operator must ensure
that the latching mechanisms or lock down mechanisms are engaged upon
installation of each casing
string or liner.
§ 250.423(c), The operator
must perform a negative
pressure test to ensure
proper casing installation.
This test must be performed for the intermediate
and production casing
strings.
§ 250.442(c), § 250.515(e),
§ 250.615(e). Have a
subsea BOP stack
equipped with remotely operated vehicle (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.
§ 250.442(c), § 250.515(e),
§ 250.615(e). Maintain an
ROV and have a trained
ROV crew on each floating
drilling rig on a continuous
basis.
§ 250.442(f), § 250.515(e),
§ 250.615(e). Provide
autoshear and deadman
systems for dynamically
positioned (DP) rigs.

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Because there are multiple
engineering firms available to do this work and
because operators have
had advance notice of
this requirement in both
the Safety Measures Report and NTL No. N05,
BOEMRE believes operators will be able to comply with this requirement
with no significant delays
and provide information
in the APD.
Completed during the casing and cementing of the
well. Compliance with
this requirement may
minimally increase the
time to drill each well.

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SUMMARY OF INTERIM FINAL RULE COMPLIANCE—Continued
Citation and requirement

Recommendation

§ 250.442(e), § 250.515(e),
§ 250.615(e). Establish
minimum requirements for
personnel authorized to operate critical BOP equipment.

Safety Measure Report:
II.A.1: Establish Deepwater
Well-Control Procedure
Guidelines.

§ 250.446(a), § 250.516(h),
§ 250.516(g), § 250.617.
Require documentation of
BOP inspections and maintenance according to API
RP 53.
§ 250.449(j), § 250.516(d)(8),
§ 250.616(h)(1). Test all
ROV intervention functions
on the subsea BOP stack
during the stump test. Test
at least one set of rams
during the initial test on the
seafloor.

Safety Measure Report:
I.B.5: Secondary Control
System Requirements and
Guidelines.

§ 250.449(k), § 250.516(d)(9),
§ 250.616(h)(2). Function
test autoshear and
deadman systems on the
subsea BOP stack during
the stump test. Test the
deadman system during
the initial test on the
seafloor.
§ 250.451(i), If the blind-shear
or casing shear rams are
activated in a well control
situation, the BOP must be
retrieved and fully inspected and tested.
§ 250.456(j), Before displacing kill-weight drilling
fluid from the wellbore, the
operator must receive approval from the District
Manager. The operator
must submit the reasons
for displacing the kill-weight
drilling fluid and provide detailed step-by-step procedures describing how the
operator will safely displace
these fluids.
Subpart O, §§ 250.1500–
250.1510, Requires that rig
personnel are trained in
deepwater well control and
the specific duties, equipment, and techniques associated with deepwater drilling.

Safety Measure Report:
I.B.5: Secondary Control
System Requirements and
Guidelines; I.C.7: Develop
New Testing Requirements.

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Operator cost to
implement per
year *

Operator ability to comply
with requirement

Ongoing requirement. Applies to all personnel that
operate subsea BOP
stacks. Majority of drilling
rigs that use subsea BOP
stacks operate in deepwater.

..............................

Ongoing requirement. All
BOP stacks. All water
depths.

..............................

Requires trained ROV
crew; for rigs not already
in compliance, additional
training or hiring of new
crew may be necessary.
Additional training could
take days to weeks, depending upon how well
existing crews are
trained. However,
BOEMRE believes no
rigs should be operating
without adequately
trained personnel.
All rigs should be able to
comply with requirement.

Applies to

Safety Measure Report:
During the stump test and
I.B.5: Secondary Control
initial test on the seafloor.
System Requirements and
All subsea BOP stacks. All
Guidelines; I.C.7: Develop
water depths.
New Testing Requirements.

118,200,000

All rigs should be able to
comply with requirement.
This requirement not expected to result in significant delay. Compliance
with this requirement will
slightly increase the time
to drill each deepwater
well drilled with a subsea
BOP, resulting in additional costs.

Safety Measure Report:
I.C.7: Develop New Testing Requirements. This requirement was also addressed in NTL No. N05.

Emergency activation of blind
or casing shear rams.

2,600,000

Safety Measure Report:
II.A.2: New Fluid Displacement Procedures.

Submit with APD or application for permit to modify
(APM). All wells where the
operator wants to displace
kill-weight fluids. This could
occur on all rigs that use
either a surface or subsurface BOP stack. Could
occur with all water depths.

..............................

New requirement. Operator
should be able to provide
this information in APD or
APM without significant
delay.

Safety Measure Report:
II.A.1: Establish Deepwater
Well-Control Procedure
Guidelines.

All wells drilled with subsea
BOP stack.

..............................

BOEMRE believes that the
majority of operators
have addressed this requirement. There should
not be any delay for this
requirement.

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Compliance with this requirement will increase
drilling costs when such
an emergency occurs.

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SUMMARY OF INTERIM FINAL RULE COMPLIANCE—Continued

Citation and requirement
§ 250.1712(g), § 250.1721(h).
Certification by a 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
§ 250.1715.

Recommendation
Safety Measure Report:
II.B.1.3: New Casing and
Cement Design Requirements: Two Independent
Tested Barriers.

Applies to
Submitted with APM. All
abandonment operations
regardless of BOP type or
water depth.

Operator cost to
implement per
year *

Operator ability to comply
with requirement

..............................

Operator should be able to
comply with no significant
delay and provide information in application for
permit to modify (APM).
Estimate that this could
take an operator as much
as several days to comply with new requirement.
Depends on operator’s
internal review process.

* 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
Total Estimated Annual Compliance Costs ........................................................................................................................
Total Estimated Annual Avoided Social Costs (Benefits) ...................................................................................................

$183.1 million.
$631.4 million—B *.

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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 nonzero 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

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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

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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, nearterm 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

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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

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63351

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 blindshear 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

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Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations

10. Required pressure testing if any
shear rams are used in an emergency.

The following table shows where
recommendations from the Safety

Safety measures report recommendation

Interim final rule citation

II.B.3.7: Enforce Tighter Primary Cementing Practices .........................................
II.B.3.7: Enforce Tighter Primary Cementing Practices .........................................
I.A.2: Order BOP Equipment 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 Design Requirements: Two Independent Barriers.
I.C.7: Develop New Testing Requirements
II.B.1.3: New Casing and Cement Design Requirements: Two Independent Barriers.
II.B.1.3: New Casing and Cement 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 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 ..........................
I.B.5: Secondary Control System Requirements and Guidelines ..........................
I.C.7: Develop New Testing Requirements
I.C.7: Develop New Testing Requirements
II.A.2: New Fluid Displacement Procedures ..........................................................
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
I.B.5: Secondary Control System Requirements and Guidelines and recommendation.
I.C.7: Develop New Testing Requirements
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
I.B.5: Secondary Control System Requirements and Guidelines and recommendation.
I.C.7: Develop New Testing Requirements
I.B.5: Secondary Control System Requirements and Guidelines and recommendation.
I.C.7: Develop New Testing Requirements
II.A.1: Establish Deepwater Well-Control Procedure Guidelines ...........................

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II.B.1.3: New Casing and Cement Design Requirements: Two Independent
Tested Barriers.
II.B.1.3: New Casing and Cement Design Requirements: Two 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

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Subpart A—General
§ 250.198 Documents incorporated by reference.
Subpart D—Oil and Gas Drilling Operations
§ 250.415 What must my casing and cementing programs include?
§ 250.416 What must I include in the diverter and BOP descriptions?
§ 250.418
APD?

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What additional information must I submit with my

§ 250.420 What well casing and cementing requirements
must I meet?
§ 250.423 What are the requirements for pressure testing
casing?
§ 250.442
tem?

What are the requirements for a subsea BOP sys-

§ 250.446 What are the BOP maintenance and inspection requirements?
§ 250.449 What additional BOP testing requirements must I
meet?
§ 250.451 What must I do in certain situations involving BOP
equipment or systems?
§ 250.456 What safe practices must the drilling fluid program
follow?
Subpart E—Oil and Gas Well-Completion Operations
§ 250.515 Blowout prevention equipment.

Subpart F—Oil and Gas Well-Workover Operations
§ 250.615 Blowout prevention equipment.
§ 250.616
drills.

Blowout preventer system testing, records, and

§ 250.617 What are my BOP inspection and maintenance requirements?
Subpart O—Well Control and Production Safety Training
§§ 250.1500–250.1510.
§ 250.1503 What are my general responsibilities for training?
Subpart Q—Decommissioning Activities
§ 250.1712 What information must I submit before I permanently plug a well or zone?
§ 250.1721 If I temporarily abandon a well that I plan to reenter, what must I do?

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.

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Measures Report are implemented in the
interim final rule.

Emergency Rulemaking
Recommendations From Safety
Measures Report
The Safety Measures Report identified
four items for emergency rulemaking:
1. Develop secondary control system
requirements;

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Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations
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 blindshear 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 been maintained according to the regulations
at § 250.446(a), maintain these records and make them available upon request (safety report rec. I.A.1).

§ 250.446 What are the BOP maintenance and inspection requirements?
§ 250.516 Blowout preventer system tests, inspections, and
maintenance.
§ 250.617 What are my BOP inspection and maintenance requirements?
§ 250.416 What must I include in the diverter and BOP descriptions?

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; 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 ROV intervention capabilities, including the ability to close 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 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 (safety report rec. I.B.5).

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Function test the hot stabs that would be used to interface with the ROV intervention panel during the stump test (safety report rec. I.B.6).

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 (safety
report rec. I.C.7).

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§ 250.442 What are the requirements for a subsea BOP system?
§ 250.515 Blowout prevention equipment.
§ 250.615 Blowout prevention equipment.
§ 250.442 What are the requirements for a subsea BOP system?
§ 250.515 Blowout prevention equipment.
§ 250.615 Blowout prevention equipment.
§ 250.449 What additional BOP testing requirements must I
meet?
§ 250.516 Blowout preventer system tests, inspections, and
maintenance.
§ 250.616 Blowout preventer system testing, records, and
drills.
§ 250.416 What must I include in the diverter and BOP descriptions?

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Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations
NTL No. 2010–N05 provision

Interim final rule citations

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 (safety report rec. I.C.7).
Have all well casing designs and cementing program/procedures certified by a
Registered Professional Engineer, verifying the casing design is appropriate
for the purpose for which it is intended under expected wellbore conditions
(safety report rec. II.B.3).

§ 250.451 What must I do in certain situations involving BOP
equipment or systems?

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).

§ 250.420 What well casing and cementing requirements
must I meet?
§ 250.1712 What information must I submit before I permanently plug a well or zone?
§ 250.1721 If I temporarily abandon a well that I plan to reenter, what must I do?

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 procedure guidelines (safety report rec. II.A.1)

§ 250.442 What are the requirements for a subsea BOP system?
§ 250.515 Blowout prevention equipment.
§ 250.615 Blowout prevention equipment.
§§ 250.1500 through 250.1510 Subpart O—Well Control
and Production Safety Training.
§ 250.456 What safe practices must the drilling fluid program
follow?
§ 250.423 What are the requirements for pressure testing
casing?

Establish new fluid displacement procedures (safety report rec. II.A.2) ...............
Develop additional requirements 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

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Enforce tighter primary 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.

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§ 250.415
clude?

What must my casing and cementing programs in-

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

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(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

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Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations
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

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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

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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

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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

emcdonald on DSK2BSOYB1PROD with RULES2

Documents Incorporated by Reference
(§ 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
§ 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

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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
§ 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 pressurecontainment 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
§ 250.198(h)(63) were updated to
include the requirements in § 250.516
and new § 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

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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
§ 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 safetyrelated 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

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these API documents at: http://
www.api.org/.
What must my casing and cementing
programs include? (§ 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

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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? (§ 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

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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-

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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? (§ 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

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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.

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What well casing and cementing
requirements must I meet? (§ 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

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and Cement Design Requirements: Two
Independent Tested Barriers.
What are the requirements for pressure
testing casing? (§ 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 § 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? (§ 250.442)
This section requires that when
drilling with a subsea BOP system, the

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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

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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

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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.

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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? (§ 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 § 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

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meet the Safety Measures Report
recommendation I.B.5: Secondary
Control System Requirements and
Guidelines.
What additional BOP testing
requirements must I meet? (§ 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.

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What must I do in certain situations
involving BOP equipment or systems?
(§ 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.

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What safe practices must the drilling
fluid program follow? (§ 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 killweight 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.

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Blowout prevention equipment.
(§ 250.515)
This section added requirements of
§ 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.
(§ 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
§ 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 § 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.
(§ 250.615)
This section added requirements of
§ 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. (§ 250.616)
Paragraph (h)(1) was added to require
tests for ROV intervention functions

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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 § 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? (§ 250.617)
This section was added to apply the
requirements of § 250.446 in subpart D,
Oil and Gas Drilling Operations, to the
requirements for well workover
operations using a subsea BOP stack.
Definitions. (§ 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? (§ 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.

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What information must I submit before
I permanently plug a well or zone?
(§ 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
§ 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?
(§ 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

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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
§ 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.

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.
New ROV Operating Capabilities.
Establish Deepwater Well-Control Procedure Guidelines.
Study Formal Personnel Training
Requirements for Casing and
Cementing Operations.
Develop Additional Requirements or Guidelines for Casing Installation.
Enforce Tighter Primary Cementing Practices.

I.B.6 .........
II.A.1 ........
II.B.1.4 .....
II.B.2.6 .....
II.B.3.7 .....

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:

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
ITEMS FOR FUTURE RULEMAKING
findings from technology-focused
research led by DOI strike teams and
Number
Recommendation
interagency workgroups. Some of the
I.A.3 ......... Develop Formal Equipment Cer- issues that are addressed by this
tification Requirements.
rulemaking, such as cementing and
I.B.4 ......... New Blind Shear Ram Redun- casing design, will be considered for
dancy Requirement.
additional rulemaking in the future. We
II.B.3.8 ..... Develop Additional Requirewill consider additional measures, after
ments or Guidelines for Evalwe have more thoroughly studied these
uation of Cement Integrity.
II.C.9 ........ Increase Federal Government issues and assessed the best approaches.
BOEMRE has identified the following
Wild-Well Intervention Capaissues as likely topics for both near-term
bilities.
II.C.10 ...... Study Innovative Wild-Well Inter- and future rulemakings:

III.C.2 .......
III.C.4 .......

vention,
Response
Techniques, and Response Planning.
Adopt Safety Case Requirements for Floating Drilling Operations on the OCS.
Study Additional Safety Training
and
Certification
Requirements.

There are also certain items which,
although they are included in this

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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

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Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations
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

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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 § 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 DrillThrough 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

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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

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interfacing and actuation by ROVoperated 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

emcdonald on DSK2BSOYB1PROD with RULES2

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

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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 peerreviewed 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 benefitcost analysis for this rule was conducted
using a scenario analysis. The benefitcost 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

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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

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emcdonald on DSK2BSOYB1PROD with RULES2

Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations
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.

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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

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63365

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

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Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations

emcdonald on DSK2BSOYB1PROD with RULES2

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

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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.

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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

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Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations
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.

emcdonald on DSK2BSOYB1PROD with RULES2

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.

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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 § 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

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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.

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Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations
Citation
30 CFR 250

Reporting and recordkeeping
requirement

Hour burden

Average number
of annual
responses

Annual
burden
hours

Subpart D
408, 409; 410–418; 420(a)(6);
423(b)(3), (c)(1); 449(j),
(k)(1); plus various references in subparts A, B, D,
E, H, P, Q.

416(g)(2) .................................
420(b)(3) .................................
423(a) .....................................

Request approval of other pressure casing test pressures
per District Manager.

423(b)(4), (c)(2) ......................

Perform pressure casing test; document results and make
available to BOEMRE upon request.

442(c) ......................................

Request alternative method for the accumulator system .......

442(h) .....................................
442(i) .......................................

Label all functions on all panels ..............................................
Develop written procedures for management system for operating the BOP stack and LMRP.

442(j) .......................................

Establish minimum requirements for authorized personnel to
operate BOP equipment; require training.

446(a) .....................................

Document BOP maintenance 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 and rams; document results every 7
days between BOP tests (biweekly). Note: part of BOP
test.

449(j)(2) ..................................

Test all ROV intervention functions on your subsea BOP
stack; document all test results; make available to
BOEMRE upon request.
Function test autoshear and deadman on your subsea BOP
stack during stump test; document all test results; make
available to BOEMRE upon request.

449(k)(2) .................................

6 .....................

MMS–123 .........
700

4,200

10 mins ..........

6 notifications ...

1

30 mins ..........

700 submissions.

Burden covered under 1010–
0141.
30 mins ..........

700 drilling ops
× 5 tests per
ops = 3,500
tests.

Burden covered under 1010–
0141.
30 mins ..........
4 .....................

30 panels .........
30 procedures ..

Burden covered under 1010–
0128.
1 .....................

105 rigs ............

Burden covered under 1010–
0141.

350
0
1,750

0
15
120
0
105

0

10 ...................

110 wells ..........

1,100

30 mins ..........

110 wells ..........

55

456(i) .......................................

Record results of drilling fluid tests in drilling report ...............

456(j) .......................................

Submit detailed step by step procedures describing displacement of fluids with your APD/APM [this submission
obtains District Manager approval].
Submit revised plans, changes, well/drilling records, procedures, certifications that include any/all supporting documentation etc., submitted on Form MMS–124 (Application
for Permit to Modify).

2 .....................

110 wells ..........

220

4 .....................

MMS–124 .........
4,057

16,228

..................................................................................................

........................

9,458 responses

24,144

460; 465; 449(j), (k)(1);
516(d)(8), (d)(9); 616(h)(1),
(2); plus various references
in subparts A, D, E, F, H, P,
and Q.
Subtotal ...........................
emcdonald on DSK2BSOYB1PROD with RULES2

Apply for permit to drill/revised APD that includes any/all
supporting documentation/evidence [test results, calculations, verifications, procedures, criteria, qualifications, etc.]
and requests for various approvals required in subpart D
(including §§ 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).
Provide 24 hour advance notice of location of shearing ram
tests or inspections; allow BOEMRE access to witness
testing, inspections and information verification.
Submit dual mechanical barrier documentation after installation.

Burden covered under 1010–
0141.

0

Subpart E
516(d)(8) .................................

Submit test procedures with your APM for approval ..............

516(d)(8) .................................

Function test ROV interventions on your subsea BOP stack;
document all test results; make available to BOEMRE
upon request.

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Burden covered under 1010–
0141.
10 ...................

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14OCR2

110 wells ..........

0
1,100

Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations
Citation
30 CFR 250

Reporting and recordkeeping
requirement

Hour burden

516(d)(9) .................................

Function test autoshear and deadman on your subsea BOP
stack during stump test; document all test results; make
available to BOEMRE upon request.
Document the procedures used for BOP inspections; record
results; maintain records for 2 years; make available to
BOEMRE upon request.

30 mins ..........

516(g)(l) ..................................

Average number
of annual
responses

63369
Annual
burden
hours

1,048 completions.

524

7 days × 12
105 rigs/once
hrs/day = 84.
every 3 years
= 35 per year.

2,940

516(g)(2) .................................

Request alternative method to inspect a marine riser ............

Burden covered under 1010–
0067.

0

516(h) .....................................

Document the procedures used for BOP maintenance;
record results; maintain records for 2 years; make available to BOEMRE upon request.

1 .....................

105 rigs ............

105

Subtotal ...........................

..................................................................................................

........................

1,298 responses

4,669

10 hours .........

1,226 workovers

12,260

30 mins ..........

1,226 workovers

613

7 days × 12
105 rigs/once
hrs/day = 84.
every 3 years
= 35 per year.

2,940

Subpart F
616(h)(l) ..................................
616(h)(2) .................................
617(a)(l) ..................................

Test all ROV intervention functions on your subsea BOP
stack; document all test results; make available to
BOEMRE upon request.
Function test autoshear and deadman on your subsea BOP
stack during stump test; document all test results; make
available to BOEMRE upon request.
Document the procedures used for BOP inspections; record
results; maintain records for 2 years; make available to
BOEMRE upon request.

617(a)(2) .................................

Request approval to use alternative method to inspect a marine riser.

Burden covered under 1010–
0067.

0

617(b) .....................................

Document the procedures used for BOP maintenance;
record results; maintain records for 2 years; make available to BOEMRE upon request.

1 .....................

105 rigs ............

105

Subtotal ...........................

..................................................................................................

........................

2,592 responses

15,918

Subpart Q
1712(f), (g); 1721(h) ...............
1721(e) ...................................

emcdonald on DSK2BSOYB1PROD with RULES2

Total .................................

Submit with your APM, archaeological and sensitive biological features; Registered Professional Engineer certification.
Identify and report subsea wellheads, casing stubs, or other
obstructions.
..................................................................................................

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

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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;

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Burden covered under 1010–
0141.
USCG requirements.
........................

13,348 responses.

0
0
44,731

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

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Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations

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 § 515, 114 Stat. 2763, 2763A–153–
154).

emcdonald on DSK2BSOYB1PROD with RULES2

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

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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

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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

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Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations
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

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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/10n05.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 thenexisting 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.

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63371

• 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

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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.

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
1. The authority citation for part 250
continues to read as follows:

emcdonald on DSK2BSOYB1PROD with RULES2

■

Authority: 31 U.S.C. 9701, 43 U.S.C. 1334.

2. Amend § 250.198 by:
a. Adding a new paragraph (a)(3),
■ b. Revising paragraph (h)(63), and
■ c. Adding new paragraph (h)(79) to
read as follows:
■
■

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§ 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
§ 250.442(c); § 250.446(a);
§ 250.516(g)(1); § 250.516(h); and
§ 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 § 250.415(f).
*
*
*
*
*
■ 3. Amend § 250.415 as follows:
■ a. Revise paragraphs (c), (d), and
(e)(2), and
■ b. Add new paragraph (f) to read as
follows:
§ 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 § 250.198). Your written description
must identify the mechanical barriers
and cementing practices you will use for

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each casing string (reference API RP 65–
Part 2, Sections 3 and 4).
■ 4. Amend § 250.416 by revising
paragraphs (d) and (e) and adding new
paragraphs (f) and (g) to read as follows:
§ 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 blindshear 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 APIlicensed 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.
■ 5. Amend § 250.418 as follows:
■ a. Revise paragraph (g),

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Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations
§ 250.420 What well casing and cementing
requirements must I meet?

b. Redesignate paragraph (h) as
paragraph (j), and
■ c. Add new paragraphs (h) and (i) to
read as follows:
■

*

§ 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
§ 250.420(a)(6);
(i) Description of qualifications
required by § 250.416(f) of any
independent third party; and
*
*
*
*
*
■ 6. Amend § 250.420 as follows:
■ a. Revise paragraphs (a)(4) and (a)(5),
■ b. Add new paragraph (a)(6),
■ c. Add new paragraph (b)(3) to read as
follows:

*
*
*
*
(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.
*
*
*
*
*
■ 7. Revise § 250.423 to read as follows:
§ 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 .................................................................................................................
(2) Conductor ..............................................................................................................................
(3) Surface, Intermediate, and 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.

emcdonald on DSK2BSOYB1PROD with RULES2

(b) Have an operable dual-pod control system to ensure proper and
independent operation of the BOP system.
(c) Have an accumulator system to provide fast closure of the BOP
components and to operate all critical functions in case of a loss of
the power fluid connection to the surface.

(d) Have a subsea BOP stack equipped with remotely operated vehicle
(ROV) intervention capability.
(e) Maintain an ROV and have a trained ROV crew on each floating
drilling rig on a continuous basis. The crew must examine all ROV
related well control equipment (both surface and subsea) to ensure
that it is properly maintained and capable of shutting in the well during emergency operations.

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8. Amend § 250.442 by revising the
section heading and the section to read
as follows:

■

§ 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.
Additional requirements

(a) Have at least four remote-controlled, hydraulically operated BOPs.

17:55 Oct 13, 2010

Not required.
200 psi.
70 percent of its minimum internal yield.

(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.

When drilling with a subsea BOP system, you must:

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You must have at least one annular BOP, two BOPs equipped with
pipe rams, and one BOP equipped with blind-shear rams. The blindshear rams must be capable of shearing any drill pipe in the hole
under maximum anticipated surface pressures.

The accumulator system must meet or exceed the provisions of Section 13.3, Accumulator Volumetric Capacity, in API RP 53, Recommended Practices for Blowout Prevention Equipment Systems for
Drilling Wells (incorporated by reference as specified in § 250.198).
The District Manager may approve a suitable alternate method.
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 LMRP.
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.

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When drilling with a subsea BOP system, you must:

Additional requirements

(f) Provide autoshear and deadman systems for dynamically positioned
rigs.

(1) Autoshear system means a safety system that is designed to 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.
Incorporate enable buttons on control panels to ensure two-handed operation for all critical functions.
Label other BOP control panels such as hydraulic control panel.
The management system must include written procedures for operating
the BOP stack and LMRP (including proper techniques to prevent
accidental disconnection of these components) and minimum knowledge requirements for personnel authorized to operate and maintain
BOP components.
Personnel must have:

(g) Have operational or physical barrier(s) on BOP control panels to
prevent accidental disconnect functions.
(h) Clearly label all control panels for the subsea BOP system.
(i) Develop and use a management system for operating the BOP system, including the prevention of accidental or unplanned disconnects
of the system.
(j) Establish minimum requirements 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.
You must maintain sufficient hydrostatic pressure or take other suitable
precautions to compensate for the reduction in pressure and to
maintain a safe and controlled well condition.
Your glory hole must be deep enough to ensure that the top of the
stack is below the deepest probable ice-scour depth.

(k) Before removing the marine riser, displace the fluid in the riser with
seawater.
(l) Install the BOP stack in a glory hole when in ice-scour area.

date of your last major inspection,
whichever is longer;
*
*
*
*
*
■ 10. Amend § 250.449, by revising
paragraphs (h) and (i) and adding new
paragraphs (j) and (k) to read as follows:

9. Amend § 250.446 by revising
paragraph (a) to read as follows:

■

§ 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 § 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

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.
■ 11. Amend § 250.451 by adding new
paragraph (i) to the table to read as
follows:

§ 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

§ 250.451 What must I do in certain
situations involving BOP equipment or
systems?

*

emcdonald on DSK2BSOYB1PROD with RULES2

If you encounter the following situation:

*

*

*

*

Then you must * * *

*
*
*
*
*
*
*
(i) You activate blind-shear rams or casing shear rams during a well Retrieve, physically inspect, and conduct a full pressure test of the
control situation, in which pipe or casing is sheared.
BOP stack after the situation is fully controlled.
*

■

12. Amend § 250.456 by:

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*

*

*

*

a. Revising the last sentence in
paragraph (i),

■

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*

*

b. Redesignating paragraph (j) as (k),
and

■

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Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations
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,

c. Adding a new paragraph (j) to read
as follows:

■

§ 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
When

(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
*
*
*
*
*
■ 13. Amend § 250.515 by adding new
paragraphs (b)(5) and (e) to read as
follows:
§ 250.515

*

Blowout prevention equipment.

*
*
(b) * * *

*

*

The minimum BOP stack must include

*
*
*
*
*
*
(5) You use a subsea BOP stack ............................................................. The requirements in § 250.442(a) of this part.
*

*

*

*
*
*
*
(e) The subsea BOP system for wellcompletions must meet the
requirements in § 250.442 of this part.
■ 14. Amend § 250.516 by:
■ a. Revising (d)(6);
■ b. Adding new paragraphs (d)(8) and
(d)(9); and
■ c. Revising paragraphs (g) and (h) to
read as follows:
§ 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 § 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

When
emcdonald on DSK2BSOYB1PROD with RULES2

*

*

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 § 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.
*
*
*
*
*
■ 15. Amend § 250.615 by:
■ a. Adding new paragraph (b)(5),
■ b. Redesignating paragraphs (e)
through (g) as (f) through (h), and
■ c. Adding new paragraph (e) to read
as follows:
§ 250.615

*

Blowout prevention equipment.

*
*
(b) * * *

*

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*

17:55 Oct 13, 2010

*

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*

The minimum BOP stack must include

*
*
*
*
*
*
(5) You use a subsea BOP stack ............................................................. The requirements in § 250.442(a) of this part.
*

*

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*

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Federal Register / Vol. 75, No. 198 / Thursday, October 14, 2010 / Rules and Regulations

(e) The subsea BOP system for wellworkover operations must meet the
requirements in § 250.442 of this part.
*
*
*
*
*
■ 16. Amend § 250.616 by adding new
paragraph (h) to read as follows:
§ 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.
§§ 250.617 and 250.618 [Redesignated as
§§ 250.618 and 250.619]

17. Redesignate §§ 250.617 and
250.618 to §§ 250.618 and 250.619,
respectively.
■ 18. Add new § 250.617 to read as
follows:
■

emcdonald on DSK2BSOYB1PROD with RULES2

§ 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 § 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

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Jkt 223001

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 § 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.
■ 19. In §§ 250.1500:
■ 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
■ b. Add definitions for ‘‘Deepwater
well control’’, ‘‘Well completion/well
workover’’, Well control’’, and ‘‘Well
servicing’’ in alphabetical order to read
as follows:
§ 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.
§ 250.1501

[Amended]

20. In §§ 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’’.

■

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§ 250.1503

[Amended]

21. In §§ 250.1503:
a. Redesignating paragraphs (b) and
(c) as paragraphs (c) and (d);
■ 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’’;
■ 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
■ d. Adding new paragraph (b) to read
as follows:
■
■

§ 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.
§ 250.1506

[Amended]

22. In §§ 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’’.

■

§ 250.1507

[Amended]

23. In §§ 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’’.
■ 24. Amend § 250.1712 by,
■ a. Revising paragraph (e) and (f)(14);
and
■ b. Adding new paragraph (g) to read
as follows:
■

§ 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

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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 § 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).
25. Amend § 250.1721 by:
■ a. Revising paragraphs (e) and (g)(3),
and
■ b. Adding new paragraph (h) to read
as follows:

emcdonald on DSK2BSOYB1PROD with RULES2

■

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§ 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

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(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 § 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 § 250.1712.
[FR Doc. 2010–25256 Filed 10–7–10; 11:15 am]
BILLING CODE 4310–MR–P

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14OCR2