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DEPARTMENT OF THE INTERIOR
Bureau of Safety and Environmental
Enforcement
30 CFR Part 250
Bureau of Ocean Energy Management
30 CFR Part 550
[Docket ID: BSEE–2019–0008, EEEE500000,
21XE1700DX, EX1SF0000.EAQ000]
RIN 1082–AA01

Oil and Gas and Sulfur Operations on
the Outer Continental Shelf—Revisions
to the Requirements for Exploratory
Drilling on the Arctic Outer Continental
Shelf
Bureau of Safety and
Environmental Enforcement (BSEE);
Bureau of Ocean Energy Management
(BOEM), Interior.
ACTION: Proposed rule.
AGENCIES:

The Department of the
Interior (DOI or Department), acting
through BOEM and BSEE, has reviewed
and is proposing to revise its existing
regulations for exploratory drilling and
related operations on the Arctic Outer
Continental Shelf (OCS), to reduce
unnecessary burdens on stakeholders
while ensuring that energy exploration
on the Arctic OCS is safe and
environmentally responsible. In
particular, this proposed rule would
revise certain requirements promulgated
through the rule entitled, Oil and Gas
and Sulfur Operations on the Outer
Continental Shelf-Requirements for
Exploratory Drilling on the Arctic Outer
Continental Shelf (‘‘2016 Arctic
Exploratory Drilling Rule’’). This
proposed rule would also add new
provisions to BSEE’s regulations
pertaining to suspensions of operations
(SOO), and BOEM’s Exploration Plan
(EP) and Development and Production
Plan (DPP) regulations.
DATES: Submit comments by February 8,
2021. BSEE and BOEM may not fully
consider comments received after this
date. You may submit comments to the
Office of Management and Budget
(OMB) on the information collection
burden in this proposed rule by January
8, 2021. The deadline for comments on
the information collection burden does
not affect the deadline for the public to
comment to BSEE and BOEM on the
proposed regulations.
ADDRESSES: You may submit comments
on BSEE’s or BOEM’s sections of the
rulemaking by any of the following
methods. For comments on this
proposed rule, please use the Regulation

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SUMMARY:

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Identifier Number (RIN) 1082–AA01 as
an identifier in your message. For
comments specifically related to the
draft Environmental Assessment (EA)
conducted under the National
Environmental Policy Act of 1969
(NEPA), please refer to NEPA in the
heading of your message. See also
Public Availability of Comments under
Procedural Matters.
• Federal eRulemaking Portal: http://
www.regulations.gov. In the entry
entitled, ‘‘Enter Keyword or ID,’’ enter
BSEE–2019–0008, then click search.
Follow the instructions to submit public
comments and view supporting and
related materials available for this
rulemaking. BSEE and BOEM may post
all submitted comments.
• Mail or hand-carry comments to the
DOI, BSEE and BOEM: Attention:
Regulations and Standards Branch,
45600 Woodland Road, VAE–ORP,
Sterling VA 20166. Please reference RIN
1082–AA01, ‘‘Oil and Gas and Sulfur
Operations on the Outer Continental
Shelf—Revisions to the Requirements
for Exploratory Drilling on the Arctic
Outer Continental Shelf,’’ in your
comments, and include your name and
return address.
• Send comments on the information
collection in this rule to: Interior Desk
Officer 1082–AA01, Office of
Management and Budget; 202–395–5806
(fax); or via the online portal at
RegInfo.gov. Please also send a copy to
BSEE and BOEM by one of the means
previously described.
• 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.
For BSEE and BOEM to withhold from
disclosure your personal identifying
information, you must identify any
information contained in the submittal
of your comments that, if released,
would constitute a clearly unwarranted
invasion of your personal privacy. You
must also briefly describe any possible
harmful consequence(s) of the
disclosure of information, such as
embarrassment, injury, or other harm.
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.
FOR FURTHER INFORMATION CONTACT: For
technical questions related to regulatory
changes BSEE is proposing in Part 250,
contact Mark E. Fesmire, BSEE, Alaska
Regional Office, [email protected],

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(907) 334–5300. For technical questions
related to regulatory changes BOEM is
proposing in Part 550, contact Joel
Immaraj, BOEM, Alaska Regional Office,
[email protected], (907) 334–
5238. For procedural questions contact
Bryce Barlan, BSEE, Regulations and
Standards Branch, [email protected], (703)
787–1126.
SUPPLEMENTARY INFORMATION:
Executive Summary
In response to BSEE- and BOEMinitiated environmental and safety
reviews of potential oil and gas
operations on the Arctic OCS,
experiences gained from Shell’s 2012
and 2015 Arctic operations, and
concerns expressed by environmental
organizations and Alaska Natives, BSEE
and BOEM published the 2016 Arctic
Exploratory Drilling Rule (see 81 FR
46478, July 15, 2016). The rule was
narrowly focused, applying solely to
exploratory drilling operations
conducted during the Arctic OCS openwater drilling season by drilling vessels
and ‘‘jack-up rigs’’ (collectively known
as mobile offshore drilling units or
MODU) in the Beaufort Sea and
Chukchi Sea Planning Areas. The
regulations were intended to ensure that
Arctic OCS exploratory drilling
operations are conducted in a safe and
responsible manner, while taking into
account the unique conditions of the
Arctic OCS, as well as Alaska Natives’
cultural traditions and their need for
access to subsistence resources. BSEE
and BOEM have since reviewed the
2016 Arctic Exploratory Drilling Rule
taking into account a Congressional
declaration of purposes in the Outer
Continental Shelf Lands Act (OCSLA) to
‘‘establish policies and procedures for
managing the oil and natural gas
resources of the Outer Continental Shelf
which are intended to result in
expedited exploration and development
of the Outer Continental Shelf in order
to achieve national economic and
energy policy goals, assure national
security, reduce dependence on foreign
sources, and maintain a favorable
balance of payments in world trade.’’ 1
The bureaus have also reviewed new
information about technological
developments in an ice environment.
Based on that review, BSEE and BOEM
are proposing revisions in this proposed
rule that are consistent with OCSLA,
and would reduce unnecessary burdens
on stakeholders while still maintaining
safety and environmental protection.
Since publication of the 2016 Arctic
Exploratory Drilling Rule, new
1 Outer Continental Shelf Lands Act, Public Law
95–372, sec. 102 (Sept. 8, 1978), 43 U.S.C. 1802(1)).

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Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules
Executive Orders (E.O.) and Secretary’s
Orders (S.O.) called on Federal agencies
to review existing regulations that
potentially burden the development or
use of domestically produced energy
resources and appropriately begin
processes to potentially suspend, revise,
or rescind those regulations that are
determined to unduly burden the
development of domestic energy
resources, beyond the degree necessary
to protect the public interest or
otherwise comply with the law.
Executive Order 13795, Implementing
an America-First Offshore Energy
Strategy (82 FR 20815) and Secretary’s
Order 3350, America-First Offshore
Energy Strategy, which are discussed in
more detail below in Section I.
Background, Subsection C. Executive
and Secretary’s Orders, specifically
called for a review of the 2016 Arctic
Exploratory Drilling Rule.2 In response
to these E.O.s and S.O.s, BSEE and
BOEM undertook a review of the
regulations promulgated through the
2016 Arctic Exploratory Drilling Rule
with a view toward encouraging energy
exploration and production on the
Arctic OCS, as appropriate and
consistent with applicable law, and
reducing unnecessary regulatory
burdens, while ensuring that any such
activity is safe and environmentally
responsible.
BSEE’s and BOEM’s views about
certain features of the existing
regulations were also informed by new
information that has become available
since the 2016 rule was finalized. This
new information includes a BSEEcommissioned Technology Assessment
Program (TAP) study entitled,
Suitability of Source Control and
Containment Equipment versus Same
Season Relief Well in the Alaska Outer
Continental Shelf Region (Bratslavsky
and SolstenXP, 2018) and a National
Petroleum Council (NPC) report
entitled, Supplemental Assessment to
the 2015 Report on Arctic Potential:
Realizing the Promise of U.S. Arctic Oil
and Gas Resources (NPC 2019 Report).
BSEE also re-assessed the original NPC
report entitled, Arctic Potential:
Realizing the Promise of U.S. Arctic Oil
and Gas Resources (NPC 2015 Report;
together with the NPC 2019 Report, the
NPC reports). Both NPC reports include
discussions about global Arctic
operations. These global operations are
discussed in further detail below in
Subsection 5. Industry Interest in the
Arctic OCS of Section I. Background,
under the subheading entitled, Global
2 These Orders did no dictate outcomes; rather,
they directed a review in accordance with
applicable law.

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Arctic Exploration Activities. The
Bratslavsky and SolstenXP study was
finalized in October 2018 and may be
downloaded from BSEE’s TAP website
at: https://www.bsee.gov/researchrecord/suitability-of-source-controlcontainment-equipment-versus-sameseason-relief-well. The NPC 2019 Report
was finalized in April 2019 and may be
downloaded from an NPC website at:
https://www.npc.org/ARSA-FINAL052219-LoRes.pdf. The NPC 2015
Report was finalized in March 2015 and
may be downloaded from an NPC
website at: http://
www.npcarcticpotentialreport.org/
index.html.
Based on the results of these reports,
BSEE and BOEM are proposing to
amend, revise, or remove certain current
regulatory provisions promulgated
through the 2016 Arctic Exploratory
Drilling Rule, to reduce unnecessary
burdens on stakeholders while still
maintaining safety and environmental
protection. This proposed rulemaking is
consistent with OCSLA’s Congressional
declaration of purposes to ‘‘establish
policies and procedures for managing
the oil and natural gas resources of the
Outer Continental Shelf which are
intended to result in expedited
exploration and development of the
Outer Continental Shelf in order to
achieve national economic and energy
policy goals, assure national security,
reduce dependence on foreign sources,
and maintain a favorable balance of
payments in world trade.’’ 43 U.S.C.
1802(1).
BSEE and BOEM also considered
another issue on the Arctic OCS in
addition to those addressed in the 2016
Arctic Exploratory Drilling Rule, but is
logical to address as part of this
rulemaking to further encourage safe
and environmentally responsible
exploration of this region, where the
areas known to have oil and gas have
been explored or studied. This issue
pertains to the effective means by which
BSEE and the operator could address
seasonal weather-related constraints in
the Arctic OCS that severely impact the
operator’s ability to safely perform
leaseholding operations for a significant
portion of the term on a lease.
Accordingly, this proposed rule
would revise certain provisions in 30
Code of Federal Regulations (CFR) Part
250, Subparts A, C, D, and G, and 30
CFR part 550, subpart B, that pertain to:
1. The factors that the BSEE Regional
Supervisor may evaluate in assessing
whether to grant an SOO, to address
unique and specific conditions relevant
only to exploration and development
activities on the Arctic OCS;
2. Pollution prevention;

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3. Arctic OCS Source Control and
Containment Equipment (SCCE);
4. Relief rig capabilities for the Arctic
OCS;
5. Timing and submission
requirements related to Integrated
Operations Plans (IOP) for proposed
Arctic exploratory drilling;
6. What must be included in the IOP;
and
7. What data and information must
accompany the EP and DPP.
This proposed rule is designed to
reflect the need to ensure the safe,
effective, and responsible exploration of
Arctic OCS oil and gas resources, while
protecting the marine, coastal, and
human environments, and preserving
Alaska Natives’ cultural traditions and
their access to subsistence resources.
This proposed rule is intended to revise
the regulations promulgated through the
2016 Arctic Exploratory Drilling Rule by
creating more flexible and less costly
compliance options in BSEE’s and
BOEM’s regulations that could achieve
these objectives. While this proposed
rule seeks to promulgate new provisions
in addition to those addressed in the
2016 Arctic Exploratory Drilling Rule,
these new provisions (i.e., provisions to
address leaseholding operations
impacted by seasonal weather-related
constraints on the Arctic OCS) would
further enhance BSEE’s and BOEM’s
abilities to ensure the safe, effective, and
responsible exploration of Arctic OCS
oil and gas resources. They would do so
while protecting the marine, coastal,
and human environments, and
preserving Alaska Natives’ cultural
traditions and access to subsistence
resources. Through lease stipulations
related to the Conflict Avoidance
Agreements (CAA), BOEM currently
requires operators to consult with
affected subsistence communities and
describe in exploration and
development plans the mitigating
practices the operator would undertake
to avoid conflicts with the communities.
Conflict Avoidance Agreements provide
a framework for mitigating the adverse
impacts a drilling project may have on
subsistence activities, values, and uses.
Table of Contents
I. Background
A. Overview of the Alaska Arctic Region
B. BSEE and BOEM Statutory and
Regulatory Authority and
Responsibilities
C. Executive and Secretary’s Orders
D. Purpose and Summary of the
Rulemaking
E. Partner Engagement in Preparation for
This Proposed Rule
II. Section-by-Section Discussion of Proposed
Changes
A. Key Revisions Proposed by BSEE

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Subpart A—General
• Definitions. (§ 250.105)
• When may the Regional Supervisor grant
an SOO? (§ 250.175)
• Documents incorporated by reference.
(§ 250.198)
Subpart C—Pollution Prevention and
Control
• Pollution prevention. (§ 250.300)
Subpart D—Oil and Gas Drilling
Operations
• What additional information must I
submit with my APD for Arctic OCS
exploratory drilling operations?
(§ 250.470)
• What are the requirements for Arctic
OCS source control and containment?
(§ 250.471)
• What are the additional well control
equipment or relief rig requirements for
the Arctic OCS? (§ 250.472)
Subpart G—Well Operations and
Equipment

• When and how must I secure a well?
(§ 250.720)
B. Key Revisions Proposed by BOEM
Subpart B—Plans and Information
• Definitions. (§ 550.200)
• Removal of § 550.204, When must I
submit my IOP for proposed Arctic
exploratory drilling operations and what
must the IOP include?
• How do I submit the EP, DPP, or DOCD?
(§ 550.206)
• What must the EP include? (§ 550.211)
• If I propose activities in the Arctic OCS
Region, what planning information must
accompany the EP? (§ 550.220)
III. Additional Comments Solicited on the
Same Season Relief Well and Relief Rig
Requirement
IV. Procedural Matters
A. Regulatory Planning and Review
(Executive Orders (E.O.) 12866, 13563,
and 13771)

B. Regulatory Flexibility Act and Small
Business Regulatory Enforcement
Fairness Act
C. Unfunded Mandates Reform Act of 1995
(UMRA)
D. Takings Implication Assessment
E. Federalism (E.O. 13132)
F. Civil Justice Reform (E.O. 12988)
G. Consultation With Indian Tribes (E.O.
13175)
H. Environmental Justice in Minority
Populations and Low-Income
Populations (E.O. 12898)
E.O. 12898
I. Paperwork Reduction Act (PRA)
J. National Environmental Policy Act of
1969 (NEPA)
K. Data Quality Act
L. Effects on the Nation’s Energy Supply
(E.O. 13211)
M. Clarity of Regulations

LIST OF ACRONYMS AND REFERENCES
60-Day report

Report to the Secretary of the Interior, review of Shell’s 2012 Alaska Offshore Oil and
Gas Exploration Program

2016 Arctic Exploratory Drilling Rule ..

Oil and Gas and Sulfur Operations on the Outer Continental Shelf-Requirements for Exploratory Drilling
on the Arctic Outer Continental Shelf, 81 FR 46478, July 15, 2016 (available at https://www.doi.gov/
sites/doi.gov/files/migrated/news/pressreleases/upload/Shell-report-3-8-13-Final.pdf.).
American Bureau of Shipping.
Alternative Compliance Program.
Alaska Department of Natural Resources.
Alaska Eskimo Whaling Commission.
Alaska National Interest Lands Conservation Act.
Alaska Native Claims Settlement Act.
Arctic National Wildlife Refuge.
Application for Permit to Drill.
American Petroleum Institute.
OCS within the Beaufort Sea and Chukchi Sea Planning Areas.
Alternative Well Kill System.
Bureau of Ocean Energy Management.
Bureau of Ocean Energy Management, Regulation and Enforcement.
Blowout Preventer.
Suitability of Source Control and Containment Equipment versus Same Season Relief Well in the Alaska
Outer Continental Shelf Region, October 2018.
Bureau of Safety and Environmental Enforcement.
Bureau of Land Management.
Conflict Avoidance Agreement.
Code of Federal Regulations.
Coastal Zone Management Act.
Clean Water Act.
Department of the Interior.
Det Norske Veritas and Germanischer Lloyd.
Development Operations Coordination Document.
Department of the Interior.
Development and Production Plan.
Environmental Assessment.
Environmental Impact Analysis.
Environmental Impact Statement.
Executive Order.
Exploration Plan.
Environmental Protection Agency.
Endangered Species Act.
Geological and geophysical.
Information Collection.
Inupiat Community of the Arctic Slope.
Integrated Operations Plan.
Initial Regulatory Impact Analysis.
International Whaling Commission.
Lower Marine Riser Package.
Maximum Anticipated Surface Pressures.
Marine Mammal Protection Act.
Minerals Management Service.
Mobile Offshore Drilling Unit.

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ABS .....................................................
ACP .....................................................
ADNR ..................................................
AEWC ..................................................
ANILCA ...............................................
ANCSA ................................................
ANWR .................................................
APD .....................................................
API .......................................................
Arctic OCS ..........................................
AWKS ..................................................
BOEM ..................................................
BOEMRE .............................................
BOP .....................................................
Bratslavsky and SolstenXP, 2018 .......
BSEE ...................................................
BLM .....................................................
CAA .....................................................
CFR .....................................................
CZMA ..................................................
CWA ....................................................
Department ..........................................
DNV GL ...............................................
DOCD ..................................................
DOI ......................................................
DPP .....................................................
EA ........................................................
EIA .......................................................
EIS .......................................................
E.O. .....................................................
EP ........................................................
EPA .....................................................
ESA .....................................................
G&G ....................................................
IC .........................................................
ICAS ....................................................
IOP ......................................................
IRIA .....................................................
IWC .....................................................
LMRP ..................................................
MASP ..................................................
MMPA ..................................................
MMS ....................................................
MODU .................................................

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LIST OF ACRONYMS AND REFERENCES—Continued
60-Day report

Report to the Secretary of the Interior, review of Shell’s 2012 Alaska Offshore Oil and
Gas Exploration Program

NAICS .................................................
NEPA ...................................................
NMFS ..................................................
NOAA ..................................................
NPC .....................................................
NPC 2015 Report ................................
NPC 2019 Report ................................

North American Industry Classification System.
National Environmental Policy Act of 1969.
National Marine Fisheries Service.
National Oceanic and Atmospheric Administration.
National Petroleum Council.
Arctic Potential: Realizing the Promise of U.S. Arctic Oil and Gas Resources.
Supplemental Assessment to the 2015 Report on Arctic Potential: Realizing the Promise of U.S. Arctic
Oil and Gas Resources.
National Pollutant Discharge Elimination System.
National Petroleum Reserve—Alaska.
North Slope Borough.
Notice to Lessees and Operators.
Outer Continental Shelf.
Outer Continental Shelf Lands Act.
Ocean Discharge Criteria Evaluations.
Office of Information and Regulatory Affairs.
Office of Management and Budget.
Office of Natural Resources Revenue.
Oil Spill Response Plan.
Permanent Fund Dividend.
Paperwork Reduction Act.
pounds per square inch per foot.
Regulation Identifier Number.
Remotely Operated Vehicle.
Recommended Practice.
Source Control and Containment Equipment.
Secretary of the Interior.
Secretary’s Orders.
Safety and Environmental Management Systems.
Subsea Isolation Device.
Same Season Relief Well.
Suspensions of Operations.
Technology Assessment Program.
Trans-Alaska Pipeline System.
Trillion Cubic Feet.
Unfunded Mandates Reform Act of 1995.
United States.
U.S. Coast Guard.
U.S. Fish and Wildlife Service.
United States Geological Survey.
Barrow.
Worst Case Discharge.

NPDES ................................................
NPR–A ................................................
NSB .....................................................
NTL ......................................................
OCS .....................................................
OCSLA ................................................
ODCE ..................................................
OIRA ...................................................
OMB ....................................................
ONRR ..................................................
OSRP ..................................................
PFD .....................................................
PRA .....................................................
psi/ft .....................................................
RIN ......................................................
ROV .....................................................
RP .......................................................
SCCE ..................................................
Secretary .............................................
S.O. .....................................................
SEMS ..................................................
SSID ....................................................
SSRW ..................................................
SOO ....................................................
TAP .....................................................
TAPS ...................................................
TCF .....................................................
UMRA ..................................................
U.S. .....................................................
USCG ..................................................
USFWS ...............................................
USGS ..................................................
Utquiavik ..............................................
WCD ....................................................

I. Background
A. Overview of the Alaska Arctic Region

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1. History of Arctic Oil and Gas
Development
Although Alaska’s first oil production
is attributable to the 1957 Swanson
River discovery on the Kenai Peninsula,
oil and gas resources have been known
to exist in the Arctic since as early as
1839. Early explorers had reported that
Alaska Natives on the Arctic coast used
oil-soaked tundra for fuel. The oil came
from natural oil seeps on the ground.
However, the extent of the resource, as
well as the State’s overall oil and gas
endowment, would not be realized until
the discovery of the Arctic’s Prudhoe
Bay oil field on the North Slope and
completion of the Trans-Alaska Pipeline
System (TAPS) in 1977.
The Prudhoe Bay field was discovered
on March 12, 1968, with the drilling of

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the Prudhoe Bay State #1 well. BP
Exploration drilled a confirmation well
the following year. However, production
did not come online until June 20, 1977,
after the TAPS was completed and other
companies with lease holdings in the
area undertook a host of activities to
delineate the reservoir, resolve equity
participation, and put together initial
infrastructure for the field. After over 40
years of production, Prudhoe Bay
remains the largest oil field in North
America and is the 18th largest field
ever discovered worldwide.3 According
to data maintained by the Alaska Oil
and Gas Conservation Commission,
Alaska’s North Slope has produced over
17.3 billion barrels of oil, with Prudhoe
Bay contributing approximately 68
3 https://dec.alaska.gov/spar/ppr/response/sum_
fy06/060302301/factsheets/060302301_factsheet_
PB.pdf.

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percent of that amount.4 Currently, the
only offshore Federal production in the
Arctic OCS 5 is Hilcorp’s Northstar field,
which includes both State and Federal
acreage in the 8(g) Zone.6 Located in the
Beaufort Sea about 12 miles northwest
of Prudhoe Bay, this prospect has been
producing since 2001. Over 150 million
barrels of oil have been produced to
date at Northstar. In 2019, the Federal
Government received nearly $5 million
in royalty payments from oil production
on Federal leases at Northstar, and from
2003 to 2018, royalty payments ranged
4 http://aogweb.state.ak.us/DataMiner3/Forms/
Production.aspx.
5 There are Federal OCS leases that do not have
ongoing production in the Cook Inlet, which is not
considered part of the Arctic.
6 Section 8(g) of the OCSLA requires the Federal
Government to share with the State of Alaska 27%
of revenue from leases in the 8(g) Zone (the first
three nautical miles of the Outer Continental Shelf).
43 U.S.C. 1337(g).

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from $3 million to over $20 million in
any given year. In 2019, the Federal
Government disbursed just over $1.5
million to the State of Alaska for
Northstar Federal leases in the 8(g)
Zone.7
The construction of TAPS enhanced
the significance of the Arctic’s
production to the State of Alaska. TAPS
is an 800-mile-long pipeline system that
was designed to accommodate the
transport of over 2 million barrels of oil
per day. The pipeline begins at Prudhoe
Bay and stretches south to Valdez in
southern Alaska, which is the
northernmost ice-free port in North
America. TAPS is one of the world’s
largest pipeline systems, an engineering
icon that was the biggest privately
funded construction project when it was
constructed in the 1970s. At peak flow
in 1988, 11 pump stations helped to
move 2.1 million barrels of oil a day.8
2. Budgetary Economic Impact on the
People of Alaska
North Slope Alaska oil and gas
exploration and production has been a
significant economic driver, not only to
the State of Alaska and Alaskan Native
communities, but also to the national
domestic energy supply. The State’s oil
and gas endowments have provided
greater economic prosperity to its
people than other important resources
in the State. Specifically, Alaska relies
on revenues generated from oil and gas
resources, along with other revenuegenerating streams, to fund a major
portion of the State’s operating and
capital budgets. This has allowed
Alaska to be the only State in the United
States that does not have either a State
sales tax or personal income tax. Oil and
gas revenues are generated by means of
a variety of taxes, royalties, and other
charges related to oil and gas
development and production. Other
examples of revenue-generating streams
for Alaska include corporate income,
fuel, alcohol, and tobacco taxes. In 2016,
72 percent of Alaska’s unrestricted
general funds, which come from the
State’s overall revenue-generating
stream, were derived from oil and gas
revenues and were available to the
State’s budget.9 In 2012, as much as 93
percent of Alaska’s unrestricted general
funds were derived from oil and gas
revenues and were also available to the
State’s budget.10 The reduced
contribution of oil and gas-generated
7 https://revenuedata.doi.gov/downloads/
disbursements/.
8 https://www.alyeska-pipe.com/TAPS.
9 https://www.legfin.akleg.gov/, Budget History
Data (Excel) (posted 1–15–2020), Row 59.
10 https://www.legfin.akleg.gov/, Budget History
Data (Excel) (posted 1–15–2020), Row 55.

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revenue to the State’s budget since 2012
is due primarily to declining oil
production in the North Slope, but also
due to a general downward trend in oil
prices.
Aside from annual State operating
and capital budgets, several Statewide
government programs established for
the benefit of the people of Alaska are
largely dependent on oil and gas-related
revenues, most notably the Alaska
Permanent Fund. In 1976, Alaska’s State
constitution was amended to establish
the Alaska Permanent Fund, which
provides that at least 25 percent of all
mineral lease rentals, royalties, royalty
sale proceeds, Federal mineral revenue
sharing payments, and bonuses received
by the State are to be placed in a
permanent fund, known as the Alaska
Permanent Fund, the principal of which
is used only for income-producing
investments. All income generated from
the permanent fund is available for
distribution to all Alaskan residents—
adults and children—on an annual basis
through the State’s Permanent Fund
Dividend (PFD) program.11 Since 1978,
this fund has grown to a total fund value
of $60 billion as of March 2020.12
Individual distributions to Alaskans
from the fund have ranged from $386
per person to as high as $2,072 per
person.13 These annual payments are
estimated to have lifted between 15,000
and 25,000 Alaskans above the Federal
poverty line.14
Much of the North Slope Borough’s
economy is tied to the oil and gas
industry, primarily in the greater
Prudhoe Bay region. Some borough
residents have rotational work in the
oilfields or in a position supporting the
oil industry, but the greatest
contribution to the economy is through
tax revenue. The borough assesses
property taxes on infrastructure, the
primary funding source for the
borough’s operations and capital
projects, which include building roads,
operating schools, and funding for other
public services, such as health clinics
and fire departments.15
In March and April of 2020, global oil
prices experienced significant volatility
11 https://apfc.org/frequently-asked-questions/
#why-did-alaskans-create-the-fund.
12 https://apfc.org/our-performance/.
13 https://pfd.alaska.gov/Division-Info/Summaryof-Applications-and-Payments.
14 Berman, Matt., Random Reamy. ‘‘Permanent
Fund Dividends and Poverty in Alaska.’’ Institute
of Social and Economic Research, University of
Alaska Anchorage. (November 2016), available
online at: https://iseralaska.org/static/legacy_
publication_links/2016_12-PFDandPoverty.pdf. p.
25 of pdf.
15 http://www.north-slope.org/assets/images/
uploads/13_Economic_Development_-_NSB_
Comprehensive_Plan.pdf.

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due to a confluence of events, including
decreased demand from coronavirus
effects, as well as production output
negotiations between OPEC and Russia.
These events caused the price of oil to
slide to 17-year lows. While prices have
already partially recovered and
stabilized, this could affect interest and
activity in the region if the low-price
environment continues into the future,
as drilling and other exploration
activities in the Arctic are more
expensive than other regions. Given the
long period of time before exploratory
drilling in the Arctic is expected to start
and the short-term nature of the
underlying price events, the Bureaus
expect that prices will continue to
rebound. The events in 2020 also
underscore the importance of ensuring
that BOEM and BSEE regulations are no
more burdensome than necessary to
protect safety and the environment.
3. Arctic Resource Potential and
Geology
The Arctic region is characterized by
its extensive oil and gas resources. The
Arctic Alaska Petroleum Province,
which consists of up to 43 geologic
plays between the Chukchi Sea and the
Beaufort Sea planning areas, extends
about 684 miles from the United StatesCanadian border westward to the
maritime boundary with Russia, and
from 62 to 372 miles northward from
the Brooks Range to the approximate
edge of the Continental Shelf. Although
the edge of the Continental Shelf
provides a well-defined physiographic
boundary for the province, this edge
does not represent a geologic limit to
potential petroleum resources. The
offshore part of the province is
characterized by a relatively narrow (62mile-wide) shelf in the Beaufort Sea and
a broad (372-mile-wide) shelf in the
Chukchi Sea. The province is bounded
onshore on the south by the Brooks
Range-Herald mountain range and
offshore to the north by the passive
continental margin of the Canada
Basin.16 In general, the formations are
fairly continuous across the Arctic
Alaska Petroleum Province.
Although most of the Arctic’s oil
production to date is attributed to the
North Slope, most of the undiscovered
resources are located off the Arctic
coast, within the Chukchi Sea and
Beaufort Sea Planning Areas. According
to BOEM’s 2016 Assessment of
Undiscovered Technically Recoverable
Oil and Gas Resources of the Nation’s
16 Houseknecht, D.W., and Bird, K.J., 2006, Oil
and gas resources of the Arctic Alaska petroleum
province: U.S. Geological Survey Professional Paper
1732–A, 11 p., available online at: http://
pubs.usgs.gov/pp/pp1732/pp1732a/.

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Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules
OCS (mean estimates available at http://
www.boem.gov/National-Assessment2016/), there are approximately 23.6
billion barrels of undiscovered
technically recoverable oil and about
104.4 trillion cubic feet (TCF) of
technically recoverable natural gas
(mean estimates) in the combined
Beaufort Sea and Chukchi Sea Planning
Areas. BOEM re-assessed its Beaufort
Sea Planning Area estimates due to
recent onshore discoveries in the
National Petroleum Reserve-Alaska
(NPR–A) from two formations that
extended offshore. In December 2017,
BOEM published its updated reassessment (mean estimates available at
https://www.boem.gov/2016a-NationalAssessment-Fact-Sheet/), which
estimated that there are approximately
24.3 billion barrels of technically
recoverable oil and about 104. TCF of
technically recoverable natural gas in
the combined Beaufort Sea and Chukchi
Sea Planning Areas; an increase of about
680 million barrels of oil and 100 billion
cubic feet of natural gas. Of the 24.3
billion barrels of oil, the Chukchi Sea
Planning Area makes up about 63% of
the estimate, while the Beaufort Sea
Planning Area makes up 37%. With
respect to gas, the Chukchi Sea Planning
Area makes up about 73% of the 104.5
TCF of gas and the Beaufort Sea
Planning Area makes up 27% of the
estimate. These estimates represent
about one-quarter of the technically
recoverable oil resources and one-third
of the technically recoverable gas
resources on the OCS.
While not as large, the Arctic’s
onshore undiscovered oil and gas
resources are also considerable. In
January 2020, the United States
Geological Survey (USGS) published an
assessment of undiscovered oil and gas
resources in the central portion of the
Alaska North Slope, (mean estimates
available at https://pubs.usgs.gov/fs/
2020/3001/fs20203001.pdf). The
assessment estimated that there are
approximately 3.6 billion barrels of
undiscovered technically recoverable oil
and about 8.9 TCF of undiscovered
technically recoverable natural gas
resources on State and Native lands, and
State waters, east of the NPR–A and
west of the Arctic National Wildlife
Refuge (ANWR). According to a 2017
USGS assessment of undiscovered oil
and gas resources in the Alaska North
Slope, (mean estimates available at
https://pubs.usgs.gov/fs/2017/3088/
fs20173088.pdf), there are
approximately 8.8 billion barrels of
undiscovered technically recoverable oil
and about 39 TCF of undiscovered
technically recoverable natural gas in

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the NPR–A. In addition, USGS’s
assessment of the 1002 Area 17 of the
ANWR estimated (mean estimates
available at https://pubs.usgs.gov/of/
2005/1217/pdf/2005-1217.pdf) there are
7.6 billion barrels of technically
recoverable oil and 7.04 18 TCF of
technically recoverable natural gas.
Efforts are already underway to bring
some of these new onshore resources
online. Collectively, these offshore and
onshore assets are enormous, and most
of the resources are located offshore.19
However, the Arctic OCS’s vast
potential has yet to be realized.
In the Arctic, the circumstances
associated with drilling from a MODU
can be different than those in the Gulf
of Mexico. The geological pressures in
the hydrocarbon bearing zones in the
shallow seas of Alaska’s Arctic are, in
many cases, likely to be substantially
lower than those encountered during
the Deepwater Horizon incident,
reducing certain risk factors of a major
blowout. As reviewed by the NPC,
through the NPC 2019 Report,
subsurface conditions (below the
seafloor) for the Arctic OCS—geology,
pressure, resource depth, and drilling
depth—are much simpler as compared
to other areas, such as the deepwater
Gulf of Mexico OCS. The NPC 2019
Report states that the targeted Arctic
potential reservoirs are shallow and
normally pressured, but that exploration
and development are dominated by
other challenges, such as water depth,
ice conditions, and the length of the
open-water season, which make the
Arctic unique (NPC 2019 Report at 10).
The NPC 2015 Report found, however,
that most of the U.S. Arctic offshore
conventional oil and gas potential can
17 The Alaska National Interest Lands
Conservation Act (ANILCA) of 1980 required
ANWR to be managed as a protected wilderness.
Section 1002 of ANILCA, however, deferred a
decision regarding future management of a 1.5
million-acre coastal plain portion of ANWR (known
as the ‘‘1002’’ area) in order to continuously study
the various natural resources on the coastal plain,
and analyze how oil and gas exploration,
development, and production could potentially
impact those resources. Section 20001 of the Tax
Cuts and Jobs Act of 2017 lifted a provision in
Section 1003 of ANILCA that prohibits oil and gas
leasing and production in the 1002 area, and the
BLM is in the process of developing an oil and gas
leasing program for that area.
18 This value represents the combined estimates
of natural gas that could technically be produced
from gas fields as well as associated gas that could
be produced from oil fields.
19 D.L. Gautier et al., ‘‘Circum-Arctic Resource
Appraisal: Estimates of Undiscovered Oil and Gas
North of the Arctic Circle,’’ U.S. Geological Survey,
USGS Fact Sheet 2008–3049, 2008. M.E. Brownfield
et al., ‘‘An Estimate of Undiscovered Conventional
Oil and Gas Resources of the World,’’ U.S.
Geological Survey, USGS Fact Sheet 2012–3024,
2012, available at https://pubs.usgs.gov/fs/2008/
3049/fs2008-3049.pdf.

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be developed using existing fieldproven technology, which was
reaffirmed by the NPC 2019 Report
(NPC 2015 Report at 28).
As identified by the NPC, targeted
potential reservoirs in the Arctic OCS
may be shallow and normally
pressured.20 However, this condition is
not consistent throughout all areas in
the Arctic OCS that have already been
explored. For example, a study
published by the American Rock
Mechanics Association 21 analyzed
wells drilled in the Chukchi Sea in
order to provide an improved
interpretation and delineation of pore
pressure in the Chukchi shelf region. A
majority of the wells contained
significant overpressure at depths
ranging from 1,098 to 2,317 meters (i.e.,
3,602 to 7,601 feet) subsea. In the
Beaufort Sea, the Alaska Department of
Natural Resources (ADNR) noted that, as
part of its findings to support Beaufort
Sea areawide oil and gas lease sales,22
operators may reasonably expect to
encounter extremely high pore
pressures along the central Beaufort Sea
region where ‘‘ . . . Cenozoic strata
(sedimentary layers) are very thick, such
as in the Kaktovik, Camden, and Nuwuk
Basins,’’ and suggests that challenges
from over pressured areas could be
reduced by ‘‘. . . identifying locations
of overpressured sediments via seismic
data analysis, and then adjusting the
mud mixture accordingly as the well is
drilled.’’ In the Point Thomson area, for
example, where drilling has taken place
from an onshore facility into a reservoir
located primarily offshore, the pore
pressure gradients were measured as
high as 0.8 pounds per square inch per
foot (psi/ft) at depths of 2.5 miles
(13,200 feet). A pore pressure gradient
of 0.433 psi/ft is considered normal in
this area.23
20 ‘‘Normally pressured’’ is not defined in the
NPC 2019 Report. However, as a general matter,
normal pressure generally refers to the hydrostatic
pressure within a well. ‘‘Normally pressured’’ refers
to conditions present when formation pressures are
predictable at any given depth and follow a normal
formation pressure gradient or ‘‘hydrostatic
pressure gradient.’’ Normal formation pressure, at
any given depth, equals the normal formation
pressure gradient multiplied by the depth. The
normal pressure is expressed in pounds per square
inch (psi).
21 Elowe, K.E., & Sherwood, K.W., 2017,
‘‘Abnormal Formation Pressure in the Chukchi
Shelf, Alaska,’’ American Rock Mechanics
Association Conference Paper, Document ID
ARMA–2017–0194, available online at https://
www.onepetro.org/conference-paper/ARMA-20170194.
22 Alaska Department of Natural Resources, 2019,
‘‘Beaufort Sea Areawide Oil and Gas Lease Sales,’’
p. 3–20, available online at https://aws.state.ak.us/
OnlinePublicNotices/Notices/View.aspx?id=193811.
23 Craig, J.D., K.W. Sherwood, and P.P. Johnson.
1985. Geologic report for the Beaufort Sea planning

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While these reports’ findings do not
fully align with the NPC’s findings,
there are other sources of information
confirming that, to a certain degree,
typical geologic conditions in the Arctic
OCS are normally pressured. For
example, a BOEM report that studied
the Chukchi Sea’s Burger gas discovery
calculated the pore pressure gradient for
one of the Chukchi Sea wells in the
study to be 0.44 psi/ft up to 4,850 feet
subsea, which the report determined to
be normally pressured. However,
beneath 4,850 feet, the pore pressure
gradient became over-pressurized
having a pore pressure gradient of 0.88
psi/ft.24 For the Beaufort Sea, a USGS
report analyzed pressure data from five
offshore wells and found that the
pressures in the area where the wells
were located were normally pressured
(i.e., at hydrostatic pressure) up to 2,000
feet subsea, and increased only slightly
above hydrostatic pressure deeper into
the well. By 10,000 feet, however, the
pressure in all five wells were overpressured, 1.5 times higher than the
hydrostatic pressure.25 Over-pressure
started to occur at around 6,700 feet
subsea.
While it is not possible to confirm
that all targeted potential reservoirs
would be shallow and normally
pressured in all exploratory drilling
situations, BSEE and BOEM will have
access to the relevant geologic and
geophysical information to help identify
hydrocarbon bearing zones and zones
with potential geologic risk, such as
over-pressurized zones, that may be
encountered during drilling operations.
These higher pressured, hydrocarbon
zones are, in fact, the targeted
formations the industry has attempted
to produce. For example, the BOEM
report analyzing the Chukchi Sea’s
Burger gas discovery illustrated the
regional geology of all the wells
included in the study, and showed that
the higher pressured zones in the wells
occurred at the same point where the
area, Alaska: Regional geology, petroleum geology,
environmental geology. U.S. Department of the
Interior, Minerals Management Service, Alaska OCS
Region, OCS Report MMS 85–0111. Anchorage,
Alaska. https://www.boem.gov/BOEM-Newsroom/
Library/Publications/1985/85_0111.aspx.
24 Craig, J.D., & Sherwood, K.W., 2001 (revised
2004), ‘‘Economic Study of the Burger Gas
Discovery, Chukchi Shelf, Northwest Alaska,’’ U.S.
Department of the Interior, Minerals Management
Service, p. 67, available online at https://
www.boem.gov/sites/default/files/boem-newsroom/
Library/Publications/2004/Economic-Study-of-theBurger-Gas-Discovery.pdf.
25 Hayba, D.O., Houseknecht, D.W., and Rowan,
E., 1999, ‘‘Stratigraphic, Hydrogeologic, and
Thermal Evolution of the Canning River Region,
North Slope, Alaska,’’ U.S. Department of the
Interior, U.S. Geological Survey, p. FF–21, available
online at https://pubs.usgs.gov/of/1998/ofr-980034/FF.pdf.

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oil-bearing zones were located.26 The
Bureaus have the means, through access
to relevant geological and geophysical
(G&G) data and drilling application
regulatory reviews, to confirm that
operators identify and plan for these
potential risks. For example, the
bureaus confirm that operators have
properly designed well casing and
drilling programs and ensure that
operators have access to properly
designed equipment that is readily
available to quickly respond to an
incident, such as the availability of a
capping stack in advance of drilling into
the targeted productive zones.
4. Partnership With Alaska Natives in
Northern Alaska
The bowhead whale provides the
largest subsistence resource available to
the native villages of Alaska’s northern
shores. In 1977, Eskimo whalers from
these villages established the Alaska
Eskimo Whaling Commission (AEWC),
whose mission is to safeguard the
bowhead whale and its habitat, defend
the Aboriginal Subsistence Whaling
Rights of their members, and preserve
the cultural and traditional values of
their villages. Eskimo whalers
established the AEWC in response to
actions taken by the International
Whaling Commission (IWC) that
resulted in the IWC’s assumption of
direct jurisdiction over the Alaskan
Native bowhead whale subsistence
hunt, without Alaska Native input. The
IWC assumed direct jurisdiction over
Alaska Native’s bowhead whale
subsistence in response to the IWC’s
concerns regarding the decline in the
western Arctic bowhead whale stock.
The IWC’s only mechanism for
protecting whale stocks is the setting of
hunting quotas. Therefore, the IWC’s
only recourse for addressing its
concerns was to prohibit the Alaska
Native bowhead whale subsistence
hunt. This action devastated local
communities, creating immediate and
severe food shortages. In response, in
1981, the AEWC was able to establish an
agreement with the Federal Government
to co-manage the bowhead whale
hunting quotas.
Although the AEWC was able to
regain control of its bowhead whale
hunting quotas, the organization shared
a similar concern with the IWC
regarding the potential effects of
26 Craig, J.D., & Sherwood, K.W., 2001 (revised
2004), ‘‘Economic Study of the Burger Gas
Discovery, Chukchi Shelf, Northwest Alaska,’’ U.S.
Department of the Interior, Minerals Management
Service, p. 72, available online at https://
www.boem.gov/sites/default/files/boem-newsroom/
Library/Publications/2004/Economic-Study-of-theBurger-Gas-Discovery.pdf.

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offshore oil exploration and
development on the bowhead whale.
Whalers observed how bowhead whales
were responding to the presence of
ocean-going oil and gas industry
exploration vessels, which were making
the whales skittish and affecting the
whalers’ ability to effectively meet the
quotas for their communities. In
response, the AEWC worked with
industry stakeholders to establish the
‘‘Oil/Whaler Agreement,’’ which was a
communication plan between whalers
and exploration vessels that was
intended to prevent direct threats to the
whalers’ safety from industry vessels.
The AEWC and industry stakeholders
eventually turned the ‘‘Oil/Whaler
Agreement’’ into a framework for
understanding and addressing indirect
interference with hunting activities,
resulting from behavioral changes in
bowhead whales as they react to the
noise and other pollutants
accompanying oil and gas work. This
framework of understanding eventually
formed the basis of what is now known
as a CAA.27 While DOI does not require
executing a CAA, BSEE and BOEM
highly encourage operators to work with
the AEWC to establish CAAs, since
these agreements essentially
acknowledge, within CAA provisions,
that both subsistence hunting activities
and oil and gas development can and
should coexist. See discussion in
Section I.E.3, History and Background
on the Conflict Avoidance Agreement,
of this preamble describing the
provisions typically included in a CAA.
This longstanding process allows for
industry representatives to sit, in
council, with members of the AEWC,
local tribes, and village and regional
corporations to determine cultural
circumstances and situations that could
cause conflict—and thus avoid them.
For example, during whale (or walrus)
hunting seasons in the spring and fall,
the CAA may include provisions
whereby industry will avoid
construction or production noise and
related activities during those times
when whales are transiting nearby, and
the hunters are in the area. With this
early initiative, direct collaboration with
local hunters, specifically the whaling
captains and their representative
organization, the AEWC, became a
critical element of offshore industrial
development planning and management
in the Alaskan Arctic.
Today, the AEWC includes registered
whaling captains and their crews from
eleven whaling communities of the
27 Conflict Avoidance Agreements are contracts
signed by the operators and the Alaska native
communities to which BOEM is not a party.

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Arctic Alaska coast: Gambell, Savoonga,
Wales, Little Diomede, Kivalina, Point
Hope, Point Lay, Wainwright, Barrow 28
(Utquiavik), Nuiqsut, and Kaktovik. The
AEWC often represents the Inupiat
Community of the Arctic Slope (ICAS)
in matters pertaining to energy
exploration or development specifically
for the OCS. The ICAS is a unique
federally recognized tribal entity. ICAS
membership is based on an individual’s
ancestral lineage to a village tribe; it
includes the peoples of eight Native
Villages: Kaktovik, Atqasuk, Nuiqsut,
Anaktuvuk Pass, Barrow, Wainwright,
Point Lay, and Point Hope. Each village
tribe acts independently but will
interact with ICAS and its membership
as it relates to Federal and State energy
issues.
Conflict avoidance tools are often
incorporated into leasing stipulations
addressing consultation with
subsistence communities, and will
continue to be essential to help satisfy
the need to provide a secure source of
energy for the Nation while at the same
time protecting the subsistence
resources and uses of the local
communities where these energy
resources are located.
5. Industry Interest in the Arctic OCS
In 1979, a year after the first Arctic
offshore discovery (i.e., the Endicott oil

field) was made in State waters, the
Department, acting through the Bureau
of Land Management (BLM), held the
first oil and gas lease sale in the Arctic
OCS, offering tracts adjacent to Prudhoe
Bay in the Beaufort Sea Planning Area.
That sale resulted in 24 leases, covering
85,776 acres, being issued. Although it
was the first sale ever conducted for the
Arctic OCS, the revenues generated
from that sale, over $491 million, make
it the 4th largest sale in Arctic OCS
history. That dollar amount would
represent almost $1.9 billion dollars in
2019 after adjusting for inflation.
Between 1979 and 2008, the
Department, acting through the BLM
and Minerals Management Service
(MMS),29 held 13 oil and gas lease sales,
and issued nearly 1,800 leases, covering
over 9.7 million acres, on the Arctic
OCS. These sales generated over $6.8
billion in bonus bids. As many as 23
companies/bidders have participated in
an Alaska OCS lease sale and, while the
number of companies/bidders
participating from one sale to the next
varied, an average of 10 companies/
bidders participated in each sale.
By 2008, U.S. oil production had been
steadily declining for 5 years to an
average of 5 million barrels per day,
while U.S. consumption of crude oil
and petroleum products reached an alltime high of 20.68 million barrels per

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day.30 The price of oil increased steadily
through 2007 from approximately $50 to
$90 per barrel by the time the most
recent Arctic sale, Lease Sale 193, was
held in February of 2008.31 These
market factors may have contributed to
the outcome of Lease Sale 193, one of
the most successful in Arctic OCS
history, based on multiple metrics—the
number of bids received, the number of
tracts receiving bids, and the total
amount of bonus bids received from the
sale. The MMS received a total of 667
bids on 488 blocks; both record-setting
numbers for the Arctic OCS. A total of
487 leases, covering over 2.7 million
acres, were issued, and the sale
generated over $2.6 billion in bonus
bids, which went to the U.S. Treasury.
Since 2008, however, the Department
has not conducted any new lease sales
for the Arctic OCS. A description of the
status of active leases in the Artic OCS
is discussed in further detail below
within this subsection, prior to the
subheading entitled, Global Arctic
Exploration Activities.
Sale 193 was significant, not only in
number of tracts sold and the amount
received from the sale, but in that the
industry’s interest spurred a flurry of
activities on the Arctic OCS prior to and
after the sale. The following table lists
those activities:

2006

June 20 ..............

MMS authorizes ConocoPhillips, Shell, and GX Technology Corporation to conduct geophysical operations for a portion
of Chukchi Sea Planning Area, which covered the Sale 193 area.
2007

July 13 ...............

MMS authorizes Shell to conduct additional geophysical operations in Chukchi Sea Planning Area covering the same
area as their 2006 geophysical permit.
2008

February 6 .........
February 15 .......

MMS holds Chukchi Sea Lease Sale 193. Seven companies were issued leases from this sale—NACRA; Repsol; Shell;
ConocoPhillips; Eni Petroleum; StatoilHydro; and Iona Energy Company.
MMS authorizes Shell to conduct even further geophysical operations, also covering the same area as their 2006 geophysical permit.
2009

May 9 ................

Shell submits its initial EP for the Chukchi Sea.
2010

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April 10 .............
May 19 ..............
June 18 ..............
August 8 ............

BP Deepwater Horizon Incident—Blowout of the Macondo well (Gulf of Mexico).
Secretary’s Order 3299 reorganizing the Minerals Management Service and dividing its functions between three separate
bureaus.
Secretary’s Order 3302 creating the Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE).
BOEMRE authorizes Statoil to conduct geophysical operations within and around the area where their leases were located in the Chukchi Sea Planning Area.

28 Although the Alaska Native tribe is based in
Utquiavik, at any given time, the whaling may
involve members of the Apugauti and Nalukatq
tribes, whose native lands do not border the coast.
For this reason, the AEWC prefers to refer to this

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group of whaling captains collectively by the
broader term ‘‘Barrow.’’
29 MMS was the predecessor agency of BSEE and
BOEM.
30 https://www.eia.gov/dnav/pet/hist/
LeafHandler.ashx?n=PET&s=MTTUPUS2&f=A,

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table entitled, ‘‘U.S. Product Supplied of Crude Oil
and Petroleum Products (Thousand Barrels per
Day)’’.
31 https://www.eia.gov/dnav/pet/hist/
LeafHandler.ashx?n=PET&s=F000000__3&f=M.

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December 7 .......

BOEMRE conditionally approves Shell’s initial EP for the Chukchi Sea.
2011

May 11 ..............
August 29 ..........
December 16 .....

Shell submits a revised EP for the Chukchi Sea.
Secretary’s Order 3299 was amended to divide BOEMRE into the Bureau of Ocean Energy Management (BOEM), the Bureau of Safety and Environmental Enforcement (BSEE), and the Office of Natural Resources Revenue (ONRR).
BOEM conditionally approves Shell’s revised EP for the Chukchi Sea.
2012

August 30 ..........
September 9 ......
September 20 ....
October 3 ...........

BSEE authorizes Shell to initiate certain limited preparatory exploration drilling activities; drilling of the top hole for
Burger A exploration well in the Chukchi Sea.
Shell begins drilling operations for its Burger A exploration well in the Chukchi Sea, but was not able to complete its
well operations. Shell returned in 2016 to complete its well operations, ultimately plugging and abandoning the well.
While not applicable to the Chukchi Sea, BSEE also authorizes Shell to initiate drilling of the top hole for the Sivuliq N
exploration well in the Beaufort Sea.
Shell begins drilling operations for its Sivuliq N exploration well in the Beaufort Sea, but was not able to complete its
well operations. Shell returned in 2016 to complete its well operations, ultimately plugging and abandoning the well.
2013

August 5 ............
November 6 .......

BOEM authorizes TGS to conduct geophysical operations for a portion of Chukchi Sea Planning Area covering a portion
of the Sale 193 area.
Shell submits a revised EP for the Chukchi Sea in response to lessons learned from its 2012 drilling operations of the
Sivuliq N and Burger A exploration wells.
2014

August 28 ..........

Shell submits a revised EP for the Chukchi Sea, replacing its November 2013 submission.
2015

January 21 .........
January 27 .........
February 24 .......
May 11 ..............
July 22 ...............
July 31 ...............
September 21 ....
October 16 .........

President Obama signed E.O. 13689, which calls for multiple agencies that may have jurisdictional responsibilities in
the Arctic to enhance their coordination efforts to protect the nation’s various interests in the region.
President Obama issues Presidential Memorandum withdrawing certain areas of the OCS within the Beaufort and
Chukchi Seas from leasing. These areas included the Hannah Shoal in the Chukchi Sea and lease deferral areas identified in BOEM’s 2012–2017 National OCS Oil and Gas Leasing Program.
BSEE and BOEM published the 2015 Proposed Arctic Exploratory Drilling Rule, providing a 90-day period for the public to review and comment on the proposed rule.
BOEM conditionally approves Shell’s revised EP for the Chukchi Sea.
BSEE authorizes Shell to initiate certain limited preparatory exploration drilling activities; drilling of the top hole for
Burger J exploration well in the Chukchi Sea.
Shell begins drilling operations for its Burger J exploration well in the Chukchi Sea.
Shell completes its Burger J exploration operations, and ultimately plugs and abandons the well.
The Department cancels all Beaufort and Chukchi lease sales that were scheduled to take place as part of BOEM’s 2012–
2017 National OCS Oil and Gas Leasing Program.
2016

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December 30 .....

President Obama issues a Presidential Memorandum that expands the withdrawal to all areas of the Chukchi Sea planning area and much of the Beaufort Sea planning area that were not currently withdrawn at that time. The withdrawal
excludes Beaufort tracts located nearshore in an area that included existing leases at the time.

A key factor that contributed to the
length of time taken to authorize Shell’s
exploration drilling activities was a
lawsuit filed by the Native Village of
Point Hope challenging the
Department’s decision to hold Sale 193.
See Native Village of Point Hope v.
Salazar, 730 F. Supp.2d 1009 (D. Ak.,
2010); see also Native Village of Point
Hope v. Jewell, 740 F.3d 489 (9th Cir.,
2014). The original Environmental
Impact Statement (EIS) for Sale 193 was
published in 2007, and the lease sale
was held, but subsequent legal
challenges and Federal court decisions
remanded the lease sale to BOEM for
further analysis. In response to the court
remand, BOEM conducted additional
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information into a Supplemental EIS
that was published in February 2015
and affirmed the sale as held. Only
thereafter were BOEM and BSEE able to
complete their formal review of Shell’s
exploration plan for the Chukchi Sea
and approve the drilling activities that
took place in the summer of 2015.
Between 2008 and 2019, oil prices
remained unstable, increasing to an alltime high of almost $96 per barrel in
2013 to $44 per barrel in 2015, which
increased to $56 per barrel in 2019.32
Domestic oil production had grown
since 2008, in part due to developments
in tight oil onshore and Gulf of Mexico
production, to about 9.4 million barrels
32 https://www.eia.gov/dnav/pet/hist/
LeafHandler.ashx?n=PET&s=F000000__3&f=M.

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per day in 2015 and 12.2 million barrels
in 2019.33 Demand for oil remained
relatively stable between 2008 and 2019,
with only a minor increase in 2019 over
2008—approximately a 4% increase.34
On September 28, 2015, Shell
announced that it would cease further
exploration activity in offshore Alaska
for the foreseeable future. Shell stated
that its decision was based on the
results of their Burger J well, which
found indications of oil and gas, but
were insufficient to warrant further
33 https://www.eia.gov/todayinenergy/
detail.php?id=4910.
34 https://www.eia.gov/dnav/pet/hist/
LeafHandler.ashx?n=PET&s=MTTUPUS2&f=A,
table titled ‘‘U.S. Product Supplied of Crude Oil
and Petroleum Products (Thousand Barrels per
Day).

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exploration in the Burger prospect. The
company also stated that its decision
was motivated by the high costs
associated with the project, and the
challenging and unpredictable Federal
regulatory environment offshore
Alaska.35 On November 17, 2015, Statoil
announced its decision to exit Alaska
and relinquish its leases acquired from
Sale 193. All leaseholders that acquired
leases in Sale 193 eventually
relinquished their leases.
Despite these setbacks, industry
interest in the Arctic OCS and other
areas of the Arctic, globally, has shown
to be consistent amidst fluctuating
commodity prices and concerns about
regulatory challenges. Since 1998,
nineteen geological and geophysical
seismic surveys were permitted and
completed for the Beaufort Sea and
Chukchi Sea Planning Areas. The data
from these surveys provide information
to both industry and the government for
use in lease sales and for design and
evaluation of activities described in EPs
and DPPs. Several different companies
participated in each of the four Beaufort
Sea Planning Area lease sales and the
one Chukchi Sea Planning Area lease
sale indicating on-going industry
interest in the area. Companies
submitted EPs, three in the Beaufort and
one in the Chukchi Sea. These plans,
and their revisions, received evaluation
and conditional approval. BOEM
approved two DPPs, both for the
Beaufort Sea. Currently, there are 19 oil
and gas leases in the Arctic OCS, all of
which are located in the Beaufort Sea
Planning Area. Exploratory drilling and
development on these leases have taken
place from gravel islands in State
waters.
Global Arctic Exploration Activities
In addition to the Arctic OCS
activities just described, global interest
and development has taken place in
other parts of the Arctic. Countries, such
as Russia, Norway, Canada, and
Greenland have been diligently
exploring their oil and gas resources in
or near the Arctic.
Greenland—Since the 1970s,
exploration activities have taken place
on the offshore waters of western
Greenland. While these exploration
activities have taken place in sub-Arctic
regions, operators do experience some
of the key challenges present in the
Arctic. It is not uncommon for icebergs
to pose dangers to drilling operations.
Operators use ice management plans to
identify, monitor, and tow away any
35 https://www.shell.com/media/news-and-mediareleases/2015/shell-updates-on-alaskaexploration.html.

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icebergs that may impact their
exploration operations. Operators also
have contingency plans that may require
disconnecting their drilling rig from the
well and moving off location to avoid
contact with icebergs.
Canada—In the Jeanne d’Arc, Orphan,
and Flemish Pass oil and gas basins on
the Grand Banks of Newfoundland,
operators have conducted exploration
drilling from MODUs in shallow and
deep waters. Like Greenland, the areas
with oil and gas potential are located in
sub-Arctic regions that experience some
seasonal sea ice and significant iceberg
incursions. In these areas, operators also
employ strong ice management and
contingency plans.
Norway—In Norway’s portion of the
Barents Sea, which is located entirely
within the Arctic, exploration activities
have taken place since 1980. Most of the
area is free of sea ice year-round, but
drilling has taken place in areas that do
experience challenging Arctic OCS
conditions. As late as 2014, exploration
drilling took place in Norway’s northern
portion of the Barents Seas in what is
known as the Hoop area. Those
exploration operations entailed the use
of winterized semisubmersible rigs and
the availability of a capping stack.
Russia—Russia’s latest drilling
operations also took place in 2014 when
ExxonMobil drilled a well in the South
Kara Sea. The operation took place in an
area of the Arctic where drilling could
not take place during the winter
months, similar to the Chukchi and
Beaufort Seas. Exploration activities
took place during the summer, when
little to no sea ice was present at the
drilling location and were completed in
mid-fall. The operation was similar to
the operations from the other countries
just described—a winterized MODU and
robust ice management and contingency
plans. However, unique to this project
was the use of a subsea isolation device
(SSID). (NPC Report 2015 at 6–17 and
6–18, and NPC Report 2019 at C–10).
The Kara Sea project is discussed in
more detail below in Section II. Sectionby-Section Discussion of Proposed
Changes, Subsection A. Key Revisions
Proposed by BSEE, under the
subheading entitled, Supplemental
Assessment to the 2015 Report on Arctic
Potential: Realizing the Promise of U.S.
Arctic Oil and Gas Resources (NPC 2019
Report).
Global Arctic Exploration Requirements
Norway, Canada, and Greenland have
similar regulatory requirements to the
United States for Arctic offshore drilling
operations performed from a MODU.
The Bratslavsky and SolstenXP study
also included a review of the regulatory

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requirements from these countries that
pertain to relief wells, SCCE, and
approval of alternative technologies.
The study did not include Russia in its
review because the country’s regulations
could not be accessed. Here is a
summary of that review:
• Relief Wells—All the Arctic
countries that were reviewed
specifically require relief wells, but
regulations among them differ. For
example, Canada simply requires a
‘‘same-season’’ relief well capacity,
whereby the operator demonstrates its
capability to drill a relief well and kill
an out-of-control well in the same
drilling season. Whereas the U.S.
requires the ability to bring in a
relief-drilling rig and complete the plug
and abandonment within 45 days,
Norway and Greenland require a
relief-drilling rig to be on site within 12
days.
• SCCE—Canada is the only country
besides the U.S. that has specific SCCE
requirements. Canada’s requirements,
however, are less prescriptive in that
they include a more general requirement
for ‘‘cap and containment methods and
same-well intervention methods,’’ as
compared to the U.S. requirement for
access to specific SCCE equipment
within a specified time period.
• Alternative Technologies—With
respect to approval of alternative
technologies in lieu of a relief rig or
SCCE, the U.S. has specific regulations
that allow for potential substitutions
and accommodations for innovative
technologies. Canada also provides for
the approval of alternative technologies
through specific approval processes.
Norway’s regulations, in general, are
largely performance-based. As such,
their regulations allow for the
consideration of different technologies
at the onset when planning a project.
B. BSEE and BOEM Statutory and
Regulatory Authority and
Responsibilities
The Outer Continental Shelf Lands
Act, 43 U.S.C. 1331 et seq., was first
enacted in 1953 and substantially
amended in 1978. In amending OCSLA,
Congress established a national policy
of making the OCS ‘‘available for
expeditious and orderly development,
subject to environmental safeguards, in
a manner which is consistent with the
maintenance of competition and other
national needs.’’ (43 U.S.C. 1332(3)).
OCSLA authorizes the Secretary of the
Interior (Secretary) to lease the OCS for
mineral development and to regulate oil
and gas exploration, development, and
production operations on the OCS.
On May 19, 2010, Secretary Ken
Salazar issued S.O. 3299, which

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restructured and divided the former
MMS’s responsibilities under OCSLA
among three new bureaus: (i) BOEM; (ii)
BSEE; and the (iii) Office of Natural
Resources Revenue (ONRR). S.O. 3299
delegated those responsibilities for oil
and gas operations to BSEE and BOEM,
both of which are charged with
administering and regulating aspects of
the Nation’s OCS oil and gas program
(see 30 CFR parts 250 and 550).
On June 18, 2010, Secretary Salazar
issued S.O. No. 3302, which announced
the name change of part of the former
MMS to the Bureau of Ocean Energy
Management, Regulation and
Enforcement (BOEMRE). This name,
BOEMRE, would remain in effect until
BOEM and BSEE were officially created
under S.O. 3299, effective October 1,
2011.
On October 1, 2010, the revenuecollection functions of the former MMS
were transferred to ONRR, reporting to
the Assistant Secretary for Policy,
Management and Budget.
S.O. 3299 assigned BOEM the
responsibility for managing the
development of the Nation’s offshore
conventional and renewable energy
resources. BOEM’s mission is to manage
the development of the OCS energy and
mineral resources in an environmentally
and economically responsible way.
BOEM’s functions include: Leasing; EP
administration; DPP administration;
permitting of geological and geophysical
activities; environmental analyses in
compliance with NEPA; environmental
studies; compliance with relevant laws
(e.g., the Endangered Species Act (ESA),
the Marine Mammal Protection Act, the
Magnuson-Stevens Fishery
Conservation and Management Act, and
the Coastal Zone Management Act 36
(CZMA)); resource evaluation; oil spill
worst case discharge (WCD)
determination; economic analysis and
fair market value bid/lease evaluations;
management of the OCS renewable
energy and marine mineral programs;
and consultation with other entities at
the local (e.g., North Slope Borough,
Native Villages), tribal (e.g., Federally
recognized tribes and Alaska Native
Claims Settlement Act Corporations),
State, and Federal levels (e.g., National
Oceanic and Atmospheric
Administration (NOAA) Fisheries, U.S.
Coast Guard (USCG)) related to
36 BOEM is not subject to the requirements of the
CZMA in Alaska as it is on the rest of the OCS,
where it is required to provide opportunities to the
coastal State to review the proposed Federal actions
for consistency with the state’s federally approved
coastal management program. More specifically, on
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activities within BOEM’s activities and
areas of responsibility.
Secretary’s Order 3299 made BSEE
responsible for safety and
environmental enforcement functions,
including, but not limited to, the
authority to permit activities, inspect,
investigate, summon witnesses and
produce evidence: Levy penalties;
cancel or suspend activities; and
oversee safety, and oil spill response
and removal preparedness. BSEE’s
mission is to promote safety, protect the
environment, and conserve resources
through vigorous regulatory oversight
and enforcement. BSEE’s functions
include evaluating permit applications
for post-lease oil and natural gas
exploration and development activities
on the OCS and conducting inspections
to ensure compliance with laws,
regulations, lease terms, and approved
plans and permits.
BOEM evaluates EPs, and BSEE,
thereafter, evaluates Applications for
Permits to Drill (APDs) and other
permits and applications, to determine
whether the operator’s proposed
activities meet OCSLA’s standards and
each Bureau’s regulations governing
OCS exploration. Based on their
respective evaluations, BSEE and BOEM
will either approve the operator’s EP
and APD, require the operator to modify
its submissions, or disapprove the EP or
APD (§ 250.410, How do I obtain
approval to drill a well?). The review
and approval of these activities is
outlined below in the following section.
1. BOEM Approval of the EP
As promulgated through the 2016
Arctic Exploratory Drilling Rule,
§ 550.204, When must I submit my IOP
for proposed Arctic exploratory drilling
operations and what must the IOP
include?, requires that a lessee submit
an IOP at least 90 days before filing an
EP with BOEM, if that EP would involve
exploration for oil and gas on the Arctic
OCS. While the IOP is not subject to
approval, the submission was intended
to facilitate the prompt sharing of
information among the relevant Federal
agencies that may be involved in
overseeing exploratory drilling
operations conducted from MODUs. The
operator may then submit an EP to
BOEM for approval. An EP must include
information such as a schedule of
anticipated exploration activities,
equipment to be used, the general
location of each well to be drilled, and
any other information deemed pertinent
by BOEM (§§ 550.211 through 550.228).
2. BSEE Approval of the APD
Approval of an EP does not, by itself,
permit the operator to proceed with

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exploratory drilling. After BOEM
approves the EP, the operator must
submit to BSEE an APD, which BSEE
must approve before an operator may
drill a well (43 U.S.C. 1340(d);
§ 250.410). Among other things, the
APD must be consistent with the
approved EP and include information
on the well location, the drilling design
and procedures, casing and cementing
programs, the diverter and blowout
preventer (BOP) systems, MODU (if one
is to be used), and any additional
information requested by the BSEE
District Manager.
C. Executive and Secretary’s Orders
On March 28, 2017, the President
issued E.O. 13783—Promoting Energy
Independence and Economic Growth
(82 FR 16093). The E.O. directed
Federal agencies to review all existing
regulations and other similar agency
actions, which potentially burden the
development or use of domestically
produced energy resources with the goal
of ‘‘avoiding regulatory burdens that
unnecessarily encumber energy
production, constrain economic growth,
and prevent job creation.’’ It made it
U.S. policy for agencies to ‘‘review
existing regulations that potentially
burden the development or use of
domestically produced energy resources
and appropriately suspend, revise, or
rescind those that unduly burden the
development of domestic energy
resources beyond the degree necessary
to protect the public interest or
otherwise comply with the law.’’
On April 28, 2017, the President
issued E.O. 13795—Implementing an
America-First Offshore Energy Strategy
(82 FR 20815), which directed the
Secretary to ‘‘take all steps necessary to
review’’ the 2016 Arctic Exploratory
Drilling Rule and, ‘‘if appropriate, [to,]
as soon as practicable and consistent
with law, publish for notice and
comment a proposed rule suspending,
revising, or rescinding this rule.’’ The
policy underlying E.O. 13795 is ‘‘to
encourage energy exploration and
production, including on the Outer
Continental Shelf, in order to maintain
the Nation’s position as a global energy
leader and foster energy security and
resilience for the benefit of the
American people, while ensuring that
any such activity is safe and
environmentally responsible.’’ These
E.O.s did not dictate outcomes; rather,
they provided direction for review in
accordance with all relevant laws.
To further implement E.O. 13795, on
May 1, 2017, the Secretary issued S.O.
3350, America-First Offshore Energy
Strategy, directing BSEE and BOEM to
review the 2016 Arctic Exploratory

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Drilling Rule ‘‘for consistency with the
policy set forth in section 2 of E.O.
13795’’ and to prepare a report
‘‘summarizing the review and providing
recommendations on whether to
suspend, revise, or rescind the rule.’’
Consistent with E.O.s 13783 and
13795, and S.O. 3350, BSEE and BOEM
reviewed the regulations promulgated
through the 2016 Arctic Exploratory
Drilling Rule and are proposing
revisions to those regulations to reduce
unnecessary burdens on industry while
maintaining safety and environmental
protection.
D. Purpose and Summary of the
Rulemaking
BSEE and BOEM promulgated the
2016 Arctic Exploratory Drilling Rule
based on experiences gained from
Shell’s 2012 and 2015 Arctic operations,
internal reviews conducted on potential
oil and gas operations on the Arctic
OCS, and concerns expressed by
environmental organizations and Alaska
Natives.
Since publication of the 2016 Arctic
Exploratory Drilling Rule, however,
BSEE and BOEM have become aware of
additional information informing and
warranting the bureaus’ reconsideration
of certain regulatory provisions
promulgated through that rule. BSEE
commissioned a Technology
Assessment Program study (Bratslavsky
and SolstenXP, 2018) that entailed a
historical statistical analysis of recent
Alaska Arctic OCS drilling seasons (5year period between 2012 and 2016), in
which meteorology and physical
oceanographic (‘‘metocean’’) and
operational conditions would support
the safe deployment of SCCE, the
drilling of a relief well, or both. The
study included a comprehensive review
and gap analysis of U.S. and
international regulations, standards,
recommended practices, specifications,
technical reports, and common industry
methods regarding the safe deployment
of SCCE, as compared to the
effectiveness of drilling a relief well in
Arctic conditions.
The Bratslavsky and SolstenXP study
determined that metocean conditions
prevalent in the Chukchi Sea and
Beaufort Sea (i.e., rough sea states and
sea ice conditions, primarily) are key
factors that limit the ability to safely
deploy SCCE throughout the Arctic
OCS. The study determined that, when
operating in the presence of sea ice in
the Chukchi Sea and the Beaufort Sea,
there is a greater probability for safe
relief well deployment versus SCCE
deployment. When operating in open
water conditions (i.e., those prone to
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there is also a greater probability for safe
deployment of a relief rig versus SCCE.
In the Beaufort Sea, the probability for
safely deploying relief wells and SCCE
is the same. This is because the Beaufort
Sea has fewer ice-free days than the
Chukchi and ice helps maintain calm
sea state conditions.
The study also determined that water
depth in the Arctic OCS is also a factor
limiting the safe deployment of SCCE.
According to the Bratslavsky and
SolstenXP study, safe deployment of
SCCE is likely to be impaired in water
depths shallower than 984 feet because
the equipment would potentially
encounter a gas boil at the surface
caused by a subsea blowing well
(Bratslavsky and SolstenXP at 143).
Water depths in the majority of the
Chukchi Sea and Beaufort Sea where
exploration has historically occurred are
relatively shallow—167 feet or less (id.
at 7 to 9). This water depth range limits
the fleet of support vessels that could be
used for the safe deployment of SCCE.
The NPC also published its NPC 2019
Report as a supplemental assessment to
the NPC 2015 Report. The NPC prepared
the NPC 2019 Report in response to an
April 2018 request from the Secretary of
Energy. The Secretary of Energy
requested that the NPC provide
recommendations for enhancing the
Nation’s regulatory environment by
improving reliability, safety, efficiency,
and environmental stewardship of oil
and gas activities on the OCS. That
report specifically addressed the
regulatory burdens associated with U.S.
Arctic OCS development.
Key findings from the NPC’s
supplemental assessment that helped
inform the preparation of this proposed
rule include the NPC’s determination
that the requirement to drill an SSRW
to mitigate the risk of a late season well
control event continuing over the winter
season is ‘‘outdated.’’ The report
concluded that SSIDs and capping
stacks are superior solutions that could
stop the flow of oil and allow
intervention through the original
borehole before a relief well could be
completed (NPC 2109 Report at 19).
Details in the report regarding Russia’s
2014 drilling operation that included
the use of an SSID in the South Kara Sea
also informs this proposed rule.
In this proposed rule, the Bureaus
also address other issues in addition to
those addressed in the 2016 Arctic
Exploratory Drilling Rule, including
seasonal weather-related constraints in
the Arctic that severely impact an
operator’s ability to safely perform
leaseholding operations for a significant
portion of the term on a lease. While
these issues are in addition to the issues

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addressed by the 2016 Arctic
Exploratory Drilling Rule, they are
unique to the Arctic OCS and, therefore,
are appropriate to address as part of this
proposed rulemaking.
BSEE and BOEM recognize that the
2016 Arctic Exploratory Drilling Rule
addressed specific operational and
environmental conditions that are
unique to the Arctic OCS. While this
proposed rule would leave most of the
regulations promulgated by the 2016
rule unaltered, certain of these
regulations are worth reconsidering to
accommodate technological innovation
and encourage energy exploration on
the Arctic OCS. Based on the new
scientific information gathered from the
Bratslavsky and SolstenXP study, and
global practical experience gained in
recent years, as described in the NPC
Reports, the bureaus believe that these
proposed revisions reduce unnecessary
regulatory burdens on stakeholders and
increase the ability to review and apply
advancing technological innovations,
while ensuring safety and
environmental protection.
The following paragraphs briefly
summarize the key elements of this
proposed rule, which are more fully
explained in Section II. Section-bySection Discussion of Proposed Changes
of this preamble:
1. Seasonal Conditions SOO—The
unique seasonal conditions in the Arctic
make it difficult or physically
impossible for operators to explore their
leases for a significant portion of each
year. To facilitate the proper
development of Arctic leases in
accordance with OCSLA sec. 5,37 BSEE
proposes to add a new provision to its
regulations that would provide those
operators that are conducting drilling
operations, but are prevented from
completing those leaseholding
operations due to seasonal constraints
unique to the Arctic, with the
opportunity to obtain an SOO. If
granted, this type of SOO would
suspend the running of the lease term
and effectively extend the term of the
affected lease by a period equivalent to
the period of such suspension. This
would provide operators that are
otherwise ready and able to conduct
drilling operations with additional time
to diligently explore their leases,
without facing lease expiration due to
37 OCSLA sec. 5 (as amended) provides in
pertinent part: ‘‘The regulations prescribed by the
Secretary . . . shall include . . . provisions . . . for
the suspension . . . of any operation or activity
. . . at the request of a lessee, in the national
interest, [or] to facilitate proper development of a
lease . . . and for the extension of any permit or
lease affected by [such] suspension . . . by a period
equivalent to the period of such suspension . . . .’’
43 U.S.C. 1334(a)(1).

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interference by seasonal constraints
unique to the Arctic.
2. Water-Based Mud and Cuttings—
BSEE proposes to eliminate references
to the Regional Supervisor’s
discretionary authority to require the
capture of water-based muds and
cuttings in those cases where
subsistence values might be impacted
by such discharges. While not intended,
BSEE understands that this reference
created some uncertainty for the
regulated industry, because it appeared
to overlap with regulation by the
Environmental Protection Agency (EPA)
and, if implemented, might result in
BSEE issuing requirements that
contradict EPA’s requirements.
3. SCCE—BSEE would preserve the
requirement for the operator to have
access to its SCCE when drilling below
or working below the surface casing.
However, with respect to the capping
stack, the Bureau proposes to provide an
opportunity to the operator to adjust the
point in time during operations when it
must position its capping stack so that
it is available to arrive at the well
location within 24 hours after a loss of
well control. The existing regulations
also impose a positioning requirement
on the cap and flow system, and
containment dome—slightly different
from the capping stack—‘‘positioned to
ensure that it will arrive at the well
location within 7 days after a loss of
well control.’’ BSEE’s proposed changes
to the positioning requirement for the
cap and flow system and containment
dome are discussed in more detail later
in this paragraph. If the operator is able
to demonstrate to BSEE, based on
documentation it submits as part of its
APD, that the operations it plans to
conduct below the surface casing would
not encounter any abnormally highpressured zones or other geological
hazards before reaching the last casing
point prior to penetrating a zone capable
of flowing hydrocarbons in measurable
quantities, then BSEE will allow the
operator to delay its positioning of the
capping stack until reaching that casing
point. BSEE’s proposal to delay the
positioning of the capping stack would
be based on the documentation that the
operator provides as well as any other
available data and information. As
previously mentioned, BSEE also
proposes to eliminate the requirement
for the operator to ensure that the
containment dome and cap and flow
system are positioned so as to arrive at
the well location within seven days after
a loss of well control. The Bratslavsky
and SolstenXP study evaluated current
industry methods and standards for
deploying SCCE in Arctic OCS
conditions, and determined that

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meteorological conditions (e.g., rough
sea state and sea ice conditions)
prevalent in the Chukchi Sea and
Beaufort Sea are the key factors limiting
the time periods when SCCE may be
safely deployed throughout the Arctic
OCS. This is discussed in further detail
below in Section II. Section-by-Section
Discussion of Proposed Changes, under
the subheading What are the
requirements for Arctic OCS source
control and containment? (§ 250.471). It
is not practical for BSEE’s regulations to
prescribe that certain SCCE
(containment dome and cap and flow
system, in particular) be positioned
within proximity to a well location
when the conditions for safely
deploying this equipment in the Arctic
OCS are limiting. However, BSEE would
retain other existing containment dome
and cap and flow system requirements
in § 250.471, which provide that the
operator must:
(i) Demonstrate that it has access to a
containment dome and cap and flow
system;
(ii) Provide a containment dome and
cap and flow system that meets BSEE’s
operating standards;
(iii) Conduct tests or exercises for all
SCCE; and
(iv) Maintain records pertaining to the
testing, inspection, maintenance, and
use of the SCCE and make these
available to BSEE upon request. The
changes BSEE proposes to the SCCE
requirements in § 250.471 would
preserve the regulations’ requirement
that operators have redundant
protective measures that are appropriate
for Arctic OCS conditions because there
is no guarantee that a single measure
could control or contain a WCD.
4. Same Season Relief Well (SSRW)
Requirement and Subsea Isolation
Devices (SSID)—BSEE proposes to
revise the relief rig and SSRW
requirements by providing the operator
with the option of using an SSID or
having access to a relief rig as an
additional means to secure the well in
the event of a loss of well control, if the
operator will be conducting exploratory
drilling operations from a MODU. In
addition, BSEE proposes to provide an
opportunity to the operator to adjust the
point in time during operations when it
must stage its relief rig (if the operator
elects to have access to a relief rig) when
conducting Arctic OCS exploratory
drilling operations—from when drilling
below or working below the ‘‘surface
casing’’ to when drilling below or
working below the ‘‘last casing point
prior to penetrating a zone capable of
flowing hydrocarbons in measurable
quantities.’’ If the operator is able to
demonstrate to BSEE, based on

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documentation it submits as part of its
APD, that the operations it plans to
conduct below the surface casing would
not encounter any abnormally highpressured zones or other geological
hazards before reaching the last casing
point prior to penetrating a zone capable
of flowing hydrocarbons in measurable
quantities, then BSEE will allow the
operator to delay its staging of the relief
rig until reaching that casing point.
BSEE’s proposal to permit the delay of
the staging of the relief rig will be based
on the documentation that operator
provides, as well as any other available
data and information. In the relief rig
and SSRW regulation, BSEE would also
eliminate the reference to expected
seasonal ice encroachment because the
relevant timeframes for operations
should be based on the capabilities of
the operator’s rig and equipment to
operate in the applicable ice conditions,
rather than an absolute date.
5. Mudline Cellars—BSEE proposes to
clarify the requirement for the operator,
in areas of ice scour, to use a mudline
cellar when drilling that is designed to
minimize the risk of damage to the well
head and wellbore. The existing
regulation could be read to require the
operator to use a mudline cellar in all
cases, except when the operator can
prove that the mudline cellar would
present an operational risk, and that was
not BSEE’s intent. This proposed change
would make it clear that the operator
has more flexibility to propose to
employ alternate procedures or
equipment instead of the mudline cellar
under appropriate circumstances, as
provided by the longstanding provisions
of § 250.141, May I ever use alternate
procedures or equipment?; not just
when a mudline cellar would present an
operational risk and if the operator is
able to demonstrate that the alternate
procedure or equipment would provide
a level of safety and environmental
protection that equals or surpasses the
mudline cellar requirement.
6. IOP—BOEM proposes to eliminate
the requirement that the operator submit
an IOP because it requires submission of
information that overlaps with that
required in the EP and the IOP’s early
information sharing is unnecessary in
light of BOEM’s practice for reviewing
and coordinating review of the EP.
Consequently, the operator is already
aware that it must plan for how it will
reduce operational risks and address the
challenges associated with operations
on the Arctic OCS through its EP.

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E. Partner Engagement in Preparation
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1. Summary of Partner Interaction
In advance of publishing this
proposed rule, BSEE and BOEM reached
out to Alaska Native tribal leaders,
ANCSA corporations, and native village
leaders in Northern Alaska for
Government-to-Government
consultations and municipal meetings.
These Bureaus arranged consultations
and meetings to receive input from
these groups on potential regulatory
changes that could encourage energy
exploration and production and reduce
unnecessary regulatory burdens, while
maintaining safety and environmental
protection. Between November 29, 2018
and January 30, 2019, BSEE and BOEM
officials met with 23 tribal, ANCSA
corporation, and municipal leaders at
villages throughout Northern Alaska
(Kotzebue, Point Hope, Utqiagvik [i.e.,
Barrow], Nuiqsut, and Kaktovik), in
Fairbanks, and in Anchorage. In
addition, BSEE and BOEM held a
consultation meeting via a conference
call with tribal representatives from the
Native Village of Point Lay. The
following list identifies the entities with
which BSEE and BOEM met:
• Tribal Governments—Native
Village of Utqiagvik, Native Village of
Wainwright, Native Village of Kotzebue,
Native Village of Point Hope, Native
Village of Nuiqsut, Native Village of
Kaktovik, Tanana Chiefs Conference,
and Native Village of Point Lay;
• Native Corporations—Olgoonik
Native Corporation, Doyon Limited,
Arctic Slope Regional Corporation,
Tikigaq Native Corporation, Cully
Corporation, Kuukpik Corporation, and
Kaktovik Inupiat Corporation;
• Municipal Governments—
Northwest Arctic Borough, Point Hope,
North Slope Borough, City of Utqiagvik,
Nuiqsut, and Kaktovik; and,
• Other Tribal Organizations—ICAS
and the AEWC.
BSEE and BOEM shared information
with the tribal representatives
describing potential options for
regulatory change that the Bureaus were
considering at the time the meetings
took place. BSEE and BOEM made
multiple attempts to contact two
corporations—Kikiktagruk Corporation
and NANA Regional Corporation but
did not receive a response from them.
2. Summary of Comments Received
BSEE and BOEM heard a variety of
perspectives during these meetings with
Alaska Natives. The most common
comment received was a concern over
food security. Subsistence resources,
including bowhead and beluga whales,

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other marine mammals, fish, and birds,
are a key food source for many peoples’
diets in the native villages. The Alaska
Natives’ primary concerns pertained to
protecting their food sources. BSEE and
BOEM are fully aware that subsistence
resources play a key role in offsetting
the high costs of conventional food
supplies and that subsistence hunting
and fishing play a key role in the
cultural identity of Alaska Natives.
BOEM’s leases all contain provisions
related to the protection of these
subsistence uses and BOEM’s
regulations at §§ 550.227(b)(7) and
550.261(b)(7) require lessees to explain
how they propose to protect these
subsistence uses. In addition, BSEE and
BOEM are not proposing any regulatory
changes that would adversely affect
protection of subsistence uses.
Certain tribal representatives, and
most ANCSA corporations, were
supportive of this rulemaking, and
explained that it could help attract more
economic opportunities to their villages.
In some cases, tribes or corporations
advocated for the use of their villages to
support safer oil and gas operations,
because the villages have deeper ports
that could support larger vessels, or
because they may be located closer to
potential drilling operations than those
ports or facilities that have been used in
the past. This could allow for quicker
response to emergency incidents.
BSEE did not include any regulatory
changes in this proposed rule
specifically designed to respond to this
comment. While requiring the staging of
equipment at strategically located
coastal depots could have a positive
impact on oil spill responses in the
Arctic, the identification and placement
of depots for such resources falls to the
discretion of the operator (within the
parameters established by existing
regulation). To provide each plan holder
with the flexibility needed to respond to
their WCD scenarios, BSEE’s Oil Spill
Response Plan (OSRP) regulations do
not mandate the use of any particular
staging location(s) for equipment and
personnel. BSEE will review the
operator’s staging arrangements
submitted as part of the proposed OSRP
to ensure that the OSRP would fully
comply with the planning requirements
in the governing regulations.
Other comments provided during the
consultation meetings included a
recommendation for BSEE and BOEM to
provide broader outreach by presenting
this proposed rule to their tribal
assembly and to citizens within the
communities.
DOI strives to strengthen its
government-to-government relationship
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a commitment to consultation with
tribes and recognition of their right to
self-governance and tribal sovereignty.
E.O. 13175, Consultation and
Coordination with Indian Tribal
Governments and DOI’s tribal
consultation policy, which implements
the E.O., provide for procedures for
consultation with tribes when taking an
action with tribal implications. DOI has
extended its consultation policy to
ANCSA corporations. Furthermore,
BSEE and BOEM recently issued their
own expanded tribal consultation
guidance on August 20, 2019 and June
29, 2018, respectively. BSEE’s guidance
(Bureau of Safety and Environmental
Enforcement (BSEE) Tribal Consultation
Guidance, August 20, 2019, available at
https://www.bsee.gov/bsee-tribalguidance-2019) and BOEM’s guidance
(BOEM Tribal Consultation Guidance,
June 29, 2018, available at https://
www.boem.gov/Tribal-Engagement/),
identify various consultation authorities
that BSEE and BOEM will follow in
consulting with tribes and ANCSA
corporations.
DOI recognizes and respects the
distinct, unique, and individual cultural
traditions and values of Alaska Native
people and the statutory relationship
between ANCSA Corporations and the
Federal Government. BSEE and BOEM
will endeavor to go above and beyond
their consultation responsibilities where
and when appropriate throughout the
rulemaking process to maintain a strong
working relationship with their tribal
and ANCSA corporation partners.
BSEE and BOEM also received a
comment from one of the ANCSA
corporations recommending that this
rulemaking take into account the NPC
2019 Report. BSEE and BOEM
considered the NPC reports when
preparing this proposed rule and based
some of the proposed regulatory
revisions on that report’s
recommendations, as discussed more
fully below.
Another common comment that BSEE
and BOEM received was a
recommendation to include a
requirement for a CAA between the oil
and gas operator and those whaling
communities potentially affected by an
operator’s proposed drilling project. A
CAA is typically established through a
collaborative process whereby both
parties work to create mitigation
strategies that would avoid adverse
impacts to bowhead whales and other
marine mammals, their habitat, and
hunting opportunities. Historically,
operators have voluntarily used the
CAA process and, currently, existing
lessees are required to do so through

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lease stipulations.38 See discussion in
Section I.E.3, History and Background
on the Conflict Avoidance Agreement,
of this preamble describing the history
and background of the CAA. In
addition, under the MMPA, the taking
of marine mammals without a permit or
exception is prohibited in order to
prevent the decline of species and
populations. To avoid liability for take,
operators must obtain an Incidental
Take Authorization or Incidental
Harassment Authorization for activities
related to offshore exploration,
development and production.
Implementation of the MMPA is shared
between NMFS and USFWS.
Section 7(a)(2) of the ESA requires
every Federal agency to ensure that any
action they authorize, fund, or carry out
is not likely to jeopardize the continued
existence of a listed species or result in
the adverse modification of designated
critical habitat. When any exploration or
development plan, or G&G permit
application, is submitted to BOEM,
BOEM evaluates the proposal, and
consults with NMFS and USFWS on
species listed under the ESA. During
this process, mitigation measures (e.g.,
vessel speed restrictions, rig lighting
specifications, and protected species
observer requirements) are developed to
reduce impacts to protected species.
These measures are then included in
BOEM’s conditions of approval for the
EP, DPP, or G&G permit.
BOEM did not include any regulatory
changes in this proposed rule
specifically designed to respond to this
comment. BOEM cannot require
whaling communities to establish
agreements with operators, since BOEM
has no jurisdiction over such
38 Every BOEM Arctic lease contains a variant of
the following stipulation: ‘‘Prior to submitting an
exploration plan or development and production
plan (including associated oil-spill contingency
plans) to MMS for activities proposed during the
bowhead whale migration period, the lessee shall
consult with the directly affected subsistence
communities, Barrow, Kaktovik, or Nuiqsut, the
North Slope Borough (NSB), and the AEWC to
discuss potential conflicts with the siting, timing,
and methods of proposed operations and safeguards
or mitigating measures which could be
implemented by the operator to prevent
unreasonable conflicts. Through this consultation,
the lessee shall make every reasonable effort,
including such mechanisms as a conflict avoidance
agreement, to assure that exploration, development,
and production activities are compatible with
whaling and other subsistence hunting activities
and will not result in unreasonable interference
with subsistence harvests.
A discussion of resolutions reached during this
consultation process and plans for continued
consultation shall be included in the exploration
plan or the development and production plan. In
particular, the lessee shall show in the plan how its
activities, in combination with other activities in
the area, will be scheduled and located to prevent
unreasonable conflicts with subsistence activities.’’

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communities. Such a requirement for
lessees and operators to execute an
agreement could give a third-party
power to set conditions for, or veto, OCS
activities over which they otherwise
have no authority.
For those reasons, BOEM has
concluded that a regulation would not
result in any additional protections of
subsistence whaling beyond those
provided by its longstanding practice of
addressing the issue in a lease
stipulation. BOEM has included as a
lease stipulation for all Arctic OCS lease
sales since 1991 that the lessee must
make every reasonable effort, including
such mechanisms as a CAA, to assure
that exploration, development, and
production activities are compatible
with whaling and other subsistence
hunting activities and will not result in
unreasonable interference with
subsistence harvests. Implementation of
the stipulation must be described in an
EP under § 550.222. In addition, either
BOEM or BSEE may require additional
mitigation measures at the EP or the
APD stages, as necessary, to
appropriately address potential
interference with subsistence activities.
For example, because subsistence
hunters are concerned that the effects of
offshore oil and gas exploration might
displace migrating bowhead whales and
other marine mammals (like beluga
whales), the Bureaus will meet with the
AEWC and its whaling captains to help
document traditional knowledge
pertaining to bowhead whales,
including movement and behavior.
Given the importance of subsistence
activities and related socio-cultural
activities to the Alaska Native
communities, BOEM has long
encouraged operators to work directly
with interested parties to help mitigate
potential impacts to subsistence
activities. In addition, BOEM funds and
supports studies to better understand
the potential impacts from OCS
operations on marine mammals and
subsistence activities. Over the last 46
years, the environmental studies
program has provided more than $1.2
billion nationally for scientific research
on the OCS. Nearly $500 million of that
amount has funded studies in Alaska to
produce more than 1,000 technical
reports and innumerable peer reviewed
publications. BOEM uses information
from the studies program to evaluate the
potential environmental effects of
leasing OCS lands for exploration and
development. Since July 2016, BOEM
has completed 35 environmental studies
and has 23 ongoing studies that cover
the Arctic, totaling nearly $72 million.
While environmental conditions change
and continue to change (e.g., walrus

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habitat, bowhead whale migration, and
ice coverage), BOEM’s environmental
studies program both adds to our
understanding and tracks these changes
to have the best science available for the
public, industry, and federal permitting
decisions. While BOEM has observed
changes through these studies, these
changes follow the trajectory that BOEM
has been studying and documenting for
several decades. While this proposed
rule would change how operators could
explore for OCS resources in the Arctic,
there are ample opportunities to permit
these activities consistent with ESA,
MMPA, NEPA, and consultation with
Alaska Native communities.
3. History and Background on the
Conflict Avoidance Agreement
In 1977, the IWC expressed concern
over the low bowhead whale
population. Its report specifically
mentioned that the future expansion of
offshore oil and gas extraction in the
Arctic posed a potential risk to the
bowhead whale population. At that
time, Inuit subsistence hunters knew
that bowhead whales were sensitive to
anthropogenic noise, movements, and
even smells. There were concerns that
increased activity would affect their
hunt. Traditional hunters had noticed
that boat traffic, seismic exploration,
and drilling were causing migrating
whales to deflect away from the shore
and beyond the hunters’ reach.
Beginning in 1986, offshore
stakeholders, such as representatives
from whaling villages, the AEWC, and
oil and gas companies, have all met to
identify sources of potential conflict,
and have relied on local traditional
knowledge as well as other information.
CAAs were developed first in the 1980s
to address these sources of potential
conflict and have been referenced in
lease stipulations since 1991.
Since 1991, all leases in the Arctic
issued by BOEM or its predecessors
have included a stipulation requiring
the operator to coordinate their
activities with potentially affected
Alaska native communities. While the
text of these stipulations has varied
from time to time, all of them have
included certain important components.
The following is an extract from such a
stipulation, incorporated into the leases
issued from the Oil and Gas Lease Sale
Number 202, issued on April 18, 2007:
Prior to submitting an exploration plan or
development and production plan (including
associated oil-spill contingency plans) to
MMS for activities proposed during the
bowhead whale migration period, the lessee
shall consult with the directly affected
subsistence communities, Barrow, Kaktovik,
or Nuiqsut, the North Slope Borough (NSB),

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and the Alaska Eskimo Whaling Commission
(AEWC) to discuss potential conflicts with
the siting, timing, and methods of proposed
operations and safeguards or mitigating
measures which could be implemented by
the operator to prevent unreasonable
conflicts. Through this consultation, the
lessee shall make every reasonable effort,
including such mechanisms as a conflict
avoidance agreement, to assure that
exploration, development, and production
activities are compatible with whaling and
other subsistence hunting activities and will
not result in unreasonable interference with
subsistence harvests.

Because this stipulation was provided
for in the lease sale notice and included
in the lease agreements resulting from
the lease sale, its requirements became
binding for all leases issued as a result
of that particular lease sale.
The intent of this stipulation is for the
operator to make a reasonable effort to
establish a CAA with potentially
affected whaling or subsistence hunting
communities. It is the operator’s
responsibility to attempt to reach
agreement on a CAA with those
communities.
II. Section-by-Section Discussion of
Proposed Changes
This section provides explanations of
and justifications for each of the specific
regulatory changes proposed in this
document. Since this is a joint BSEE
and BOEM proposed rulemaking, this
Section-by-Section discussion is
organized according to the order in
which the relevant provisions would
appear in the CFR. BSEE’s and BOEM’s
regulations are found in the CFR at Title
30—Mineral Resources, Volume 2;
BSEE’s regulations are in Chapter II, and
BOEM’s regulations are in Chapter V.
A. Key Revisions Proposed by BSEE
Title 30, Chapter II, Subchapter B, Part
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Subpart A—General
Definitions. (§ 250.105)
BSEE proposes to revise the definition
of Capping Stack by deleting the phrase
‘‘including one that is pre-positioned’’
from the definition. BSEE included this
phrase as part of the 2016 Arctic
Exploratory Drilling Rule in response to
a suggestion that the definition in the
2015 Arctic Proposed Rule should be
expanded to allow pre-positioned
capping stacks to be used below subsea
BOPs when deemed technically and
operationally appropriate. Recognizing
that the comment was helpful, BSEE
agreed with the suggestion and added
the phrase ‘‘including one that is prepositioned’’ to the capping stack
definition (see 81 FR 46492). As a
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stacks are similar to SSIDs. Accordingly,
this modification in the 2016 final rule
effectively allows the operator to install
an SSID below a subsea BOP and would
be in compliance with the capping stack
requirement in the existing § 250.471,
What are the requirements for Arctic
OCS source control and containment?
Existing § 250.471(a)(1), specifically
requires the operator, when drilling
below or working below the surface
casing, to have access to a capping stack
that is positioned to ensure that it will
be able to arrive at the well location
within 24 hours after a loss of well
control. Typically, an operator would
comply with this requirement by having
one or more support vessels capable of
handling and deploying the capping
stack down to the subsea wellhead,
when needed. Installing an SSID below
the subsea BOP allows the operator to
comply with § 250.471(a)(1) and forgo
the need to provide support vessels and
a capping stack on standby at the
surface.
However, BSEE is proposing to
eliminate this language because a prepositioned capping stack is a piece of
equipment that, as previously
mentioned, aligns closely with an SSID.
The Bureau is currently proposing
distinct SSID requirements under
§ 250.472, What are the additional well
control equipment or relief rig
requirements for the Arctic OCS? This
proposed revision would provide clarity
concerning the capping stack
requirements under § 250.471,
specifically that installation of an SSID
under § 250.472 does not constitute
compliance with the capping stack
requirements under § 250.471. For
purposes of BSEE’s proposed
regulations, an SSID is not considered to
be the same as, or to satisfy the
requirement to have, a capping stack.
The new SSID option that BSEE is
proposing under § 250.472 does not, and
is not intended to, replace any of the
SCCE requirements in proposed
§ 250.471(a), where BSEE’s capping
stack requirement is addressed.
When may the Regional Supervisor
grant an SOO? (§ 250.175)
BSEE proposes to revise § 250.175 by
adding a new paragraph (d), which
would allow an operator to request an
SOO under certain situations that may
be present in the Arctic OCS. This
proposed revision is consistent with
OCSLA’s requirement that the Secretary
promulgate suspensions regulations that
‘‘facilitate proper development of a lease
. . . .’’ 39 The proposed regulation
39 OCSLA sec. 5, as amended, codified at 43
U.S.C. 1334(a)(1).

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would list the factors upon which BSEE
may rely when determining whether to
grant an SOO and include when an
operator:
(1) Has conducted operations on the
lease during the drilling season
immediately preceding the period for
which the operator is seeking a
suspension;
(2) is drilling from: A MODU, an
artificial gravel island or a gravity-based
structure, or an artificial ice island; and
(3) is not able to safely continue its
operations due to the presence of
seasonal ice, temporary seasonal drilling
restrictions in its approved oil spill
response plan, or seasonal temperature
changes (respectively, for each facility
type).
Currently, BOEM issues Alaska OCS
leases with the maximum 10-year
primary lease term allowed under
OCSLA.40 However, operators may be
precluded from properly developing
leases because it is not possible to
conduct leaseholding operations for
significant portions of those 10-year
terms. Offshore drilling locations on the
Arctic OCS are inaccessible for a
significant portion of each year, due to
seasonal changes that make operating
conditions unsafe or otherwise preclude
operations. Moreover, it is difficult to
predict precisely when sea ice will
persist or break-up.
MODUs—For example, drilling
operations performed from a MODU
may occur only during the open-water
drilling season (generally late June to
early November), when sea ice is nonexistent or minimal. This practical
limitation, without considering other
logistical problems unique to the Arctic
OCS, could mean that during a
consecutive 10-year period, a lease may
be unavailable for operations for
approximately 70 percent of the time.
Artificial Gravel Islands or Gravitybased Structures—Drilling from
artificial gravel islands and gravitybased structures is prohibited during the
spring/summer ice break-up and the
fall/early winter freeze-up periods,
because of the potential impact of
weather and ice conditions on potential
oil spill response and cleanup efforts. In
particular, response and cleanup
techniques for a large spill are not as
effective when sea ice is broken and
unconsolidated around the drilling
location. By contrast, response and
40 OCSLA sec. 8, as amended, states in part: ‘‘An
oil and gas lease issued pursuant [OCSLA] shall be
for an initial period of (A) five years; or (B) not to
exceed ten years where the Secretary finds that
such longer period is necessary to encourage
exploration and development in areas because of
unusually deep water or other unusually adverse
conditions . . . .’’ 43 U.S.C. 1337(b).

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cleanup efforts for a large oil spill from
an artificial gravel island or a gravitybased structure could be executed
effectively during the summer (i.e., in
open-water conditions) using existing
oil spill response technologies. During
the winter (i.e., under solid ice
conditions), the ice, and any snow on
the ice, could provide an effective
platform for oil spill response and
cleanup efforts, and help absorb the
spill and contain it to an area relatively
close to the gravel island or gravitybased structure. Land-based equipment
could then be used to collect and
transport the oil-covered ice out of the
location. For context, a gravity-based
structure would include a concrete
island drilling structure and a steel
drilling caisson(s).
Artificial Ice Islands—A similar issue
would be encountered if drilling were to
take place from a man-made ice island.
In those cases, the drilling location
would be accessible only during the
winter season when temperatures are
very low, and the area is completely
covered by ice stable enough to safely
support a drilling rig and associated
equipment. As temperatures rise during
the spring and summer seasons, the ice
breaks or melts away, making the
drilling location inaccessible until the
next winter season.
The new paragraph (d) of § 250.175
would facilitate the proper development
of a lease by addressing those seasonal
conditions that limit leaseholding
operations by providing an operator
ready and able to complete its
operations with the opportunity to
obtain an SOO. If granted, this SOO
would suspend the running of the lease
term and effectively extend the term of
the affected lease by a period equivalent
to the period of such suspension. The
SOO would allow a diligent operator to
use the full 10 years in a 10-year lease
term to explore for hydrocarbons,
without the concern for a lease expiring
because Arctic seasonal constraints
prevented operations.
BSEE would continue to require the
operator to comply with the existing
requirements for requesting a
suspension under existing § 250.171,
How do I request a suspension? For
example, § 250.171 requires the operator
to submit a reasonable schedule of work
for resuming the suspended operations
on the subject lease for which the
operator requests the suspension. A
schedule of work typically includes
milestones describing what activities
the operator will perform to resume
operations and when those operations
will be performed. If the operator
submits a schedule of work that
demonstrates a reasonable plan and

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schedule for resuming operations, BSEE
will typically grant the SOO (assuming
the other requirements are satisfied).
BSEE will use the reasonable schedule
of work as an established measuring
stick by which the Bureau would assess
the operator’s diligence and progress
toward prudent development. If the
operator does not adhere to its approved
work schedule, BSEE may terminate the
SOO under existing regulations.
Paragraph (e) of existing § 250.170, How
long does a suspension last? authorizes
BSEE to terminate any suspension when
the Regional Supervisor determines the
circumstances that justified the
suspension no longer exist. Because a
reasonable schedule of work serves as a
required foundation for BSEE’s SOO
approval, the operator’s adherence to
that schedule is necessary to maintain
the SOO. This allows BSEE to ensure
that the operator complies with the
OCSLA Congressional declaration of
purpose. Other regulations under
Subpart A that would also apply to
BSEE’s implementation of proposed
paragraph (d) of § 250.175 includes
§ 250.170, How long does a suspension
last? which allows BSEE to issue a
suspension for up to five years and
provides that the suspension
automatically ends when the suspended
operation commences.
BSEE understands the requirement in
OCSLA to supervise operations in a
manner that assures due diligence in the
exploration and development of each
lease. Therefore, BSEE is contemplating
the option of limiting the period for
when the suspension would remain in
effect; only during the period between
one drilling season and the next when
the operator is prevented from
continuing its drilling or other
leaseholding activities due to seasonal
conditions. This option would still
provide operators more time to
effectively explore their leases without
fear of an expiring lease. It could also
provide BSEE with a better means of
tracking an operator’s diligence efforts.
This option, however, could result in
additional unnecessary burdens, since
an operator would have to ‘‘reapply’’ for
a new suspension if the operator is
unable to return to the location during
the next open-water season. BSEE is
seeking comment on this regulatory
option for the SOO or any other option
that could avoid or minimize additional
burden, but still assure diligent lease
exploration and development.
BSEE’s proposed regulatory change
would address concerns raised in the
NPC reports, which suggested that the
current approach toward administration
of the 10-year primary lease term
allowed under OCSLA ‘‘comes from

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other offshore areas in the U.S., where
operators have access to the leases all
year-round.’’ (NPC 2015 Report at 31
and NPC 2019 Report at 25). The NPC
2019 Report pointed out that a ‘‘10-year
lease in the U.S. Arctic equates to about
3 to 4 years of working time, compared
with the equivalent 10 years working
time in the Gulf of Mexico.’’ (NPC 2019
Report at 25). While it is not possible for
BOEM to award leases with more than
the maximum ten-year primary lease
term allowed under OCSLA, this
proposed regulatory change would rely
on the Secretary’s statutorily delegated
authority, which has, in turn, been
delegated to BSEE, to administer
suspensions to address, as appropriate,
the effects of Arctic working conditions
when they may limit the operator’s
ability to perform leaseholding
activities.
Documents Incorporated by Reference.
(§ 250.198)
BSEE proposes to revise the existing
relief rig and SSRW requirements in
§ 250.472 by providing the operator
with an option to either use an SSID or
have access to a relief rig if the operator
will conduct exploratory drilling
operations from a MODU. As part of that
proposed regulatory change, which is
discussed in detail later below in the
What are the relief rig or additional well
control equipment or relief rig
requirements for the Arctic OCS?
(§ 250.472) section-by-section
discussion, BSEE proposes to require
the SSID to include Remotely Operated
Vehicle (ROV) intervention equipment
that has the capabilities to function the
SSID. Under proposed
§ 250.472(a)(3)(ii), BSEE would require
the ROV to have panels that are
compliant with API RP 17H, Remotely
Operated Tools and Interfaces on
Subsea Production Systems, Second
Edition, June 2013; Errata, January 2014,
to ensure that the operator’s ROV
capabilities for the SSID follow BSEE’s
existing ROV panel requirements for
BOP systems. In conjunction with
proposed paragraph (a)(3)(ii) that would
require the operator’s ROV panels to be
compliant with API RP 17H, BSEE
proposes to add the citation for
proposed § 250.472(a)(3) to
§ 250.198(e)(73). Paragraph (e)(73) of
§ 250.198 documents the locations in
the regulations where API RP 17H is
incorporated by reference as a
regulatory requirement, which would
include § 250.472(a)(3) under this
proposed rule. Adding the citation for
§ 250.472(a)(3) to § 250.198(e)(73) would
clarify that API RP 17H is a regulatory
requirement when complying with
§ 250.472 and is subject to BSEE

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oversight and enforcement in the same
manner as other regulatory
requirements.
API Recommended Practice 17H—
Remotely Operated Tools and Interfaces
on Subsea Production Systems
This recommended practice provides
general recommendations and overall
guidance for the design and operation of
remotely operated tools (ROT) and
remotely operated vehicle (ROV) tooling
used on offshore subsea systems. ROT
and ROV performance is critical to
ensuring safe and reliable subsea
operations and this document provides
general performance guidelines for this
and associated equipment. This second
edition also includes provisions on high
flow Type D hot stabs.
The American Petroleum Institute
(API) provides free online public access
to view read only copies of its key
industry standards, including a broad
range of technical standards. All API
standards that are safety-related and that
are incorporated into Federal
regulations are available to the public
for free viewing online in the
Incorporation by Reference Reading
Room on API’s website at: http://
publications.api.org [1]. In addition to
the free online availability of these
standards for viewing on API’s website,
hardcopies and printable versions are
available for purchase from API. The
API website address to purchase
standards is: https://www.api.org/
products-and-services/standards/
purchase.
[1] To view these standards online, go
to the API publications website at:
http://publications.api.org. You must
then log-in or create a new account,
accept API’s ‘‘Terms and Conditions,’’
click on the ‘‘Browse Documents’’
button, and then select the applicable
category (e.g., ‘‘Exploration and
Production’’) for the standard(s) you
wish to review.
For the convenience of the viewing
public who may not wish to purchase or
view the incorporated documents
online, the documents may be inspected
at BSEE’s offices at: 3801 Centerpoint
Dr, Anchorage, Alaska, 99503 (phone:
907–334–5300); 1919 Smith Street,
Suite 14042, Houston, Texas 77002
(phone: 1–844–259–4779); or 45600
Woodland Road, Sterling, Virginia
20166 (email: [email protected]), by
appointment only. BSEE will make
documents incorporated in the rule
available for viewing at the time and
date agreed upon for the appointment.
Additional information on where these
documents can be inspected or
purchased can be found at 30 CFR
250.198, Documents incorporated by

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reference, or by sending a request by
email to [email protected].
Subpart C—Pollution Prevention and
Control
Pollution prevention. (§ 250.300)
BSEE proposes to revise paragraphs
(b)(1) and (2) of § 250.300 by eliminating
the existing language that states the
Regional Supervisor may require the
capture of all water-based mud, and
associated cuttings, from operations
after completion of the hole for the
conductor casing to prevent its
discharge into the marine environment.
While this proposed rule would
eliminate the language regarding the
Regional Supervisor’s discretionary
authority to require the capture of
water-based muds and cuttings, it
would maintain the existing
requirement in § 250.300(b)(1) and (2)
that operators capture all petroleumbased mud and associated cuttings
while operating on the Arctic OCS.
Existing § 250.300(b)(1) and (2) state
that the BSEE Regional Supervisor may
exercise his or her discretionary
authority to restrict discharges of waterbased muds and associated cuttings
from Arctic OCS exploratory drilling
based on various factors, such as:
Proximity of drilling operations to
subsistence hunting and fishing
locations; the extent to which
discharged water-based mud or cuttings
may cause marine mammals to alter
their migratory patterns in a manner
that impedes subsistence users’ access
to or use of those resources, or increases
the risk of injury to subsistence users; or
the extent to which discharged mud or
cuttings may adversely affect marine
mammals, fish, or their habitat. BSEE
promulgated the existing provisions in
response to concerns raised by Alaska
Native Tribes during preparation of the
2015 Arctic Proposed Rule. These
concerns included how water-based
muds or cuttings could adversely affect
marine species (e.g., whales and fish)
and their habitats and compromise the
effectiveness of subsistence hunting
activities.
BSEE re-examined the language in
paragraphs (b)(1) and (2) of this section
in light of EPA’s authority to address
water-based muds and cuttings
discharges. The Clean Water Act (CWA)
(Section 301(a), 33 U.S.C. 1311(a))
provides EPA with the authority to issue
National Pollutant Discharge
Elimination System (NPDES) general
permits, which authorize certain
discharges, including certain restricted
discharges of water-based muds and
cuttings, from oil and gas exploratory
facilities on the OCS in the Beaufort Sea

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and the Chukchi Sea. Those general
permits additionally prohibit the
discharge of oil-based and non-aqueous
based muds and cuttings. The EPA must
issue an NPDES general permit before
an operator may seek coverage under
that general permit. Compliance with
the CWA, including gaining coverage
under an applicable NPDES general
permit, is necessary before an operator
may discharge pollutants from its
exploratory drilling operations.
Before issuing an NPDES permit, EPA
must make specific determinations to
ensure that issuance of a permit will not
lead to unreasonable degradation of the
marine environment. EPA’s
determination is guided by an Ocean
Discharge Criteria Evaluation (ODCE).
The ODCE requires the agency to
consider multiple environmental
factors, such as potential impacts on
human health through direct and
indirect pathways, and the importance
of the receiving water area to the
surrounding biological community.
These factors take into consideration
how discharges could impact
subsistence activities, marine resources,
and coastal areas. The most relevant
NPDES permits issued for offshore oil
and gas exploration activities conducted
from a MODU on the Arctic OCS are
two 2012 general permits that covered
oil and gas exploration facilities
conducting operations in Federal waters
of the Beaufort Sea and the Chukchi
Sea. The Beaufort Sea permit 41 does not
allow the discharge of water-based
muds and cuttings during the fall
bowhead whale hunt. However, the
Chukchi Sea permit 42 did not include a
similar restriction. According to the
ODCE for the Chukchi Sea permit, the
restriction was not necessary because
the migration of bowhead whales would
be over before discharge-related
activities would begin.43
Under this proposed rule, BSEE
would preserve the requirements in
§ 250.300(b)(1) and (2) that the operator
capture all petroleum-based mud and
associated cuttings. This requirement is
consistent with a longstanding, OCSwide regulatory authority that existed
prior to the promulgation of the 2016
Arctic Exploratory Drilling Rule. BSEE
must preserve the petroleum-based
muds and cuttings requirement since it
is not unusual for petroleum-based
41 https://www.epa.gov/sites/production/files/
2017-12/documents/r10-npdes-beaufort-oil-gas-gpakg282100-final-permit-2012.pdf.
42 https://www.epa.gov/sites/production/files/
2017-12/documents/r10-npdes-chukchi-oil-gas-gpakg288100-final-permit-2012.pdf.
43 https://www.epa.gov/sites/production/files/
2017-12/documents/r10-npdes-chukchi-oil-gas-gpakg288100-odce-2012.pdf, pp. 6–14 to 6–17.

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muds to contain constituents that are
toxic and harmful to the environment.
Although water-based muds may not be
a feasible option for all drilling
operations, such as when drilling
through hydrophobic geologic
formations that could be damaged by
water-based muds, its use is a more
environmentally benign approach in
comparison to the use of petroleumbased muds. However, BSEE’s proposed
revisions reflect the Bureau’s
understanding that the express
statements regarding the Regional
Supervisor’s discretionary authority to
require the capture of water-based muds
and cuttings in existing § 250.300(b)(1)
and (2) are not necessary. In particular,
the EPA already addresses the goals of
protecting water quality through the
NPDES program, protecting marine
species and their habitats, as well as the
effectiveness of subsistence hunting
activities, through the exercise of that
agency’s authorities. Thus, BSEE does
not expect the Regional Supervisor to
need to exercise the discretionary
authority under existing § 250.300(b)(1)
and (2) in the foreseeable future.
Furthermore, BSEE understands, and
did so even while it was preparing the
2016 Arctic Exploratory Drilling rule,
that the references to the BSEE Regional
Supervisor’s authority in existing
paragraphs (b)(1) and (2) created some
uncertainty for the regulated industry
because it appeared to overlap with
EPA’s jurisdiction and, if implemented,
might result in BSEE issuing duplicative
or conflicting requirements. BSEE
addressed this concern by explaining
that the amendments were meant to
clarify the Regional Supervisor’s
authority to impose operational
measures that complement EPA’s
discharge limitations by considering
potential impacts to specific
components of the Arctic environment,
such as subsistence activities, marine
resources, and coastal areas (81 FR
46505). Given the policy in E.O. 13783
to review existing regulations that
potentially burden the development or
use of domestically produced energy
resources and the general principles in
Section 1 of E.O. 13563—Improving
Regulation and Regulatory Review (76
FR 3821)—to promote predictability and
reduce uncertainty, BSEE believes it is
appropriate to propose eliminating the
water-based mud, and associated
cuttings, provisions in § 250.300(b)(1)
and (2).
This proposed regulatory change does
not suggest any change in BSEE’s
recognition that it is responsible for
ensuring that oil and gas exploration
and production activities on the OCS
are conducted in a safe and

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environmentally responsible manner
pursuant to OCSLA. Therefore, the
proposed rule would not alter the
longstanding regulation at
§ 250.300(b)(1), under which the District
Manager (or Regional Supervisor)
retains the ability to restrict the rate of
drilling fluid discharges or prescribe
alternative discharge methods where
warranted. Pursuant to § 250.300(b)(1),
BSEE would be able to determine
whether there is a need to require
capture of water-based muds and
cuttings on a case-by-case basis, if the
EPA has not done so. In particular, the
District Manager would consider and
determine whether such a requirement
would be appropriate for any facility.
The District Manager would make this
determination on a case-by-case basis,
in conjunction with the EP and APD
approval process. This process includes
coordinating with BOEM, particularly at
the EP stage, when BOEM conducts an
environmental review to identify the
direct, indirect, and cumulative
environmental effects that may be
expected as a result of implementing the
EP. That environmental review also
incorporates input about potential
environmental effects that may be
obtained through consultations and
review by interested parties, Federal
agencies (e.g., EPA), State or local
agencies, Tribes, or the public. Nothing
would change BSEE’s position from the
2016 rule to communicate with other
agencies responsible for oversight of
discharges related to oil and gas
exploration drilling in the Arctic. This
communication will help ensure that
conflicts do not arise (81 FR 46504).
BSEE expects that such input from EPA
would address whether that agency has
issued or plans to issue a permit for the
same exploratory drilling facilities, and
whether that agency believes that
capture of water-based muds in a
specific case is warranted. Through
BSEE’s longstanding authority under
§ 250.300(b)(1), the District Manager
could require an operator to restrict the
rate of drilling fluid discharges or
prescribe alternative discharge methods.
Such a restriction on the discharge of
water-based muds and cuttings might be
appropriate if identified in the EP
environmental review process.
In addition to the proposed revisions
just described, BSEE proposes a minor
modification to the second sentence in
existing paragraph (b)(2), which requires
the operator to capture all cuttings from
operations that ‘‘utilize’’ petroleumbased mud to prevent their discharge
into the marine environment. BSEE
proposes to replace the word ‘‘utilize’’

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with ‘‘use’’ to improve the readability of
the regulation.
Subpart D—Oil and Gas Drilling
Operations
What additional information must I
submit with my APD for Arctic OCS
exploratory drilling operations?
(§ 250.470)
BSEE proposes to revise paragraph (b)
of § 250.470 by adding paragraph (b)(13)
to include ‘‘Recover the subsea isolation
device (SSID), where applicable.’’ This
revision is necessary to address the
SSID alternative proposed in § 250.472,
and to ensure the operator’s permit
addresses how it would recover the
SSID, if one is used. For operations
relying on an SSID, the SSID is a critical
piece of equipment. Therefore, BSEE
must understand how the operators will
handle it, prior to and after drilling
operations. We also propose minor, nonsubstantive edits to paragraphs (b)(11)
and (12) to accommodate this addition.
In cases where an operator obtains
SCCE capabilities through contracting,
paragraph (f)(3) currently requires the
operator to provide proof of contracts or
membership agreements with
cooperatives, service providers, or other
contractors. This includes information
demonstrating the availability of the
personnel and/or equipment on a 24hour per day basis during operations
below the surface casing. BSEE proposes
to revise paragraph (f)(3) by replacing
the ‘‘below the surface casing’’ language
in this paragraph with the phrase
‘‘below the surface casing, or before the
last casing point prior to penetrating a
zone capable of flowing hydrocarbons in
measurable quantities, as approved by
the Regional Supervisor.’’ This change
would make the requirement in
paragraph (f)(3) consistent with the
changes BSEE is proposing to § 250.471,
which houses the substance of the
Arctic OCS SCCE requirements. This
proposed change is discussed in further
detail in connection with that provision.
Finally, BSEE proposes to add a new
paragraph (h) to complement the
proposed revisions to § 250.472, which
would provide the operator with the
option to use an SSID or have access to
a relief rig, as an additional means to
secure the well in the event of a loss of
well control, if the operator will be
conducting exploratory drilling
operations from a MODU (that change is
discussed in further detail in connection
with that provision). Under proposed
paragraph (h), if the operator elects to
use an SSID, BSEE would require the
operator to provide a certification,
signed by a registered professional
engineer, confirming that its SSID and

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well design (including casing and
cementing program) meet the design
requirements in proposed § 250.472(a),
and the design is appropriate for the
purpose for which it is intended under
expected wellbore conditions. BSEE is
proposing this new provision to be
consistent with existing requirements
under existing § 250.420 (a)(7)(i), which
require the operator to include with the
APD a certification signed by a
registered professional engineer that the
casing and cementing design is
appropriate for the purpose for which it
is intended under expected wellbore
conditions.

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What are the requirements for Arctic
OCS source control and containment?
(§ 250.471)
Section 250.471(a) currently requires
the operator to have access to the SCCE
described in paragraphs (a)(1) through
(3), which must be capable of stopping
or capturing the flow of an out-ofcontrol well if the operator will be using
a MODU when drilling below or
working below the surface casing.
Paragraph (a)(1) specifically requires the
capping stack to be positioned to ensure
that it will be able to arrive at the well
location within 24 hours after a loss of
well control. Paragraphs (a)(2) and (3)
require the cap and flow system and the
containment dome to be positioned to
ensure that they will be able to arrive at
the well location within 7 days after a
loss of well control.
BSEE proposes to revise § 250.471 by:
(i) Adding a new provision at the end
of paragraph (a) stating that ‘‘However,
the Regional Supervisor will approve
delaying access to your SCCE until your
operations have reached the last casing
point prior to penetrating a zone capable
of flowing hydrocarbons in measurable
quantities provided that you submit
adequate documentation (such as, but
not limited to, risk modeling data, offset well data, analog data, seismic data),
with your APD, demonstrating that you
will not encounter any abnormally highpressured zones or other geologic
hazards. The Regional Supervisor will
base the determination on any
documentation you provide as well as
any other available data and
information.’’
(ii) modifying the language in
paragraph (a) describing the
performance standard that the SCCE
must meet by replacing ‘‘capable of
stopping or capturing the flow of an outof-control well’’ with ‘‘capable of
controlling or containing the flow from
an out-of-control well when drilling
below or working below the surface
casing;’’ and

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(iii) removing the phrase ‘‘positioned
to ensure that it will arrive at the well
location within 7 days after a loss of
well control’’ from subparagraphs (a)(2)
and (3), which apply to the cap and flow
system and containment dome,
respectively.
The changes described in item (i)
from the previous paragraph could
allow the operator to adjust the point in
time during operations when it must
position its capping stack—from ‘‘when
drilling or working below the surface
casing’’ to ‘‘when drilling or working
below the last casing point prior to the
zone capable of flowing hydrocarbons in
measurable quantities’’—if the operator
is able to demonstrate that it will not
encounter any abnormally highpressured zones or other geological
hazards before that casing point.
However, unless otherwise approved by
BSEE, the operator must have access to
their SCCE as described in paragraph
(a)(1) and proposed paragraphs (a)(2)
and (3), when drilling or working below
the surface casing. While BSEE does not
propose changes to the capping stack
provision in paragraph (a)(1), changes to
paragraph (a) would have a practical
effect on the existing capping stack
requirements. Changes to the capping
stack requirements are discussed in the
next subsection, entitled, Revisions to
the Capping Stack Requirements.
BSEE’s proposed modifications to the
language in paragraph (a), describing the
performance standard that the operator’s
SCCE must meet, is administrative in
nature. BSEE proposes this change so
that the language is consistent with the
source ‘‘control’’ and ‘‘containment’’
description of this equipment, as well as
the title of this section of the regulations
(i.e., § 250.471 What are the
requirements for Arctic OCS source
control and containment?). It would not
change the performance standard that
the operator’s SCCE must meet.
BSEE’s proposed changes to remove
the phrase ‘‘positioned to ensure that it
will arrive at the well location within 7
days after a loss of well control’’ from
paragraphs (a)(2) and (3) would still
require the operator to ensure it has
access to a cap and flow system or a
containment dome. However, the
operator would no longer be required to
ensure the equipment is positioned to
be able to arrive at the well location
within 7 days after the loss of well
control. The distinction between the
positioning requirement and the
requirement to have access to the
equipment is that ‘‘having access’’ refers
to ensuring the operator has identified
the equipment that would meet the
performance requirements in this
section and in other existing BSEE

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regulations—§ 250.462 (What are the
source control, containment, and
collocated equipment requirements?)
and is able to deploy the equipment as
directed by the Regional Supervisor.
Details regarding BSEE’s proposed
revisions to § 250.471(a)(2) and (3) are
discussed in the subsection below,
entitled, Revisions to the Cap and Flow
System, and Containment Dome
Requirements.
• Revisions to the Capping Stack
Requirements
BSEE’s proposed revisions to
paragraph (a) would provide an
opportunity to the operator to adjust the
point in time during operations when it
must position its capping stack, so that
it will be available to arrive at the well
location within 24 hours after a loss of
well control. If the operator is able to
demonstrate to BSEE that the operations
it plans to conduct below the surface
casing would not encounter any
abnormally high-pressured zones or
other geologic hazards before reaching
the last casing point prior to penetrating
a zone capable of flowing hydrocarbons
in measurable quantities, then BSEE
would allow the operator delay its
positioning of the capping stack until
that point. A capping stack, as defined
under the existing regulations at
§ 250.105, is a mechanical device that
can be installed on top of a subsea or
surface well head or BOP to stop the
uncontrolled flow of fluids into the
environment. BSEE also proposes
certain non-substantive language
changes for clarity.
The existing capping stack
requirements in paragraphs (a) and
(a)(1) are intended to ensure that a
capping stack is readily available to stop
or capture the flow of hydrocarbons in
case of a loss of well control when
drilling below or working below the
surface casing. While BSEE does not
propose to eliminate the requirement in
paragraph (a)(1) to ensure that the
capping stack will be able to arrive at
the well location within 24 hours after
a loss of well control, the existing
requirement in paragraph (a) to ensure
the equipment is accessible when
drilling below the surface casing does
not fully take into consideration the
known geology of an area. The
formations below the surface casing,
based on the known geology of the area,
may have minimal or no potential to
flow hydrocarbons in measurable
quantities during drilling operations.
This obviates the need for ensuring
capping stack availability during
operations in those zones. Prior to
submitting an APD, operators assess the
formations they will potentially
encounter during drilling operations,

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including the potential for hydrocarbon
flow. Operators base this assessment on
existing G&G data that they include in
the APD.
In many cases, flowable hydrocarbons
are not anticipated or encountered in
measurable quantities until the target
productive formation is reached. For
example, a surface casing shoe setting
depth for an Arctic OCS exploration
well could be only 1,500 feet, but the
hydrocarbon bearing formation may be
thousands of feet below that point. The
existing regulations require the operator
to have access to an available capping
stack when drilling or working below
the surface casing, even though geologic
and engineering risk analyses the
operator must submit as part of their
APD may show that there is little or no
potential for hydrocarbons to escape the
formation and flow into the well prior
to reaching the targeted productive
formation. In such circumstances, the
operator could safely drill for thousands
of feet below the surface casing, without
any identifiable need for a capping
stack. This proposed change would,
when appropriate, eliminate an
unnecessary burden for the operator to
maintain a positioned capping stack
while drilling into low risk, nonproductive sections of the well below
the surface casing.
An extensive amount of geophysical
data already exists for certain areas of
both the Beaufort and Chukchi Sea
Planning Areas, and there has been
extensive drilling in certain areas of the
Beaufort Sea Planning Area. In the
known geologic conditions of the U.S.
Arctic, operators have a good
understanding of the locations of
reservoirs that they will encounter,
which can be relatively shallow and
normally pressured above certain
geologic depths. Therefore, it may not
be necessary to have access to a capping
stack when drilling through zones
below the surface casing that do not
have abnormally high formation
pressures or contain other geological
hazards, and do not have the potential
to flow hydrocarbons in measurable
quantities, as they are penetrated.
However, because geologic conditions
are not uniformly normally pressured
throughout the Arctic OCS, BSEE is
maintaining the existing requirement to
have the capping stack positioned when
drilling or working below the surface
casing. At the same time, BSEE does not
discount the possibility that future
projects would not need to have SCCE
(i.e., the capping stack) positioned until
reaching the last casing point prior to
penetrating a zone capable of flowing
hydrocarbons.

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The criteria BSEE proposes to rely
on—that the operator can demonstrate
to BSEE that it will not encounter
‘‘abnormally high-pressured zones or
other geologic hazards’’—to determine
whether to grant an exception accounts
for those downhole risks that could lead
to a blowout and may require the use of
a capping stack. With respect to
abnormally high-pressured zones, BSEE
is concerned that there could be a case
where a kick (an influx, or flow, of
formation fluid from the high-pressured
zone entering into the wellbore) is not
controlled and could lead to a blowout.
While there are means of mitigating the
risk of a kick, (i.e., overbalanced
drilling), the capping stack needs to be
readily available if heavier weight
drilling muds, the BOP, and SSID, if
applicable, fail to control the well.
There could be other geologic
hazards, such as fractured or high
permeability zones, that may also pose
a risk, particularly if those zones
contain hydrocarbons. It is possible that
normally pressured zones may be highly
permeable or contain fractures, in which
lost circulation may occur. This could
cause a dynamic effect where drilling
mud flows into the permeable formation
causing the circulating pressure to
decrease below the zone’s pore pressure
resulting in formation fluids flowing
into the well bore. This may lead to a
loss of well control. The capping stack
needs to be readily available if heavier
weight drilling muds, the BOP, and
SSID, if applicable, fail to control the
well.
However, if the operator is able to
demonstrate that a highly permeable or
fractured zone is predicted to only
contain water, BSEE would consider
allowing the operator to delay
positioning of the capping stack. Under
this scenario, the operator would be able
to use the diverter system in
conjunction with the BOP system to
maintain safety and environmental
protection because it would be unlikely
for hydrocarbons to be released into the
environment. The diverter system
consists of a mechanical device similar
to a BOP annular preventer. The
diverter system is used to divert gases,
fluids, and other materials flowing from
the well, away from facilities and
personnel. Also, an operator would
pump fluid loss materials into the well
to bridge the formation to reduce its
permeability and allow drilling muds to
isolate the formation from the well. To
permanently address the incident, the
operator could also install a liner or set
a new casing point at the interval where
that highly permeable or fractured zone
is located. BSEE would like to know
whether there are more appropriate

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criteria, other than ‘‘abnormally highpressured zones or other geologic
hazards,’’ that the Bureau should use to
determine whether to allow the operator
to delay positioning of the capping
stack.
BSEE’s proposed regulatory language
describing the types of documentation it
would consider adequate to demonstrate
that abnormally high-pressured zones or
other geological hazards would not be
encountered before reaching the last
casing point prior to penetrating a zone
capable of flowing hydrocarbons in
measurable quantities—‘‘such as, but
not limited to, risk modeling data, offset well data, analog data, seismic
data’’—is not meant to be an exhaustive
list. BSEE would accept any other types
of documentation the operator may
provide that will help its demonstration.
BSEE does not anticipate this
submission requirement would lead to a
significant information collection
burden on the operator because it is
normal practice for operators to gather
these types of information to develop
and design an offshore exploration
drilling project on the OCS in the
Arctic. BSEE is requesting comment on
what other types of information could
be used to demonstrate the absence of
abnormally pressured zones or other
geologic hazards, and how burden on
the operator could change—increase or
decrease—if BSEE were to require its
submission.
At the APD stage, BSEE would
evaluate the operator’s documentation
along with other accompanying geologic
and engineering information/analyses
that must be submitted as part of its
APD. BSEE would also consider any
other available G&G information, such
as information gathered from prior
drilling operations in the area (e.g., well
log and pressure testing information),
and any other applicable geophysical
(e.g., seismic data) information. BSEE
makes clear in its proposed regulatory
language that the Regional Supervisor
will base the determination on whether
to allow the operator to delay
positioning of the capping stack on the
documentation that the operator
submits, as well as any other available
data and information.
BSEE is also considering an
alternative regulatory approach whereby
the Bureau would instead revise
existing paragraph (a) by replacing
‘‘surface casing’’ with ‘‘last casing point
prior to penetrating a zone capable of
flowing hydrocarbons in measurable
quantities.’’ This regulatory option
would uniformly adjust the point in
time during operations when the
operator must have access to its capping
stack, by requiring the operator to have

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its capping stack positioned before
drilling below or working below the last
casing point prior to penetrating a zone
capable of flowing hydrocarbons in
measurable quantities.
Under this regulatory option, BSEE
would evaluate the geologic and
engineering information/analysis that
the operator must submit as part of its
APD, while also taking into
consideration any other available G&G
information the Bureau may have (e.g.,
off-set well data, such as well logs and
pressure testing information, or
geophysical information, such as
seismic data). Based on these different
sources of information, BSEE would
determine whether there may be a need
for the operator to position the capping
stack at a point in time during
operations earlier than last casing point
prior to penetrating a zone capable of
flowing hydrocarbons in measurable
quantities.
There may be cases where the
operator or BSEE may not have
sufficient G&G or analogous well data
during the permit review process on a
proposed project to provide an adequate
level of certainty regarding anticipated
formations that may be encountered
prior to reaching the targeted productive
formation. Therefore, BSEE is also
considering, as part of this regulatory
option, a clarification that the Regional
Supervisor may require the operator to
have access to a capping stack in
advance of drilling below or working
below the last casing point prior to
penetrating a zone capable of flowing
hydrocarbons in measurable quantities
if BSEE determines there is insufficient
G&G or analogous well data.
For example, there may be
insufficient G&G or analogous well data
in cases where there have been a limited
number of wells drilled within
proximity to the planned well. In most
cases, G&G and analogous well data are
gathered from multiple sources.
However, the same sets and amounts of
data and information may not be
available for each area, well, or project.
There is no single set of criteria for
determining the sufficiency of G&G or
analogous well data. The more data that
are available from sources near to the
proposed drilling location, the greater
confidence BSEE will have in the G&G
interpretations. BSEE wants to ensure
the operator has the most accurate data
to make determinations about where the
zones capable of flowing hydrocarbons
in measurable quantities are located.
This alternative regulatory option
would maintain the same level of safety
and environmental protection in
comparison to BSEE’s proposed
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whether it is appropriate to delay
positioning of the capping stack at a
point in time when operations are
taking place below the surface casing
resides with BSEE. BSEE, ultimately,
may decide not to allow the operator to
delay positioning of the capping stack if
the Bureau reasonably assesses that
potential risks below the surface casing
exist that may require immediate
deployment of this device. However, the
distinction under this regulatory option
is that the operator would not need to
specifically demonstrate that
abnormally high-pressured zones or
other geologic hazards would be
encountered above last casing point
prior to penetrating a zone capable of
flowing hydrocarbons in measurable
quantities. The presumption would be
that all zones above the last casing point
prior to penetrating a zone capable of
flowing hydrocarbons are safe unless
BSEE determines otherwise. In addition,
under BSEE’s proposed regulatory
change, it would be clear that the
Bureau may request additional
information from the operator and
would provide that BSEE may consider
other available data and information.
BSEE is specifically soliciting
comments about the benefits or
disadvantages of this regulatory option.
BSEE is also soliciting comments about
the need for the operator to verify on a
case-by-case basis those zones incapable
of flowing hydrocarbons in measurable
quantities. Operators verify these zones
by analyzing G&G data to evaluate the
formations that are expected to be
encountered during drilling operations
and confirm that there are no
hydrocarbons present. Operators must
use available offset well data in
conjunction with the G&G data. BSEE
requests comment on other methods
operators use to verify the hydrocarbon
zones, or abnormally high-pressured
zones or other geologic hazards (such as
fractured or high permeability zones),
they anticipate encountering for a
proposed drilling project and how
frequently the data would be lacking at
the point of preparing information to
submit as part of an APD.
• Revisions to the Cap and Flow
System, and Containment Dome
Requirements
As described at the beginning of this
section-by-section discussion, § 250.471,
BSEE is also proposing to revise
paragraphs (a)(2) and (3) of existing
§ 250.471, which refers to the timing of
the arrival of a cap and flow system and
containment dome, respectively, by
removing the phrase ‘‘positioned to
ensure that it will arrive at the well
location within 7 days after a loss of
well control’’ from each paragraph. This

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proposed change would remove the
requirement to have a cap and flow
system or a containment dome
positioned to ensure the equipment will
be available to arrive at the well location
within 7 days after the loss of well
control, while preserving the existing
requirement to deploy those pieces of
equipment as directed by BSEE.
BSEE proposes to allow the operator
to adjust the point in time during
operations when it must position its
capping stack under paragraph (a), from
‘‘when drilling or working below the
surface casing’’ to ‘‘when drilling below
or working below last casing point prior
to penetrating a zone capable of flowing
hydrocarbons in measurable quantities’’
if the operator is able to demonstrate
that it will not encounter any
abnormally high-pressured zones or
other geologic hazards before that casing
point. Only the 7-day arrival timing
related to the ‘‘flow’’ part of the cap and
flow system would be altered as a result
of BSEE’s proposed modification to
paragraph (a)(2) of § 250.471.44
The changes proposed in paragraphs
(a)(2) and (3) to remove the requirement
for the cap and flow system and the
containment dome to arrive at the well
location within 7 days after a loss of
well control would not change other
existing requirements throughout
§ 250.471 for the operator to ensure:
(i) Access to a containment dome and
cap and flow system;
(ii) that the cap and flow system is
designed to capture at least the amount
of hydrocarbons equivalent to the
calculated WCD rate referenced in the
operator’s BOEM-approved EP;
(iii) that the containment dome has
the capacity to pump fluids without
relying on buoyancy;
(iv) that tests or exercises are
conducted for the SCCE, as directed by
the Regional Supervisor;
(v) that records pertaining to the
testing, inspection, maintenance, and
use of the SCCE are maintained and
made available to BSEE upon request;
(vi) that all SCCE identified in
§ 250.471 are transported to the well
upon a loss of well control; and
(vii) that SCCE is deployed as directed
by the Regional Supervisor.
BSEE proposes to remove the cap and
flow system and containment dome 7day arrival timing requirements based
on the Bratslavsky and SolstenXP study.
The Bratslavsky and SolstenXP study
determined that the time periods when
SCCE may be safely deployed
throughout the Arctic OCS is limited
based on typical Arctic conditions. In
44 Existing § 250.105 defines Cap and flow system
and Capping stack.

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the Chukchi Sea, this means that safe
SCCE deployment could only occur
between August and October in the
historically active exploration area.
Moving north from the historically
active exploration area of the Chukchi
Sea, the ability to safely deploy SCCE
diminishes significantly (id. at 100). The
study mentions there are more
opportunities for safe deployment of
SCCE in other portions of the Chukchi
Sea (June through December). However,
it is only in the southwestern extent of
the Chukchi Sea Planning Area; outside
of the historically active exploration
area.
In the Beaufort Sea, the study noted
that sea ice concentrations tend to be
greater year-round as compared to the
Chukchi Sea (id. at 75). Accordingly,
safe SCCE deployment could occur from
ice capable vessels between early
August and October in the historically
active exploration area of the Beaufort
Sea (i.e., the southern portion of the
Beaufort Sea Planning Area). However,
moving north beyond the historically
active exploration area, time windows
for safe SCCE deployment decrease
significantly (id. at 104).
In the case of open water operations
in both the Chukchi and Beaufort Seas,
the study points out that sea state is an
important limiting factor for safe SCCE
deployment. Rough sea states—high
waves and longer wave periods—can
affect the safety and operating limits of
SCCE deployment. The vessel carrying
the SCCE can become very unstable in
rough sea states and the heave action on
the deck can therefore increase
significantly beyond the vessel’s
tolerance levels for conducting
operations, which may negatively affect
the ability to safely deploy the SCCE.
Rough sea states are most likely to occur
when there is less sea ice coverage and
larger open water areas to generate large
waves, which is more of an issue in the
Chukchi Sea, where there are larger
open water areas throughout the open
water season (id. at 11).
When operating in open water
conditions, sea states generally dictate
that safe SCCE deployment could occur
only between late September and
October in the historically active
exploration area of the Chukchi Sea, and
that window diminishes significantly
moving north of the historically active
exploration area. In the Beaufort Sea,
where there is less open water
throughout the operating season, sea
states would generally permit safe
deployment of SCCE between lateAugust and early-to mid-October in the
historically active exploration area.
Beyond that, the probability for safe
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the historically active exploration area
and in the other areas of the Beaufort
Sea. (id. at 98,102)
Water depth is also an important
factor to consider for the safe
deployment of SCCE. Deployment is
likely to be impaired in water depths
shallower than 984 feet because the
equipment would potentially be subject
to a gas boil at the surface from a subsea
blowing well (id. at 143). A gas boil is
a forceful release of hazardous gases
which can present human-health
hazards to workers, fire hazards, and
potential stability problems for support
vessels and the vessel deploying the
SCCE directly above the blowing well.
Water depths in the majority of the
Chukchi Sea and Beaufort Sea where
exploration has historically occurred are
relatively shallow—167 feet or less
(Table 1–1 and Table 1–2, id. at 7 to 9).
As recently as April of 2020,45 there
were active leases in the Arctic OCS
where SCCE may be deployed. These
leases were located in the Beaufort Sea
in water depths less than approximately
170 feet deep. This water depth range
limits the fleet of support vessels that
can be used for the safe deployment of
SCCE. A possible solution that could
enable SCCE deployment in the
presence of a gas boil is the use of
offset-deployment technology to
remotely position SCCE over the
blowing well in shallow water (id. at A–
35).
When BSEE proposed its original
Arctic OCS SCCE requirements in 2015,
the Bureau explained that there is
limited ability in the Arctic region to
summon additional source control and
containment resources. Accordingly, the
Bureau required operators to plan for
response redundancies and planning
complexities not required elsewhere (80
FR 9938). BSEE determined that the
provisions finalized in 2016 provided
for the necessary redundancy and
sequencing of the responses, based on
the time necessary to deploy, and
therefore provided sufficient safety and
environmental protection to allow for
exploratory drilling on the Arctic OCS.
At that time, BSEE believed that the
technologies identified in its SCCE
requirements represented the optimal
approach to well control capabilities
available for the Arctic OCS (81 FR
46520).
45 In April of 2020, the only leases with potential
projects that would be subject to the Arctic OCS’s
SCCE requirements were relinquished. However,
there are other active leases in the Beaufort Sea
located nearer to the shore in shallow waters where
exploration and development projects are being
pursued (primarily through man-made gravel
islands).

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Since publication of the 2016 rule,
however, BSEE has sought to better
understand the ability to safely deploy
SCCE (and relief rigs) in Arctic OCS
conditions, through a study it
commissioned to Bratslavsky Consulting
Engineers, Inc., and SolstenXP, Inc.
According to the Bratslavsky and
SolstenXP study, the time periods when
SCCE may be safely deployed
throughout the Arctic OCS is limited in
comparison to relief-well drilling
operations, based on typical Arctic
conditions. BSEE did not have the
benefit of having the Bratslavsky and
SolstenXP study when finalizing the
2016 Arctic Exploratory Drilling Rule.
BSEE’s proposed changes to
§ 250.471(a)(2) and (3) for the
containment dome and cap and flow
system responds to the information it
has gathered from the study.
In light of these findings, BSEE
proposes the revisions under § 250.471
to the containment dome and cap and
flow system deployment requirements
in paragraphs (a)(2) and (3) because it is
not reasonable to impose such
universal, prescriptive requirements for
equipment that may not be safely
deployed (moved to the location,
equipment put into place, and activated)
and effectively used under certain
Arctic OCS conditions. The deployment
and arrival schedules of the cap and
flow system and the containment dome
will be directed by the BSEE Regional
Supervisor on a case-by-case basis.
However, as previously described,
BSEE proposes only to adjust, rather
than eliminate, the reference to the
point in time during operations when
the operator must have access to a
capping stack that is positioned to be
able to arrive at the well location within
24 hours after a loss of well control. The
Bratslavsky and SolstenXP study shows
that the time periods when SCCE
(capping stack, containment dome, and
cap and flow system) may safely be
deployed and effectively used are
limited. Metocean conditions (i.e.,
rough sea states and sea ice
concentrations) prevalent in the Arctic
OCS can exceed the operating limits of
the vessels that transport and deploy the
SCCE. In addition, SCCE deployment is
likely impaired in water depths
shallower that 984 feet, where gas boils
could form above a blowing well. Water
depths in the majority of the Chukchi
Sea and Beaufort Sea where exploration
has historically occurred are relatively
shallow—167 feet or less. However,
BSEE’s independent observation outside
of the study is that the chances for
successfully deploying a capping stack
under Arctic OCS conditions is greater
in comparison to the containment dome

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and cap and flow system. More
specifically, in comparison to the
containment dome, the capping stack
has proven to be a more effective
technology when successfully deployed
and has a different function compared
to a containment dome. The capping
stack latches on to a connector or pipe
stub located on or in the well to achieve
a pressure tight seal to capture or stop
all fluids flowing out of the well. A
containment dome, which removes oil
and gas from the water column, will
likely capture only a portion of the
hydrocarbon flow due to the non-sealing
design. In addition, the use of a
containment dome may be constrained
by the drilling unit itself. Certain
drilling rigs, such as jackups and
submersible drilling vessels, are
unlikely to provide adequate structural
clearance for deployment of a
containment dome without moving the
rig off the drill site. (id. at 33).
Furthermore, containment domes have
limited field application to prove their
capabilities while, in contrast, capping
stacks have been field tested and
successfully deployed in multiple
practice drills (id. at 32 and 34).46
With respect to the cap and flow
system, the flow portion of the system
would require additional vessel support
activities on the surface (e.g., support
vessels for oil and gas processing, and
hydrocarbon storage/transfer) to keep
the system working in comparison to
what would be needed to deploy a
capping stack (e.g., a single vessel that
would load the capping stack and
deploy to the well when needed). The
support activities and the vessel on
which the flow system is loaded would
be subject to the same challenging
metocean conditions previously
described, thus limiting their ability to
be safely deployed throughout the
Arctic drilling season. The capping
stack would generally have a better
opportunity for deployment because
once the capping stack is lowered under
the water and attached to the wellhead,
weather becomes less of a factor.
BSEE believes it is critical to ensure
that operators have redundant
protective measures in place, as there is
no guarantee that a single measure
could control or contain a worst-case
discharge (see 81 FR 46487). Because
the chances of successfully deploying a
capping stack under Arctic OCS
conditions may be greater in
comparison to the containment dome
and cap and flow system, BSEE is
revising, and not eliminating, the
46 For example, the capping stack technology was
used to shut-in the Macondo well during the
Deepwater Horizon incident.

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capping stack positioning requirement.
BSEE invites comments on any
technological upgrades or methods that
exist for SCCE that would meet the
objective of being a redundant system
that could control or contain a WCD.
Although BSEE is proposing to
remove the requirement in existing
paragraphs (a)(2) and (3) to ensure that
the cap and flow system and
containment dome will be available to
arrive at the well location within 7 days
after a loss of well control, BSEE would
maintain the provisions under the same
paragraphs that require that the operator
identify and have access to a
containment dome and cap and flow
system capable of deployment as
directed by BSEE. BSEE would also
maintain the requirement under existing
paragraph (g) to initiate transit of all
SCCE identified under § 250.471 upon a
loss of well control. Collectively, the
proposed revisions to paragraphs (a)(2),
(a)(3), and existing paragraph (g) would
mean that, in the event of a loss of well
control, the containment dome and cap
and flow system would be in transit
while the capping stack is being
deployed at the well location. In light of
the distinct functions and capabilities of
these various elements of SCCE under
anticipated Arctic OCS exploratory
drilling conditions, BSEE proposes to
retain these requirements, as modified,
to preserve the regulations’ requirement
for redundant protective measures,
while acknowledging the capability of
each SCCE component, as there is no
guarantee that a single measure could
control or contain a WCD.
Finally, BSEE proposes to revise
existing paragraph (b) by eliminating the
requirement for the operator to conduct
a stump test of a pre-positioned capping
stack, if the operator elects to use one,
prior to installation on each well. This
proposed change would provide
consistency with BSEE’s proposed
revision to the definition of a capping
stack in § 250.105 and the new SSID
alternative BSEE is proposing under
§ 250.472. BSEE’s proposed SSID
alternative includes specific testing
procedures, which is discussed in detail
later in this preamble. BSEE’s prior
references to ‘‘pre-positioned capping
stacks’’ were intended to address a
comment on the 2015 Arctic
Exploratory Drilling Proposed Rule
suggesting that the definition of a
capping stack be expanded to allow prepositioned capping stacks to be used
below subsea BOPs when deemed
technically and operationally
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What are the additional well control
equipment or relief rig requirements for
the Arctic OCS? (§ 250.472)
Paragraph (b) of § 250.472 currently
requires the operator to have access to
a relief rig (different from the primary
drilling rig), when drilling or working
below the surface casing. In addition,
when drilling or working below the
surface casing, paragraph (b) requires
the operator to stage the relief rig so that
it could arrive on site, drill a relief well,
kill and permanently plug the out-ofcontrol well, and abandon the relief
well prior to expected seasonal ice
encroachment at the drill site, and in no
event later than 45 days after the loss of
well control.
BSEE proposes to revise the existing
relief rig and SSRW requirements in
§ 250.472 by:
(i) Providing the operator with an
option to either use an SSID or have
access to a relief rig, if the operator will
conduct exploratory drilling operations
from a MODU;
(ii) Establishing the requirements that
the operator must satisfy if the operator
elects to use an SSID to comply with
§ 250.472;
(iii) Establishing the requirements that
the operator must satisfy if the operator
elects to have access to a relief rig to
comply with § 250.472;
(iv) Adding a new provision that
would apply if the operator elects to
have access to a relief rig, which states,
‘‘However, the Regional Supervisor will
approve delaying access to your relief
rig until your operations have reached
the last casing point prior to penetrating
a zone capable of flowing hydrocarbons
in measurable quantities provided that
you submit adequate documentation
(such as, but not limited to, risk
modeling data, off-set well data, analog
data, seismic data), with your APD,
demonstrating that you will not
encounter any abnormally highpressured zones or other geological
hazards. The Regional Supervisor will
base the determination on any
documentation you provide as well as
any other available data and
information.’’; and
(v) Eliminating the reference to
expected seasonal ice encroachment at
the drill site, which applies to relief rig
operations.
With respect to the structure of
§ 250.472, proposed paragraph (a)
would establish the requirements the
operator must follow if the operator
elects to use an SSID, and proposed
paragraph (b) would establish the
requirements the operator must follow if
the operator elects to maintain access to
a relief rig. BSEE would combine the

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requirements in existing paragraphs (a)
and (b) into a single paragraph—
proposed paragraph (b)—for
organizational purposes, since existing
paragraphs (a) and (b) cover relief rigs.
Proposed paragraph (b) would also
include the relief rig-related revision
described in item (iv) of the previous
paragraph, which could allow the
operator to adjust the point in time
during operations when it must stage its
relief rig—from ‘‘when drilling or
working below the surface casing’’ to
‘‘when drilling or working below the
last casing point prior to the zone
capable of flowing hydrocarbons in
measurable quantities’’—if the operator
is able to demonstrate that it will not
encounter any abnormally highpressured zones or other geological
hazards before that casing point.
However, unless otherwise approved by
BSEE, the operator must stage its relief
rig in a location, such that the relief rig
would be available to arrive on site, drill
a relief well, kill and abandon the
original well, and abandon the relief
well no later than 45 days after the loss
of well control, when drilling or
working below the surface casing.
Finally, proposed paragraph (b) would
include the proposed relief rig-related
revision to eliminate the reference to
expected seasonal ice encroachment at
the drill site, which could potentially
extend the open-water drilling season
for MODUs. The changes included in
proposed paragraphs (a) and (b) are
discussed in further detail below,
respectively, under the two subheadings
entitled, Proposed Paragraph (a)—
Complying with § 250.472 by Using an
SSID and Proposed Paragraph (b)—
Complying with § 250.472 by Having
Access to a Relief Rig.
In addition, the general alternative
compliance language in existing
paragraph (c) would be eliminated
because the proposed rule would
provide the operator with the
alternatives of either using an SSID or
having access to a relief rig, and because
§ 250.141, May I ever use alternate
procedures or equipment?, already
provides an option for an operator to
seek approval to use alternate
procedures or equipment, potentially
including future technologies that have
not yet been developed.
When it promulgated the 2016 Arctic
Exploratory Drilling Rule, BSEE
understood that, based on past loss of
well control events (including the
Deepwater Horizon incident), it was
important for the operator to be
prepared to drill a relief well to
permanently plug a well, in the event of
a loss of well control. Arctic OCS
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conducted from MODUs are
complicated by the fact that these
operations can take place only during a
short period each year, when ice
hazards can be physically managed and
there is no continuous ice layer over the
water. Outside of that window, ice
encroachment complicates or prevents
drilling, including drilling a relief well,
and transit operations. Therefore, BSEE
concluded in the proposed rule: Oil and
Gas and Sulphur Operations on the
OCS—Requirements for Exploratory
Drilling on the Arctic OCS (February 24,
2015, 80 FR 9916) that, for Arctic OCS
Conditions, it was necessary to establish
a relief rig and SSRW requirements,
whereby the rig would be positioned at
a location that would enable it to transit
to the well site, drill a relief well, kill
and permanently plug the out-of-control
well, plug the relief well, and
demobilize from the site, prior to
expected seasonal ice encroachment.
(see 80 FR 9940).
Prior to finalizing the 2016 Arctic
Exploratory Drilling Rule, BSEE did not
identify any alternative technologies
that provided a comparable level of
results to drilling a relief well and
permanently killing an out-of-control
well. Drilling a relief well prior to
seasonal ice encroachment eliminates
the risk of a prolonged uncontrolled
flow of hydrocarbons under the ice,
throughout the winter season. The SCCE
intervention options in BSEE’s existing
regulations (capping stack, cap and flow
system, and containment dome) are
intended only to temporarily control a
well and not to be left in place over an
entire ice season. However, BSEE did
provide an option through the 2016 rule
for the operator to request that BSEE
approve ‘‘alternative compliance
measures to the relief rig requirement,’’
as provided in the longstanding
regulation at § 250.141, May I ever use
alternate procedures or equipment?
Since the promulgation of the 2016
Arctic Exploratory Drilling Rule, BSEE
has received and considered new
information regarding the current relief
rig and SSRW requirements in
§ 250.472. BSEE used the following
information when developing the
proposed requirements of this section:
• Supplemental Assessment to the
2015 Report on Arctic Potential:
Realizing the Promise of U.S. Arctic Oil
and Gas Resources (NPC 2019 Report)
In April 2018, the Secretary of Energy,
in cooperation with DOI, requested that
the NPC develop a supplemental
assessment to the NPC 2015 Report. In
April 2019, the NPC issued a report
entitled, ‘‘Supplemental Assessment to
the 2015 Report on Arctic Potential:
Realizing the Promise of U.S. Arctic Oil

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and Gas Resources.’’ The supplemental
assessment evaluated recent experiences
with Arctic exploration and
advancements in technology, and it
provided findings and
recommendations directed toward
enhancing the Nation’s regulatory
environment to improve reliability,
safety, efficiency, and environmental
stewardship for Arctic oil and gas
development. One of the key areas the
Secretary of Energy requested that the
NPC address was regulatory burdens
related to development on the Arctic
OCS. (NPC 2019 Report at A–1)
The NPC 2015 Report described
various technologies employed by
industry as preventative measures, to
reduce the risk of a well control
incident or to mitigate the impacts of an
incident through response and recovery
measures. It recommended further
examination of source control and
containment technologies, including
capping stacks and SSIDs, noting that
such alternatives ‘‘. . . could prevent or
significantly reduce the amount of
spilled oil compared to a relief well,
which could take a month or more to be
effective.’’ (NPC 2015 Report at 4–16).
In July/August of 2007, BSEE’s
predecessor, MMS, published a paper
entitled, ‘‘Absence of fatalities in
blowouts encouraging in MMS study of
OCS incidents 1992–2006.’’ You may
download and view the paper at http://
drillingcontractor.org/dcpi/dcjulyaug07/DC_July07_
MMSBlowouts.pdf. The paper
summarizes BSEE’s assessment of
statistical information about loss of well
control events that occurred during
drilling operations on the OCS from
1992 through 2006. The paper noted
that although relief wells were initiated
in 2 of the 39 blowouts that occurred
during the study period, both wells
were controlled by other means prior to
completion of the relief well. According
to the NPC 2015 report, ‘‘[a] relief well
under good weather conditions may
take 30 to 90 days plus rig mobilization,
whereas a capping stack could be
installed significantly sooner, and a
subsea shut-in device could be activated
in minutes.’’ (NPC 2015 Report at 8–17)
The NPC 2019 Report noted that,
when ExxonMobil drilled an
exploratory well in the Russian waters
of the Kara Sea, it used an SSID that was
built and tested in Norway. According
to the NPC 2019 Report, the SSID used
in the Kara Sea used existing capping
stack technology, including dual blind
shear rams; an upgraded, redundant
control system; and side inlets for
intervention below the shear rams. (id.
at C–10). At the same time, the NPC
2019 Report described the SSID as

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similar to a second BOP that was
designed to be left on the wellhead,
instead of being removed with the
drilling rig, if the rig moves off the well
near the end of the drilling season. The
SSID, which could be actuated
remotely, and the casing design together
were capable of safe full well shut-in,
diminishing the risk related to a loss of
well control event occurring in late
season and continuing over the winter
season. The NPC 2019 Report observed
that this design approach could
eliminate the need for an SSRW. (id. at
C–28). Ultimately, the NPC
recommended that the use of an SSID,
in conjunction with capping stacks, be
accepted in place of the existing
requirement for SSRW capability. (id. at
2).
The NPC 2019 Report also included
additional data regarding the geologic
characteristics of the formations targeted
during exploratory drilling operations in
the Chukchi Sea and Beaufort Sea. The
NPC 2019 Report provides an
illustrative comparison of the geologic
depths encountered in the Arctic OCS
and the Gulf of Mexico OCS. (NPC 2019
Report at 11). The shallower targeted
geologic formations in the Arctic OCS
make drilling less complex and lower
risk. This is different from current water
depths encountered by operators in the
Gulf of Mexico. In the Arctic OCS,
exploratory drilling operations
conducted from MODUs have taken
place in waters less than 200 feet. In the
Gulf Mexico, drilling activities are
continually taking place in waters
deeper than 9,000 feet.
The Arctic OCS’s distinct challenges
are driven by the region’s extreme
environmental conditions, geographic
remoteness, and a relative lack of fixed
infrastructure and existing operations.
In comparison to the Gulf of Mexico, the
Arctic OCS lacks extensive operations
and infrastructure from which resources
could be drawn to respond to a well
control incident. In addition, the open
water season for drilling from a MODU
is limited, allowing operators to perform
drilling operations only during the
summer and early fall. A late-season
well-control event could challenge an
operator’s ability to perform well
intervention operations prior to freeze
up.
• Suitability of Source Control and
Containment Equipment versus SSRW
in the Alaska Outer Continental Shelf
Region (Bratslavsky and SolstenXP,
2018)
In addition to the NPC 2019 Report,
BSEE received information about SSIDs
through the Bratslavsky and SolstenXP
study, discussed in the previous section
in connection with the proposed

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changes to the current Arctic OCS
source control and containment
requirements in § 250.471. As
previously mentioned, the Bratslavsky
and SolstenXP study entailed a
comprehensive review and gap analysis
of U.S. and international regulations,
standards, recommended practices (RP),
specifications, technical reports, and
common industry methods regarding
the safe deployment of SCCE as
compared to the effectiveness of drilling
an SSRW in Arctic conditions. BSEE
notes that the Bratslavsky and
SolstenXP study refers to the SSID as a
‘‘subsea intervention device’’ and
considers the device to be SCCE, which
is used to mitigate the consequences of
a well control event. However,
consistent with the findings in the NPC
2019 Report that categorizes SSIDs as
preventative measures (instead of a
response and recovery measure), BSEE
considers SSIDs to be a barrier intended
to prevent or minimize the impacts of a
well control event. (id. at 16).
The Bratslavsky and SolstenXP study
noted that an SSID was installed and
field tested on a submersible drilling
vessel (i.e., a steel drilling caisson) for
a 2005/2006 drilling project in the
Canadian Beaufort Sea. However, the
system was not completed in time to
meet the approval process timelines and
shipping deadlines required for timely
implementation of the unit. (Bratslavsky
& SolstenXP at A–36). According to the
study, the use of a preinstalled SSID
could provide a faster and safer
additional line of defense for a response
to a blowout than an SSRW or
deployment of a capping stack or
containment dome, resulting in smaller
discharges to the environment. The
report also mentions that the ability to
remotely function the SSID ensures that
it can be used in instances where other
types of SCCE cannot be deployed due
to site hazards that make it unsafe or
inaccessible. These instances may
include: A blowout with pressurized
fluids coming up solely through the
wellbore (forming a gas boil on the
surface), a rig catching fire or collapsing
on top of the well, or an incident in an
area where response operations are
limited, such as in shallow waters (id.
at 35). The report also stated that if the
well is designed to accommodate a full
shut-in of the last casing string interval,
the SSID can temporarily cap and
control a well and facilitate its plugging
and abandonment. This finding is
consistent with the information from the
NPC 2019 Report discussed previously.
In 2008, Chevron initiated a technology
venture with its partners on an R&D
project to develop an SSID that would

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advance the best BOP technologies
available at the time and would meet or
exceed Canada’s SSRW Arctic offshore
regulations. The SSID was known as the
Alternative Well Kill System (AWKS),
which had two shear rams that were
capable of simultaneously shearing and
sealing heavier wall, larger diameter
tubulars, and casings than was possible
at that time. According to the NPC 2015
Report, Chevron successfully completed
its testing of the AWKS in 2014 and is
ready for deployment. (NPC 2015 Report
at 4–18).
Although the Bratslavsky and
SolstenXP study points out that SSIDs
could provide a faster and safer
response to a blowout than capping
stacks or containment domes, BSEE
does not conclude from this observation
that SSIDs should also replace the SCCE
requirements in existing and proposed
§ 250.471. In the Arctic, it is critical for
the operator to have redundant
protective measures in place, as there is
no guarantee that a single measure
could control or contain a WCD. (see 81
FR 46487). In addition to these
redundant protective measures, the
SSID, well design, and BOPs serve as
controls and barriers that prevent or
minimize the likelihood of loss of well
control.
Other pertinent information from the
Bratslavsky and SolstenXP study
includes the statistical analysis of recent
OCS drilling seasons in the Beaufort and
Chukchi Seas. The analysis identified
the metocean and operational
conditions that would support the safe
drilling of a relief well. The study noted
that the hazards of sea ice to drilling
vessels and associated support vessels
are primarily determined by the
concentration and thickness of the sea
ice. A vessel’s ice classification, which
are determined by various marine
classification societies, such as the
American Bureau of Shipping (ABS)
and Det Norske Veritas and
Germanischer Lloyd (DNV GL),
indicates the vessel’s capabilities. As ice
concentrations increase, a vessel’s
efficiency decreases. (Bratslavsky &
SolstenXP at 23).
The study notes that the currently
available open water operating season in
the Chukchi Sea ranges from
approximately 60 to 90 days in the
historically active exploration area. (id.
at 143). However, the results of the
study showed that there is a high
probability (90 percent) that drilling can
be conducted safely in sea ice
conditions in a majority of the
historically active exploration area of
the Chukchi Sea for 70 to 160 days if an
ice class MODU and associated support
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operation. (id. at 108 and 145).
Moreover, the NPC 2019 Report notes
that ‘‘vessels and equipment that are
positioned in the theater ‘just in case’
they are needed to minimize
environmental impact, can actually
impede personnel safety and source
control objectives, because they distract
operations personnel, add congestion,
and can impede surface access to the
well location.’’ (NPC 2019 Report at 19).
In the Beaufort Sea, the available open
water operating season is limited to
approximately 50 to 60 days across the
historically active exploration area. (id.
at 143). The study’s analysis showed
there is a high probability (90 percent)
that drilling can be conducted safely for
70 days, from mid-August through
October, in a majority of the historically
active exploration area of the Beaufort
Sea. (id. at 146).
In light of the information from the
NPC reports and the Bratslavsky and
SolstenXP study, and BSEE’s
consideration of that information, BSEE
proposes to revise § 250.472 in the
following manner:
• Proposed Paragraph (a)—
Complying with § 250.472 by Using an
SSID
The use of an SSID is not a new
concept and was discussed in the 2016
Arctic Exploratory Drilling Rule.47
Through the 2016 rulemaking comment
process, stakeholders informed the
Bureau that use of an SSID could help
significantly reduce the risk of a release
of hydrocarbons if the BOP system fails.
At that time, BSEE focused more on
permanent remediation to resolve a
WCD event in the Arctic. Nonetheless,
the Bureau agreed that an operator
could request to use an SSID as an
alternate procedure or equipment to the
relief rig (80 FR 9940). Stopping short of
requiring the use of an SSID, BSEE,
instead, stated in the 2016 rule that it
would consider the use of an SSID as an
alternate procedure or equipment, under
appropriate circumstances, if proposed
for use with a jack-up (when surface
BOPs are used). At that time, BSEE
determined that, in the case where
subsea BOPs are used in conjunction
with floating drilling units, SSIDs
would only be marginally effective or
redundant (81 FR 46531). Since the
47 See, e.g., 80 FR 9940 (‘‘[BSEE] requests
comments on alternative compliance approaches
and specifically requests data on the performance
of SIDs, including operational issues (such as
timeframes needed to activate such alternatives). In
particular, BSEE requests comments on appropriate
staging requirements for a relief rig assuming that
an SID has been installed at the exploration well.
Comments are also requested on the need for an
operator to have an in- season relief well drilling
capability if an SID is used at a location that is not
subject to ice scouring.’’)

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publication of the 2016 rule, BSEE has
reevaluated the use of SSIDs and the
overall improved technology for similar
components (BOPs). In this proposed
rule, BSEE would allow operators the
option to use an SSID based on BSEE’s
assessment of improved SSID design
and operating requirements, including
the ability to shut in a well over the
winter ice season with a well cap.
Additionally, BSEE would make this
revision to potentially minimize
environmental damage due to a
prolonged ongoing well control event.
An SSID is not a permanent solution for
well remediation. However, it can
provide a significantly quicker response
time to address a well control event
compared to drilling a relief well.
Consistent with the policy in E.O.
13783 to review existing regulations that
potentially burden the development or
use of domestically produced energy
resources, BSEE re-considered the SSID
more closely, in light of the SSID
information from the NPC reports and
the Bratzlavsky and SolstenXP study, to
determine whether the device could
address the issues the Bureau identified
when promulgating the 2016 rule.
Drilling a relief well is a complex,
time-consuming process. After setting
up the drill rig and drilling begins, the
process to intercept the original
wellbore may take several weeks or
more because the operator needs to drill
deep enough at great precision to ensure
interception of the original well. This
delay increases the length of the time oil
and other fluids within the original well
could be flowing uncontrollably into the
marine environment. There is no delay
for operational use of an SSID compared
to the process of using the relief rig or
capping stack.
In this proposed rule, BSEE
developed its proposed SSID
requirements based on existing BOP
equipment/technology whose
performance and reliability has been
tested, proven in a manner that is
repeatable and reproducible, and has
improved since promulgation of the
2016 rule. BSEE also proposes to require
an SSID used in the Arctic OCS to
operate independently from the BOP.
This would be accomplished by
requiring the SSID to have a redundant
control system, independent from the
BOP control system, and independent,
dedicated subsea accumulators to
operate the SSID. By having two
independent, redundant components
(i.e., the BOP and the SSID) as part of
the well control system, the overall
reliability and effectiveness of the entire
system increases. The following
paragraphs describe BSEE’s proposed
requirements associated with the SSID,

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including the SSID’s redundant control
system (i.e., under proposed
§ 250.472(a)(2)(ii)) and subsea
accumulators (i.e., under proposed
§ 250.472(a)(2)(iii)).
Although the NPC 2019 Report
recommended that the use of an SSID
and capping stacks replace the
requirement for an SSRW capability,
BSEE is not proposing to eliminate the
relief rig and SSRW requirements.
Rather, BSEE is proposing to maintain
the relief rig and SSRW requirement as
an option for the operator to meet the
regulatory requirements of § 250.472.
BSEE has determined that its
regulations should provide options and
flexibility to the operator (i.e., an SSID
or a relief rig) to fit its needs and plans
to develop its Arctic OCS leases. There
could be cases where the operator’s
drilling schedule may not align with the
availability of an SSID. In such a case,
the operator should have the option to
elect to proceed by complying with the
relief rig and SSRW requirements. If an
operator does not complete its
exploratory drilling operations during
that open water operating season, the
operator could come back during a
subsequent open water operating season
and use an SSID, if one has become
available in time.
There could also be cases where two
or more operators may plan to perform
exploratory drilling operations during
the same open water season. In such a
case, each operator’s drilling rig could
serve as the other’s relief rig. Under the
existing regulations, BSEE would
consider this type of a scenario to be in
compliance with the relief rig and
SSRW requirements. BSEE would not
change that interpretation as part of this
rulemaking. In a scenario like this, none
of the operators would need to install an
SSID, so long as there is an agreement
among the operators that their drilling
rigs will serve as a relief rig, if
necessary. While it is not possible to
identify every conceivable scenario,
BSEE recognizes there could be other
scenarios that are reasonably possible.
Thus, it is appropriate to provide
regulatory flexibility in order to
accommodate an operator’s drilling
program. BSEE also retains its
regulatory authority to approve alternate
procedures or equipment if the
proposed procedures or equipment
either meet or exceed the level of safety
and environmental protection required.
The term SSID is a broadly used
industry term, and there is not a single,
all-encompassing definition that
establishes the scope and function of an
SSID. In some cases, different terms are
used to describe the device. For
example, as stated earlier, the

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Bratslavsky and SolstenXP study refers
to the device as a ‘‘subsea intervention
device,’’ while some in the industry also
refer to the SSID as a ‘‘mudline closure
device.’’ Irrespective of these
synonymous titles, BSEE uses the term
SSID to refer to a fit-for-purpose device
that may be used for different types of
situations, including for well
intervention applications, and can be
used in different locations, including
outside of the Arctic. However, for the
purposes of Arctic OCS exploratory
drilling from a MODU, BSEE is
proposing to define the minimum
acceptable capabilities and functions of
an SSID. BSEE notes that, outside of the
Arctic OCS, operators are contemplating
using SSIDs for future projects, and
SSIDs have already been approved for
use in other parts of the OCS. The NPC
2019 Report notes that the requirement
to drill an SSRW to mitigate the risk of
a late season well control event
continuing over the winter season is
‘‘outdated.’’ The 2019 report concludes
that SSIDs and capping stacks are
superior solutions that could stop the
flow of oil and allow intervention
through the original borehole before a
relief well could be completed. (NPC
2109 Report at 19). The SSID
requirements BSEE is proposing to
establish in this proposed rule would
not apply to projects outside of the
Arctic OCS. The design requirements for
those SSIDs would be based on the
needs of a particular project and may or
may not be similar to what BSEE is
proposing in this proposed rule. BSEE
requests comments on these SSID
requirements as outlined in the
proposed rule.
Under proposed paragraph (a) of
§ 250.472, if the operator elects to satisfy
the requirements of this section by using
an SSID, BSEE would require the
operator to ensure that the SSID and
well design (including the casing and
cementing program) are designed to
achieve a full shut-in, without causing
an underground blowout or having
reservoir fluids broach to the seafloor.
Currently, BSEE’s regulations for
SCCE under § 250.462 do not require all
wells to be designed to achieve a full
shut-in (e.g., partial shut-in is
acceptable) as there are methods to
control the residual fluid flow into a
surface production and storage system
when a well is designed for partial shutin. However, because BSEE is proposing
that the SSID be designed to achieve full
wellbore shut-in until kill operations are
completed, it is important that the well
design assures that the well will be able
to withstand the associated loads for the
entire time the SSID is closed (e.g.,
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wellbore). If the wellbore is
compromised during or after a full shutin, an underground blowout or broach
to the seafloor may occur. BSEE
reviewed available incident data on loss
of well control events,48 and determined
that, on average, five loss of well control
events occurred each year on the OCS
between 2007 and 2017.
The well design language in proposed
paragraph (a) would also require the
operator to account for the stresses and
loads placed on the well from the
equipment that may be required to
regain control after a loss of well control
event. This includes the SSID, BOP
stack, and capping stack. It is imperative
that all well components are designed to
withstand all potential loads and
stresses placed on the well, including
those that may be required during well
control situations and deployment of
SCCE (i.e., the well must be able to
support a capping stack in addition to
the other equipment required for normal
operations).
The need for the operator to account
for all potential loads placed on the well
also includes consideration of
conditions where a well would be shutin over the ice season. For example, in
typical well control operations, a BOP is
used to stop the uncontrolled flow and
shut-in the well. It remains shut-in for
a relatively short period of time while
well kill operations are implemented
and, if needed, materials and personnel
are mobilized to the rig.
For wells that may be shut-in for
extended periods, the operator must
consider the potential effects of gas
expansion within the well. For example,
in reservoirs containing gas, which is
less dense than the liquids in the
wellbore (e.g., drilling mud, completion
fluid, brine), the gas will migrate
upward in the wellbore until it reaches
the closed BOP. This gas exerts a lower
hydrostatic pressure than the column of
oil or drilling fluids in the wellbore, and
more of the reservoir pressure is
transmitted to the top of the wellbore as
a result. As the hydrostatic pressure
acting on the bubbles decreases, the
bubbles expand.
As these bubbles continue to migrate
and expand over time, the wellbore
pressure profile increases. What was
once a low pressure at the top of the
well, with a hydrostatic pressure
gradient below it, will eventually
increase to reservoir pressure,
increasing the downhole pressure. As
the pressures in the wellbore increase,
some of the liquid may bleed into the
open formation(s). Eventually, the
48 See, BSEE’s website at https://www.bsee.gov/
stats-facts/offshore-incident-statistics.

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pressure may exceed the strength of the
formation (fracture pressure) in the
wellbore, potentially resulting in a
fracture of the formation and an
underground blowout. Because
proposed paragraph (a) of § 250.472
contemplates allowing the operator to
leave a well shut-in from one openwater season to the next (i.e., in the case
of a late season well control event),
wells need to be designed to withstand
this potential loading condition.
In a new paragraph (a)(1), BSEE
proposes to establish performance-based
design requirements for the SSID. BSEE
would require the operator to ensure
that the SSID is designed to:
(1) Close and seal the wellbore,
independent of the BOP;
(2) Perform under the maximum
environmental and operational
conditions anticipated to occur at the
well;
(3) Be left on the wellhead in the
event the drilling rig is moved off
location (e.g., due to storms, ice
incursions, or emergency situations);
(4) Preserve isolation through the
winter season without relying on the
elastomer elements of the rams (e.g., by
using a well cap) and allow re-entry
during the following open-water season;
and
(5) In the event of a loss of well
control, preserve isolation until other
methods of well intervention may be
completed, including the need to drill a
relief well.
BSEE’s analysis of loss of well control
events data indicates that the most
common methods employed to regain
control of a well include pumping mud
or cement into the uncontrolled well or
activating mechanical well control
equipment (e.g., blowout preventer).
These SSID design requirements
would help ensure the device is capable
of shutting in and containing all fluids
within the wellbore for an entire ice
season (in the case of a loss of well
control event too late in the open-water
season to provide enough time for the
operator to perform well kill or plug and
abandonment operations). BSEE is
basing the proposed design requirement
for the SSID to be capable of preserving
isolation through the winter season
without relying on the elastomer
elements of the rams (e.g., by using a
well cap) on information it gained from
the Kara Sea project. BSEE understands
that the SSID used in the Kara Sea
project was capable of preserving
isolation over an entire ice season
because it was designed to have a metalto-metal cap installed on top of the
SSID, after the BOP is detached and all
equipment is moved off of the drill site.
BSEE understands that isolation could

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not be achieved over the ice season if
the shut-in relied solely on the
elastomer elements of the rams. The
design requirements would also ensure
the SSID will allow for re-entry to
perform well recovery operations during
the following open water season.
In a new paragraph (a)(2), BSEE
proposes to require that the operator’s
SSID include the following equipment:
(1) Dual shear rams, including ram
locks; one ram must be a blind shear
ram;
(2) A redundant control system,
independent from the BOP control
system, that includes ROV (remotely
operated vehicle) capabilities and a
control station on the rig;
(3) Independent, dedicated subsea
accumulators with the capacity to
function all components of the SSID;
and,
(4) Two side inlets for intervention,
one of which must be located below the
lowest ram on the SSID.
The dual shear ram requirement in
proposed paragraph (a)(2)(i) would
ensure that the SSID is capable of
shearing through drill pipe, sealing the
wellbore, and containing the fluids
before they can escape during a loss of
well control event. BSEE notes that the
NPC 2019 Report describes the SSID as
having shearing/sealing rams. In fact,
when describing the SSID used in the
Kara Sea Project, the report explains
that the device utilized dual blind shear
rams. While proposed paragraph (a)(2)(i)
would require only one of the rams to
be a blind shear ram, BSEE is seeking
comment on the advisability of
requiring dual blind shear rams on the
SSID. As described in the bow-tie
diagram of the NPC 2019 Report, the
SSID is the last line of prevention to
minimize the impacts of an event. (NPC
2019 Report at 14).
The redundant control system
requirements in proposed paragraph
(a)(2)(ii) would ensure there is
reliability in the system and that the
SSID will function when needed in an
emergency situation. This proposed
requirement is intended to align with
the existing requirement in existing
§ 250.734(a)(2), which requires subsea
BOPs to have a redundant control
system to ensure proper and
independent operation of the BOP
system. With respect to the requirement
that an SSID have a separate control
station on the rig that is independent
from the BOP control system located on
the rig, it is important for the SSID
functions to be controlled by personnel
directly involved in the drilling process
to allow for an appropriate response
from a ‘‘situationally aware’’ individual.
Therefore, while BSEE is proposing to

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require the SSID control system to
remain independent of the BOP control
system, it would not require those
systems to be located in separate
locations.
BSEE is seeking comment on whether
the proposed requirement in paragraph
(a)(2)(ii) is appropriate for the SSID or
whether there are additional ways to
enhance the system’s reliability. For
example, BSEE is contemplating
whether it may be more appropriate to
require the SSID’s redundant control
system capabilities to be separate from
the ROV’s capabilities. BSEE is also
considering, as part of the final rule,
requiring the SSID control systems to be
consistent with the fully redundant
control system requirements described
in American Petroleum Institute (API)
Specification (Spec.) 16D (e.g., yellow
pod and blue pod). More specifically,
BSEE is further considering whether
there should be an additional manual
method (separate from the redundant
control system) to close the SSID’s rams
with the ROV and whether it may be
appropriate to require a standby or
tending vessel with an ROV. These
measures could address cases where the
SSID’s control system on the drilling rig
is not available (e.g., due to failure or an
evacuation of the rig).
The requirement in proposed
paragraph (a)(2)(iii) for SSIDs to have
independent, dedicated subsea
accumulators with capacity to function
all components of the SSID would help
ensure that, if the BOP system fails, the
SSID will have the capabilities to
function as needed, independent of the
BOP’s accumulator system. The
requirement in proposed paragraph
(a)(2)(iv) for SSIDs to have two side
inlets, with one of the inlets located
below the lowest ram on the SSID,
would allow for re-entry through the
SSID to perform well intervention
operations. Side inlets allow the
operator to pump fluids into the well to
kill the well, before opening the blind
shear ram to perform additional well
intervention operations.
In proposed paragraph (a)(3), BSEE
would require the SSID to include ROV
intervention equipment and capabilities
to function the SSID. BSEE regulations
currently include requirements for ROV
intervention capabilities in relation to a
BOP’s functionality. BSEE is proposing
similar requirements for the SSID
because the SSID functions similarly to
a BOP. Under proposed paragraph (a)(3),
the ROV equipment and capabilities
must:
(1) Be able to close each shear ram
under the Maximum Anticipated
Surface Pressures (MASP), as defined
for the operation;

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(2) Include an ROV panel that is
compliant with API RP 17H (as
incorporated by reference in § 250.198);
(3) Meet the ROV requirements in
existing § 250.734(a)(5); and,
(4) Have the ability to function the
SSID in any environment (e.g., when in
a mudline cellar).
The requirement in proposed
paragraph (a)(3)(i) for the ROV to be able
to close each shear ram under the
operation’s defined MASP would ensure
that the operator is able to remotely
close (through the ROV) each shear ram
on the SSID and seal the well, which are
the most critical functions during a well
control event. The requirement in
proposed paragraph § 250.472 (a)(3)(ii)
for the ROV to have panels that are
compliant with API RP 17H would
ensure that the operator’s ROV
capabilities for the SSID follow BSEE’s
existing ROV panel requirements for
BOP systems. API RP 17H provides
recommendations and overall guidance
for the design and operation of ROV
tooling used on offshore subsea systems
(e.g., provision for high flow Type D hot
stabs). This guidance is critical to
ensuring safe and reliable ROV
operations. In conjunction with the
proposal in paragraph (a)(3)(ii) to
require the operator’s ROV panels to be
compliant with API RP 17H, BSEE
proposes to add the citation for
proposed § 250.472(a)(3) to
§ 250.198(e)(73). Section 250.198(e)(73)
documents the locations in the
regulations where API RP 17H is
incorporated by reference as a
regulatory requirement, which would
include § 250.472(a)(3) under this
proposed rule. Adding the citation for
§ 250.472(a)(3) to § 250.198(e)(73) would
clarify that API RP 17H is a regulatory
requirement when complying with
§ 250.472 and is subject to BSEE
oversight and enforcement in the same
manner as other regulatory
requirements.
The requirement in proposed
paragraph (a)(3)(iii) for the operator to
meet the requirements in existing
§ 250.734(a)(5) would ensure that the
operator has a trained ROV crew on
each rig unit. The crew must ensure that
the ROV is maintained and capable of
carrying out the necessary tasks during
emergency operations and be trained in
operating the ROV, including stabbing
into the ROV intervention panel on the
SSID. The crew must also have the
capability to communicate with
designated rig personnel, who are
knowledgeable about the SSID’s
capabilities.
The requirement in proposed
paragraph (a)(3)(iv) for the ROV to be
capable of functioning the SSID in any

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environment is meant to address those
cases where it may be necessary to place
the SSID in an enclosed or restricted
environment. For example, if the SSID
is used in an area with ice scouring or
with deep ice keels, the SSID would be
placed in a mudline cellar. If the ROV
panels are attached to the SSID, the
ROV may not be able to access the
panels if there is not enough space in
the cellar. The operator must ensure that
the ROV has the capabilities to address
these types of scenarios. BSEE is aware
of current projects that are evaluating
positioning the ROV panels away from
the SSID. The ROV would function the
SSID from the remote panel, which
would be hardwired to the SSID. In
addition, it is possible for a mudline
cellar to be constructed via a dragline.
In such a case, the mudline cellar could
be constructed wide enough to provide
adequate space for the ROV to access
the panel if the panel was attached to
the SSID. BSEE proposes to make the
requirement in proposed paragraph
(a)(3)(iv) flexible, recognizing that there
are multiple ways an operator could
address this type of concern.
In general, however, BSEE is seeking
comment on the feasibility of installing
an SSID below a subsea BOP in cases
where the SSID would also be installed
in a mudline cellar. BSEE’s current
regulations at §§ 250.734(a)(13) and
250.738(h) require placement of subsea
BOP systems in mudline cellars when
drilling occurs in areas subject to icescouring. In addition, proposed
§ 250.720(c)(2) requires placement of the
wellhead in a mudline cellar in areas
subject to ice-scouring. BSEE is
requesting more information about
whether there are any other operational
or installation challenges that the
operator may encounter when
attempting to effectively operate the
SSID in this environment. If so, what are
those challenges, and how could they be
addressed?
BSEE understands that the SSID used
in the Kara Sea could be manually
activated using acoustic technologies.
While such technologies are available to
function the SSID from a remote
location, BSEE is proposing to require
use of an ROV, as described in proposed
paragraph (a)(3). BSEE understands that
ROVs are more reliable for this type of
application. However, BSEE requests
that commenters provide any
information that demonstrates the
reliability of acoustic (or other)
technologies to actuate an SSID from a
remote location.
Furthermore, although BSEE is not
proposing to require the SSID to have a
self-actuating function, the Bureau is
contemplating whether one may be

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necessary for certain emergency
situations. BSEE is aware that in the
Arctic OCS, it is possible for a drilling
vessel to sink and allide with (i.e., strike
against) the top of a wellhead during a
loss of well control event (Bratslavsky
and SolstenXP at 17). As discussed in
the previous section, all exploratory
drilling in the Beaufort Sea and the
Chukchi Sea has taken place in waters
less than 167 feet deep, and as recent as
April 2020,49 there were active leases in
the Beaufort Sea where an SSID could
have been deployed. These leases were
located in water depths less than
approximately 170 feet deep. In these
water depths, during an emergency, a
vessel could sink before the BOP or
SSID can be activated. A self-actuating
system incorporated into the SSID could
potentially address this problem.
One option BSEE is considering is
whether it may be appropriate to
establish an autoshear and deadman
system requirement for the SSID. The
intent would be to address those
emergency situations, such as when a
sunken MODU allides with the
wellhead, where the SSID could no
longer be functioned via the ROV (due
to lack of access) or a control station on
the drill ship. BSEE’s regulations
already address autoshear and deadman
systems for subsea BOPs. Existing
§ 250.734(a)(6)(i) requires subsea BOPs
to have an autoshear system that is
designed to automatically shut-in the
wellbore in the event of a disconnect of
the lower marine riser package (LMRP).
Also, existing § 250.734(a)(6)(ii) requires
a deadman system, that is designed to
automatically shut-in the wellbore in
the event of a simultaneous absence of
hydraulic supply and signal
transmission capacity in the subsea
control pods, respectively. However,
BSEE did not propose this requirement
for SSIDs in this rulemaking. The SSID
is meant to be a backup to the BOP, and
it is not necessary for the SSID to have
the same automatic emergency
functions as the BOP.
There could potentially be negative
consequences if both systems were to
automatically function. For example,
there could be a situation where the
BOP’s autoshear or deadman systems
function, but they are not able to shutin the well because a non-shearable drill
string is positioned across the rams. If
the subsea BOP rams are experiencing
49 In April 2020, the only leases with potential
projects that would be subject to the Arctic OCS’s
SSID or SSRW requirements were relinquished.
However, there are other active leases in the
Beaufort Sea located nearer to the shore in
shallower waters where exploration and
development projects are actively being pursued
(primarily through man-made gravel islands).

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this issue, then the SSID may also
encounter the same problem, depending
on the part of the drill string that is
across the rams at that time. In this
scenario, it would be more appropriate
to assess the situation to determine
whether other well intervention
operations could be performed to
address the position of the drill string,
before activating the SSID.
Regardless of these challenges, BSEE
is seeking comment on what fail-safe
mechanism(s) may be appropriate to
address cases where the BOP fails and
the SSID is inaccessible by an ROV or
a control station. If an autoshear system
or a deadman system are appropriate
fail-safe mechanisms to add to the SSID,
BSEE is seeking input on what criteria
should be used to function these
systems, to ensure the system does not
function at the wrong time or interferes
with or impacts the BOP’s autoshear
and deadman systems.
BSEE is also seeking comment on how
to ensure that the SSID will be able to
preserve isolation over the winter
season in the event of a late-season
emergency incident, such as a sunken
drillship. As previously mentioned,
BSEE understands that prior SSIDs have
planned for long-term isolation through
installation of a metal-to-metal cap (i.e.,
a well cap) on the SSID before leaving
the device on the seafloor over the
winter season. In the case of a lateseason emergency situation that
prevents access to the SSID to install a
metal-to-metal cap, how would isolation
be preserved through the winter season?
In addition, BSEE is soliciting
comment on whether the regulations
should require use of an autoshear or
deadman system in cases where these
systems are not built into the BOP’s
system. As previously mentioned,
BSEE’s autoshear and deadman system
requirements currently apply to subsea
BOPs. There is no current requirement
to use an autoshear or deadman system
when surface BOPs are used. BSEE
would expect that if an operator uses a
surface BOP, the operator would still
install the SSID on the seafloor. BSEE
seeks comment on whether it would be
appropriate in such a case to require use
of an autoshear or deadman system on
the SSID. If so, what criteria should
BSEE apply to the functioning of the
autoshear or deadman systems in an
environment where a surface BOP is
used? Furthermore, BSEE welcomes any
other comments, unrelated to autoshear
or deadman systems, regarding use of a
surface BOP.
With respect to installation of the
SSID, BSEE proposes in paragraph (a)(4)
to require operators to install the SSID:
(1) Below the BOP;

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(2) At or before the time they install
their BOP; and
(3) In a way that will provide
protection from deep ice keels in the
event it must remain in place over the
winter season (e.g., installed in a
mudline cellar).
Installing the SSID below the BOP
would allow for quick detachment of
the BOP and other equipment above the
SSID, which would be critical when
moving off of a location for emergency
purposes. With respect to timing of the
SSID’s installation, the operator would
be required to install the SSID at or
before the time they install the BOP.
The proposed requirement for the SSID
to be installed in a way that will provide
protection from deep ice keels would
help ensure that the device is not
damaged by ice in areas of ice scour. As
previously discussed, this could be
accomplished by placing the SSID in a
mudline cellar. In complying with this
proposed requirement, the operator
must also consider situations where the
drill site is not located in an ice scour
area, but could experience ice floes with
keels deep enough to clip and
compromise the SSID if left on the
seafloor over the winter season.
In a new paragraph (a)(5), BSEE
proposes to require the operator to test
the SSID according to the BOP testing
requirements in § 250.737, What are the
BOP system testing requirements? The
SSID’s testing requirements should align
with the BOP testing requirements
since, as previously mentioned, the
SSID functions similarly, and in
addition, to a BOP. This testing would
aid in predicting future performance of
the SSID to ensure that the device will
function when needed during an
emergency situation. While BSEE
proposes to align the SSID testing
requirements with the Bureau’s existing
BOP testing requirements, BSEE
welcomes input on whether there are
more appropriate and reliable testing
methods. For example, what testing
procedures have been used in the past
to test an SSID when it was deployed?
For future operations, what testing
procedures are being developed
specifically for an SSID? What testing
procedures should be applied to SSIDs,
and why?
Overall, BSEE intends for the SSID to
provide time for the operator to marshal
the equipment and materials necessary
to permanently address a well control
event, without the constraints of
seasonal ice coverage, and to prevent
the potential environmental impacts
that could occur if an out of control well
was allowed to flow over the season
when the operator would not have
access to the site due to ice. The SSID,

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along with the proper well design,
would allow the well to be shut in over
the ice season without requiring
additional vessels and the situation
addressed permanently in the following
open water season. It would also allow
the operator the time necessary to
complete the intervention, without the
well flowing, if unforeseen problems are
encountered.
Collectively, the SSID’s design
requirements; equipment specifications;
ROV intervention capabilities;
installation requirements; and testing
requirements; together with the
additional well design requirements,
would help ensure that the device will
function when needed during an
emergency situation and will be capable
of controlling the well over the ice
season, if necessary, until the operator
returns to perform well intervention
operations during the following openwater season. In connection with that
well intervention operation, BSEE may
still exercise its existing authority to
also require the operator to drill a relief
well to permanently plug and abandon
the out-of-control well, if needed. BSEE
reviewed recent incident data from 2013
to 2017, which may be accessed on
BSEE’s website at https://www.bsee.gov/
stats-facts/offshore-incident-statistics, to
try to identify any past incidents
involving the use of a BSEE directed
relief well to remedy the loss of well
control. Aside from the Macondo well
incident in 2010, one incident in 2013
required the drilling of a relief well (see
https://www.bsee.gov/newsroom/latestnews/statements-and-releases/pressreleases/drilling-of-relief-well-begins-atsouth). Other loss of well control events
during that timeframe were successfully
remedied with conventional well
control methods. These incidents
occurred in the Gulf of Mexico and were
controlled by either circulating heavier
weighted muds into the well or closing
the BOP (or both), to control pressures
within the well. BSEE would evaluate
the individual circumstances associated
with each case to make this
determination. For these reasons,
BSEE’s proposed changes to § 250.472
would maintain safety and
environmental protection, though BSEE
invites comment on the technical
feasibility of such requirements.
BSEE is seeking comment on whether
the use of an SSID, particularly in a case
where a subsea BOP is deployed, could
present operational or installation
challenges. For example, if the well is
not located in an ice scour area and the
BOP system, including the LMRP, and
the SSID are placed on the seafloor, then
these pieces of equipment could get as
tall as 88 feet when installed (BOP

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approximately 70 feet + SSID
approximately 18 feet). In addition, the
bottom of a ship’s hull, in the case
where a drillship is used, may extend as
much as 40 feet into the water from the
sea surface. Historically, drilling in the
Beaufort Sea and the Chukchi Sea has
occurred in waters less than 167 feet
deep. With as much as 128 feet of water
column taken up by the BOP system,
SSID, and ship’s hull, very little space
remains for operations between the
bottom of the ship and the top of the
well control system. BSEE seeks
comment on what sorts of challenges
operators have faced or would
anticipate facing in the scenario just
described. BSEE would also like to
know how operators addressed those
challenges in the past or could address
them for future operations, taking into
account the unique characteristics and
extreme conditions of the Arctic OCS.
BSEE is also generally seeking
comment on its proposed changes to
§ 250.472. For example, BSEE is seeking
comments on how well design could be
better addressed in this rulemaking to
enhance overall safety of operations on
the Arctic OCS. Is the well design
requirement proposed in paragraph (a)
adequate to address the situations that
may be encountered if a well is shut-in
with an SSID over a winter season? As
previously described, there could be
cases where the wellbore pressure
profile may increase to reservoir
pressures at the top of the well over the
course of a winter season. What other
scenarios should BSEE consider that
could occur in the well over the ice
season that could be addressed in
proposed paragraph (a)?
• Proposed Paragraph (b)—
Complying with § 250.472 by Having
Access to a Relief Rig
As discussed earlier, BSEE proposes
to combine existing paragraphs (a) and
(b) into a single, new paragraph (b),
Relief Rig, for organizational purposes
because both existing paragraphs cover
relief rigs. Combining existing
paragraph (a) into proposed paragraph
(b) would not be a substantive
modification to BSEE’s regulations
because the specific requirements from
existing paragraph (a) would remain
unchanged. More specifically, the
provision in existing paragraph (a) that
requires the operator’s relief rig to
comply with all other requirements of
30 CFR part 250 that pertain to drill rig
characteristics and capabilities, and
requires the relief rig to be able to drill
a relief well under anticipated Arctic
OCS conditions, would be relocated to
proposed paragraph (b)(1). The
provision in existing paragraph (a) that
provides that the Regional Supervisor

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may direct the operator to drill a relief
well in the event of a loss of well
control would be relocated to proposed
paragraph (b)(2).
Æ Last Casing Point Prior to
Penetrating a Zone Capable of Flowing
Hydrocarbons in Measurable Quantities
Substantively, BSEE proposes to
revise the requirements in existing
paragraph (b) that prescribe the
availability of the relief rig. BSEE would
maintain the requirement for the
operator to have access to a relief rig,
different from its primary drilling rig,
when drilling or working below the
surface casing. However, BSEE proposes
to add a new provision to the newly
rearranged proposed paragraph (b)
stating ‘‘However, the Regional
Supervisor will approve delaying access
to your relief rig until your operations
have reached the last casing point prior
to penetrating a zone capable of flowing
hydrocarbons in measurable quantities,
provided that you submit adequate
documentation (such as, but not limited
to, risk modeling data, off-set well data,
analog data, seismic data), with your
APD, demonstrating that you will not
encounter any abnormally highpressured zones or other geological
hazards. The Regional Supervisor will
base the determination on any
documentation you provide as well as
any other available data and
information.’’
BSEE would also add new language at
the beginning of existing paragraph (b)
that says ‘‘Relief Rig. If you choose to
satisfy this requirement by having
access to a relief rig, you must have
access to your relief rig at all times
when you are drilling below or working
below the surface casing during Arctic
OCS exploratory drilling operations.’’
This language would simply clarify that
if the operator chooses to use a relief rig
to comply with proposed § 250.472, it
must have access to its relief rig at all
times when drilling below or working
below the surface casing. The changes
described in this paragraph would be
shown as a general requirement in
proposed paragraph (b).
BSEE’s proposed revisions to
paragraph (b) would potentially provide
an opportunity for the operator to adjust
the point in time during its operations
when it must stage its relief rig. If the
operator is able to demonstrate to BSEE
that the operations it plans to conduct
below the surface casing would not
encounter any abnormally highpressured or other geologic hazards
before reaching the last casing point
prior to penetrating a zone capable of
flowing hydrocarbons in measurable
quantities, then BSEE would allow the

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operator to delay staging of its relief rig
until reaching that point.
The changes BSEE is proposing would
make proposed paragraph (b) of
§ 250.472 and proposed paragraph (a) of
§ 250.471 consistent, with respect to
providing a potential opportunity to the
operator to delay access to its SCCE (as
described in § 250.471(a)(1) and
proposed § 250.471(a)(2) and (3)) until
its operations have reached the last
casing point prior to penetrating a zone
capable of flowing hydrocarbons in
measurable quantities, so long as the
operator submits adequate
documentation, with its APD,
demonstrating that it will not encounter
any abnormally high-pressured zones or
other geologic hazards before that casing
point.
The existing requirement in
§ 250.472(b) pertaining to the
availability of a relief rig does not take
into consideration that the operator may
demonstrate, based on geologic and
engineering analyses, that there could
be zones below the surface casing that
are not hydrocarbon-bearing or that
have minimal or no potential to flow
hydrocarbons in measurable quantities
during drilling operations. In many
cases, operators do not anticipate or
encounter flowable hydrocarbons in
measurable quantities until the target
productive formation is reached. For
example, a surface casing shoe setting
depth for an Arctic OCS exploration
well could be only 1,500 feet deep, but
the hydrocarbon bearing formation may
be thousands of feet deeper below that
point. The existing regulations require
the operator to stage its relief rig when
drilling or working below the surface
casing, even though geologic and
engineering risk analyses the operator
must submit as part of their APD may
indicate that there is little or no
potential for hydrocarbons to escape the
formation and flow into the well prior
to reaching the targeted productive
formation. In such circumstances, the
operator could safely drill for thousands
of feet below the surface casing without
any identifiable need for a relief rig.
This proposed change would, when
appropriate, eliminate the need for the
operator to stage its relief rig while
drilling through low risk, nonproductive sections of the well below
the surface casing. Arctic regional pore
pressure modeling conducted by BOEM
for an area in the Beaufort Sea identifies
a general uniformity following an
average pressure gradient (i.e., normally
pressured) up to approximately 7,500
feet to 8,500 feet, subsea. The typical
reservoirs targeted for exploration in the
Arctic are usually located at less than
8,000 feet. In the GOM, there are many

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different geological features that can
affect the pressure profiles and
potentially create abnormal pressures
(e.g., salt domes, and shallow water flow
areas).
An extensive amount of geophysical
data already exists for certain areas of
both the Beaufort and Chukchi Sea
Planning Areas, and there has been
extensive drilling in certain areas of the
Beaufort Sea Planning Area. In the
known geologic conditions of the U.S.
Arctic, operators have a good
understanding of the locations of
reservoirs that they will encounter,
which can be relatively shallow and
normally pressured to certain depths.
Therefore, it may not be necessary to
have a relief rig immediately available
when drilling through zones below the
surface casing that do not have
abnormally high formation pressures or
contain other geological hazards, and do
not have the potential to flow
hydrocarbons in measurable quantities
as they are penetrated.
However, because geologic conditions
are not uniformly normally pressured
throughout the Arctic OCS, BSEE is
maintaining the existing requirement to
have the relief rig staged when drilling
or working below the surface casing. At
the same time, BSEE does not want to
discount the possibility that future
projects would not need to have the
relief rig staged until reaching the last
casing point prior to penetrating a zone
capable of flowing hydrocarbons.
The criteria BSEE proposes to rely
on—that the operator can demonstrate
to BSEE that it will not encounter
‘‘abnormally high-pressured zones or
other geologic hazards’’—to determine
whether to grant an exception accounts
for those downhole risks that could lead
to a blowout and may require the use of
a relief rig. With respect to abnormally
high-pressured zones, BSEE is
concerned that there could be a case
where a kick (an influx, or flow, of
formation fluid from the high-pressured
zone entering into the wellbore) is not
controlled and could lead to a blowout.
While there are means of mitigating the
risk of a kick, (i.e., overbalanced
drilling), the relief rig needs to be
readily available if heavier weight
drilling muds, the BOP and SSID, if
applicable, fail to control the well.
There could be other geologic
hazards, such as fractured or high
permeability zones, that may also pose
a risk, particularly if those zones
contain hydrocarbons. It is possible that
normally pressured zones may be highly
permeable or contain fractures, in which
lost circulation can occur. This could
cause a dynamic effect where drilling
mud flows into the permeable formation

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and causing the circulating pressure to
decrease below the zone’s pore pressure
resulting in formation fluids flowing
into the well bore. This may lead to a
loss of well control. The relief rig needs
to be readily available if heavier weight
drilling muds, the BOP, and the capping
stack, fail to control the well.
However, if the operator is able to
demonstrate that a highly permeable or
fractured zone is predicted to only
contain water, BSEE would consider
allowing the operator to delay the
staging of its relief rig. Under this
scenario, the operator would be able to
use the diverter system in conjunction
with the BOP system to maintain safety
and environmental protection because it
would be unlikely for hydrocarbons to
be released into the environment. The
diverter system consists of a mechanical
device similar to a BOP annular
preventer. The diverter system is used
to divert gases, fluids, and other
materials flowing from the well, away
from facilities and personnel. Also, an
operator would pump fluid loss
materials into the well to bridge the
formation to reduce its permeability and
allow drilling muds to isolate the
formation from the well. To
permanently address the incident, the
operator could also install a liner or set
a new casing point at the interval where
that highly permeable or fractured zone
is located. As requested in the sectionby-section discussion of § 250.471,
BSEE would like to know whether there
are more appropriate criteria, other than
‘‘abnormally high-pressured zones or
other geologic hazards,’’ the Bureau
should use to determine whether to
allow the operator to delay its staging of
the relief rig.
BSEE’s proposed regulatory language
describing the types of documentation it
would consider adequate to demonstrate
that abnormally high-pressured zones or
other geologic hazards would not be
encountered before reaching the last
casing point prior to penetrating a zone
capable of flowing hydrocarbons in
measurable quantities— ‘‘such as, but
not limited to, risk modeling data, offset well data, analog data, seismic
data’’—is not meant to be an exhaustive
list. BSEE would accept any other types
of documentation the operator may
provide that will help its demonstration.
BSEE does not anticipate this
submission requirement would lead to a
significant information collection
burden on the operator because it is
normal practice for operators to gather
these types of information in order to
develop and design an offshore
exploration drilling project in the Arctic
OCS. BSEE is requesting comment on
what other types of information could

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be used to demonstrate the absence of
abnormally pressured zones or other
geologic hazards, and how burden on
the operator could change—increase or
decrease—if BSEE were to require its
submission.
At the APD stage, BSEE would
evaluate the operator’s documentation
along with other accompanying geologic
and engineering information/analyses
that must be submitted as part of their
APD. BSEE would also take into
consideration any other available G&G
information, such as information
gathered from prior drilling operations
in the area (e.g., well log and pressure
testing information), and any other
applicable geophysical information (e.g.,
seismic data). BSEE makes clear in its
proposed regulatory language that the
Regional Supervisor will base the
determination for whether to allow the
operator to delay staging of its relief rig
on the documentation the operator
submits as well as any other available
data and information.
BSEE is also considering an
alternative regulatory approach whereby
the Bureau would instead revise
existing paragraph (b) by replacing
‘‘surface casing’’ with ‘‘last casing point
prior to penetrating a zone capable of
flowing hydrocarbons in measurable
quantities.’’ This option would adjust
the point in time during operations
when the operator must stage its relief
rig. This alternative regulatory change
would, instead, require the operator to
stage its relief rig before drilling below
or working below the last casing point
prior to penetrating a zone capable of
flowing hydrocarbons in measurable
quantities.
Under this regulatory option, BSEE
would evaluate the geologic and
engineering information/analysis the
operator must submit as part of its APD,
while also taking into consideration any
other available G&G information the
Bureau may have (e.g., off-set well data,
such as well logs and pressure testing
information, or geophysical information,
such as seismic data). Based on these
different sources of information, BSEE
would determine whether there may be
a need for the operator to position the
capping stack at an interval earlier than
last casing point prior to penetrating a
zone capable of flowing hydrocarbons in
measurable quantities.
There may be cases where the
operator or BSEE may not have
sufficient G&G or analogous well data
during the permit review process on a
proposed project to provide an adequate
level of certainty regarding anticipated
formations that may be encountered
prior to reaching the targeted productive
formation. Therefore, BSEE is also

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contemplating, as part of this regulatory
option, a clarification that the Regional
Supervisor may require the operator to
stage its relief rig prior to drilling below
or working below the last casing point
prior to penetrating a zone capable of
flowing hydrocarbons in measurable
quantities if BSEE determines there is
insufficient G&G or analogous well data.
For example, there may be
insufficient G&G or analogous well data
in cases where there have been a limited
number of wells drilled within
proximity to the planned well. In most
cases, G&G and analogous well data are
gathered from multiple sources.
However, the same sets and amounts of
data and information may not be
available for each area, well, or project.
There is no single set of criteria for
determining the sufficiency of G&G or
analogous well data. The more data that
are available from sources near to the
proposed drilling location, the greater
confidence BSEE will have in the G&G
interpretations. BSEE wants to ensure
the operator has the most accurate data
to make determinations about where the
zones capable of flowing hydrocarbons
in measurable quantities are located.
This alternative regulatory option
would maintain the same level of safety
and environmental protection in
comparison to BSEE’s proposed
regulatory change. The decision on
whether it is appropriate to delay
positioning of the capping stack below
the surface casing resides with BSEE.
BSEE, ultimately, may not allow the
operator to delay staging of the relief rig
if there are potential risks below the
surface casing that may require
immediate relief rig deployment.
However, the distinction under this
regulatory option is that the operator
would not need to specifically
demonstrate that abnormally highpressured zones or other geologic
hazards would be encountered above
last casing point prior to penetrating a
zone capable of flowing hydrocarbons in
measurable quantities. BSEE would be
responsible for making that
determination.
BSEE is specifically soliciting
comments about its views of the benefits
or disadvantages of this regulatory
option and the need for the operator to
verify on a case-by-case basis which
zones are incapable of flowing
hydrocarbons in measurable quantities.
Æ Expected Seasonal Ice
Encroachment at the Drill Site
In the 2015 proposed Arctic
Exploratory Drilling Rule, BSEE
determined that, because Arctic OCS
exploratory drilling operations from a
MODU take place only during the open
water season (i.e., that period of time in

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the summer and early fall when ice
hazards can be physically managed and
there is no continuous ice layer over the
water), it was critical to ensure that
drilling (including relief well drilling)
and other operations affected by sea ice
are concluded before ice encroachment.
Ice encroachment may complicate or
prevent drilling, transit, and oil spill
response operations. However, the
analysis from the Bratslavsky and
SolstenXP study shows that the sea ice
capabilities of an ice class MODU and
its support vessels can extend the
currently available open-water operating
seasons in the Chukchi and Beaufort
Seas, depending on the drilling location
within each planning area (id. at 143).
Therefore, BSEE proposes to eliminate
the reference to ‘‘expected seasonal ice
encroachment’’ at the drill site in
existing paragraph (b). BSEE, however,
would retain the requirement clarifying
that the relief rig must be different than
the operator’s primary drilling rig and
that the relief rig must be staged in a
location such that it can arrive on site,
drill a relief well, kill and abandon the
original well, and abandon the relief
well no later than 45 days after the loss
of well control. This proposed
regulatory change would effectively
extend the drilling season in those cases
where the operator’s MODU and
associated support vessels are capable of
safely operating beyond the period
when seasonal sea ice begins to
encroach at a drill site. The operator
would no longer need to plan for their
well operations to end in time to
complete a relief well prior to the date
when sea ice is expected to encroach on
the drill site. The operator would,
instead, have to plan to end its
operations with sufficient time to
complete its relief well prior to the
anticipated date when sea ice
conditions at the drill site are
approaching the ice classification
capability and rating limits of the
operator’s vessels.
BSEE and BOEM would evaluate the
ice classification capabilities and
limitations of the operator’s MODU and
associated support vessels using
existing permitting and review
processes. For example, through
BOEM’s EP review process, the operator
is required under existing
§ 550.220(c)(6) to specify when it
anticipates completing onsite operations
and when it anticipates terminating
drilling operations. In addition,
§ 550.220(c)(1) requires the operator to
describe how it will design and conduct
its exploratory drilling activities in a
manner that accounts for Arctic OCS
conditions. Furthermore, in the EP

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regulations at proposed § 550.220(c)(1),
BOEM would require the operator to
submit a description of how all vessels
and equipment will be designed, built,
and/or modified to account for Arctic
OCS conditions and how such activities
will be managed and overseen as an
integrated endeavor. This preamble
discusses this proposed regulatory
change in more detail later. Collectively,
this information provided in an EP
would allow BOEM (in conjunction
with BSEE) to evaluate the capability of
the operator’s equipment, including its
vessels and procedures to manage and
mitigate risks associated with Arctic
OCS conditions.
At the APD stage, BSEE would also
review the capabilities of the operator’s
MODU and associated supporting
vessels. Existing paragraph (a)(2) of
§ 250.470, What additional information
must I submit with my APD for Arctic
OCS exploratory drilling operations?
requires the operator to describe how it
plans to prepare its equipment,
materials, and drilling unit for service in
the environmental, meteorological, and
oceanic conditions it expects to
encounter at the well site and how its
drilling unit will be in compliance with
the requirements of existing § 250.713,
What must I provide if I plan to use a
Mobile Offshore Drilling Unit (MODU)
for well operations. Paragraph (d) of
§ 250.713 requires the operator, when
using a MODU for well operations, to
provide the current Certificate of
Inspection (for U.S.-flag vessels) or
Certificate of Compliance (for foreignflag vessels) from the USCG, as well as
a Certificate of Classification. The
operator must also provide current
documentation of any operational
limitations imposed by an appropriate
classification society. As discussed
earlier in this section, the Bratslavsky
and SolstenXP study notes that a
vessel’s capabilities are identified by the
ice classification for the vessel, which is
provided by marine classification
societies such as ABS and DNV GL.
BSEE would evaluate the information
required under existing §§ 250.470(a)(2)
and 250.713(d), together with BOEM’s
approval of the operator’s end-of-season
date(s) in the EP, to verify whether the
vessels’ capabilities and limitations can
support extending operations beyond
when seasonal ice is expected to arrive
at the drill site. However, in no case will
BSEE approve a permit that proposes to
use a vessel that does not meet the
existing requirements of § 250.713,
including providing a current certificate
of inspection or compliance from the
USCG.
Finally, while BSEE is proposing
these revisions to § 250.472, BSEE is

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seeking comment on whether there are
other appropriate approaches to well
control operations in the Arctic,
including alternative equipment/
technology or performance standards.
For example, although the NPC 2019
Report recommends accepting the use of
an SSID in place of the requirement for
SSRW capability, it also recommends
replacing the relief rig and SSRW
requirements with requirements that
specify the desired outcome (i.e., to stop
the flow of a well and allow the operator
to propose equivalent technology and
demonstrate its capabilities). (NPC 2019
Report at 30). BSEE assumes that the
NPC recommends specifying a desired
performance-based outcome in the
regulations that would allow the
operator to propose and demonstrate
technologies capable of meeting that
standard at the permitting stage, rather
than prescribing a particular technology,
such as a relief rig.
Subpart G—Well Operations and
Equipment
When and how must I secure a well?
(§ 250.720)
BSEE proposes to delete the last
sentence in existing paragraph (c)(2)
that states ‘‘BSEE may approve an
equivalent means that will meet or
exceed the level of safety and
environmental protection provided by a
mudline cellar if the operator can show
that utilizing a mudline cellar would
compromise the stability of the rig,
impede access to the well head during
a well control event, or otherwise create
operational risks.’’ In its place, BSEE
proposes to insert a new sentence that
states ‘‘You may request, and the
Regional Supervisor may approve, an
alternate procedure or equipment in
accordance with §§ 250.141 and
250.408.’’ BSEE, however, would
preserve the basic requirement in in
paragraph (c)(2) for the operator to use
a mudline cellar or an equivalent means
if there is indication of ice scour. The
regulatory change BSEE is proposing in
this section would make clear that BSEE
could approve the equivalent means of
doing so in accordance with §§ 250.141,
May I ever use alternate procedures or
equipment? and 250.408, May I use
alternate procedures or equipment
during drilling operations?
The new language that BSEE proposes
to insert reiterates longstanding
regulatory provisions contained in
§§ 250.141 and 250.408 that describe
what procedures the operator must
follow and standards it must meet to
receive BSEE’s approval of a request to
use alternate procedures or equipment
to those required by regulation. Section

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250.141 allows the BSEE District
Manager or Regional Supervisor to
approve the use of any alternate
procedures or equipment that the
operator may propose if the proposal
provides a level of safety and
environmental protection that equals or
surpasses BSEE’s current requirements.
It also describes the types of information
the operator must submit or present to
BSEE when requesting to use alternate
procedures or equipment. Section
250.408 requires the operator to identify
and discuss their proposed alternate
procedures or equipment in their APD.
Since the issuance of the 2016 Arctic
Exploratory Drilling Rule, BSEE learned
that there is an industry misconception
that the last sentence in existing
paragraph (c)(2) means that the operator
would be required to use a mudline
cellar in all cases, except when the
operator can prove that the mudline
cellar would present an operational
risk—effectively narrowing the scope of
§§ 250.141 and 250.408 in this context.
However, BSEE did not intend that
language to constrain the contexts in
which operators could seek approval of
alternatives to the mudline cellar
requirement. Rather, in response to
commenters expressing concern that use
of a mudline cellar may create
operational risks in certain contexts,
BSEE introduced that language to make
clear that alternate approaches were
available in those contexts, while at the
same time highlighting the general
flexibility available under § 250.141,
May I ever use alternate procedures or
equipment? (see 81 FR 46507 and
46510). The last sentence in existing
paragraph (c)(2) was not intended to,
and did not, restrict or preclude use of
the longstanding options for seeking
approval of alternate procedures or
equipment under §§ 250.141 and
250.408, which do not necessarily
require a demonstration of operational
risk. Thus, this proposed change would
clarify that the operator has more
flexibility to propose alternate solutions
to the mudline cellar requirement under
a broader range of circumstances than
those described in the last sentence of
existing § 250.720(c)(2). An operator
could still base such a request on the
same grounds that BSEE described in
the language that we propose to delete
(i.e., that installation of a mudline cellar
in a specific case would cause
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B. Key Revisions Proposed by BOEM
Title 30, Chapter V, Subchapter B, Part
550, Subpart B—Plans and Information
Definitions. (§ 550.200)
BOEM is proposing to eliminate the
definition of the term ‘‘Integrated
Operations Plan,’’ consistent with the
proposal to eliminate the requirement
for the operator to submit an IOP for the
reasons listed immediately below.
Removal of the IOP Requirement
(§ 550.204)
The 2016 Arctic Exploratory Drilling
Rule discussed how commenters
generally criticized the IOP provision as
being duplicative or redundant of
existing requirements (see 81 FR at
46492–46493). In 2016, when the rule
was adopted, BOEM disagreed with
these commenters and published
responses to the commenters in the
preamble. In its responses, BOEM
discussed how the IOP was distinct
from existing regulations, the
importance of contractor management as
it related to the IOP provisions, and the
BOEM Regional Director’s ability to
waive submission of required
information in the EP that was already
provided in the IOP. Circumstances
have changed since the IOP requirement
was originally adopted. The various
Federal agencies have improved their
coordination to such an extent that
BOEM believes there is no need for
operators to create and submit a
separate IOP for that purpose. Much of
the required content of the two
documents overlaps, and in the 2016
rulemaking itself BOEM added
requirements that the EP include
additional information that made this
overlap even greater. BOEM is now
proposing to keep two important
provisions from the IOP and incorporate
them into the requirements for EPs. The
first provision would reinforce BOEM’s
commitment to operational safety, while
the second provision would require the
operator to provide details of how its
operations would conform to the unique
circumstances of the Arctic OCS. Taken
together, the enhancements to BOEM’s
regulations made in connection with the
2016 Arctic Exploratory Drilling Rule
and the retention of these key
provisions from the IOP make the IOP
unnecessary and redundant.
For these reasons, BOEM proposes to
eliminate the requirement for preparing
and submitting the IOP. In doing so,
BOEM would delete all of § 550.204,
and remove corresponding references to
the IOP from §§ 550.200 and 550.206.
Currently, BOEM requires the operator
to submit an IOP at least 90 days before
filing an EP with BOEM. The IOP is not

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subject to agency approval. BOEM
developed the IOP requirement based
on the Report to the Secretary of the
Interior, Review of Shell’s 2012 Alaska
Offshore Oil and Gas Exploration
Program, prepared by DOI (60-Day
Report), March 2013,50 which
included 51 the following
recommendation:
All phases of an offshore Arctic program—
including preparations, drilling, maritime
and emergency response operations—must be
integrated and subject to strong operator
management and government oversight. (60day report, p. 3).

The information provided in the IOP
was intended to facilitate the prompt
sharing of information among the
relevant Federal agencies (e.g., BOEM,
BSEE, USFWS, USCG, NMFS, U.S.
Army Corps of Engineers, and EPA).
Standing BOEM practice (LP–SOP–06
Standard Operating Procedure for
Exploration Plans) in the Anchorage,
Alaska OCS Office is to inform other
agencies about an operator’s EP, well in
advance of the completeness review
(i.e., the deemed submitted
determination) for the EP. BOEM
successfully did so prior to the 2016
implementation of the IOP requirement.
The IOP requirement does not
supersede or supplant the operator’s
obligation to comply with all other
applicable Federal agency requirements.
As described in the 2016 Arctic
Exploratory Drilling Rule, the IOP
process does not provide a mechanism
for agencies to approve or disapprove
the operator’s proposed activities.
BOEM has no authority under the IOP
provision other than to make
unenforceable suggestions to the
operator. If BOEM or another agency
determined that an operator was failing
to engage in the needed integrated
planning in advance of EP submission,
BOEM could only compel an operator to
do so through the EP review process.
The 2016 Arctic Exploratory Drilling
Rule added informational requirements
for EPs to address key concerns that
motivated the IOP, as shown in Table 1,
‘‘Crosswalk between the IOP provisions
proposed for removal and existing EP
regulations and review practices.’’
Because this information is required in
the EP, operators should be aware that
they must plan for how they will
manage contractors to reduce
50 Available at: https://www.doi.gov/sites/doi.gov/
files/migrated/news/pressreleases/upload/Shellreport-3-8-13-Final.pdf.
51 Report to the Secretary of the Interior, Review
of Shell’s 2012 Alaska Offshore Oil and Gas
Exploration Program, prepared by DOI (60-Day
Report), March 2013, available at: https://
www.doi.gov/sites/doi.gov/files/migrated/news/
pressreleases/upload/Shell-report-3-8-13-Final.pdf.

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operational risks and address the
challenges associated with operations
on the Arctic OCS. The EP regulations
are clear that the operator must plan to
coordinate the work of a number of
contractors to ensure that time pressure,
or other contractor complications, do
not undermine safe and
environmentally responsible operations.
In particular, proposed § 550.220(c)(1)
would require the operator to describe
in the EP how it will design and
conduct its exploratory drilling
activities, and how it will manage and
oversee these activities as an integrated
endeavor. BOEM does not need, and
nothing in OCSLA requires, an operator
to inform Federal agencies about its
planning on these issues in advance of
an EP. The EP, however, will make
evident whether the operator has done
so, and if the EP does not address the
operators’ planning on all the required
elements, BOEM will return the EP to
the operator to include the requisite
information in accordance with existing
§ 550.231(b).

As part of the 2016 Arctic Exploratory
Drilling Rule, BOEM expanded the
regulatory criteria for EPs to include
information important for planning
Arctic exploratory drilling. Specifically,
BOEM expanded requirements for:
Emergency plans at existing
§ 550.220(a), the EP’s suitability for
Arctic OCS conditions at proposed
§ 550.220(c)(1), ice and weather
management at existing § 550.220(c)(2),
SCCE capabilities at existing
§ 550.220(c)(3), deployment for a relief
rig at proposed § 550.220(c)(4), resourcesharing at existing § 550.220(c)(5), and
anticipated end of seasonal operation
dates at existing § 550.220(c)(6).
BOEM’s EP and environmental impact
analysis (EIA) requirements at existing
§ 550.202, What criteria must the
Exploration Plan (EP), Development and
Production Plan (DPP), or Development
Operations Coordination Document
(DOCD) meet?, existing paragraphs (a)
and (c) of § 550.211, What must the EP
include?, existing paragraph (c) of
§ 550.216, What biological, physical,

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and socioeconomic information must
accompany the EP?, existing paragraphs
(a) and (b) of § 550.219, What oil and
hazardous substance spills information
must accompany the EP?, existing
paragraphs (b), (c)(2) and (5) of
§ 550.220, If I propose activities in the
Alaska OCS Region, what planning
information must accompany the EP?,
proposed paragraph (c)(1) of § 550.220,
existing paragraph (a) of § 550.224,
What information on support vessels,
offshore vehicles, and aircraft you will
use must accompany the EP?, and
existing paragraph (b)(7) of § 550.227,
What environmental impact analysis
(EIA) information must accompany the
EP? require the operator to address
issues that the operator also needs to
consider in preparing the IOP. The
following table provides a detailed
analysis of how the key operational
provisions of the IOP are addressed in
BOEM’s existing regulations, and why
the key safety provisions of the IOP will
continue to be fully addressed by other
provisions within BOEM’s regulations:

TABLE 1—CROSSWALK BETWEEN THE IOP PROVISIONS PROPOSED FOR REMOVAL AND EXISTING EP REGULATIONS AND
REVIEW PRACTICES
IOP provision

Coverage in BOEM’s continuing regulations, operator EPs, and
review practices

§ 550.204(a)—The operator describes how vessels and equipment were designed for Arctic OCS conditions;
§ 550.204(b)—The operator includes a schedule of the exploratory program;
§ 550.204(c)—The operator describes how its plans account for
Arctic OCS conditions;

§ 550.220 (c)(1)—The operator describes how drilling activities account for Arctic OCS conditions.
§ 550.211(a)—The operator includes a schedule and discussion of objectives
for its exploration program.
§ 550.220 (c)(1)—The operator describes how drilling activities account for Arctic OCS conditions.
§ 550.220(c)(2)—The operator describes weather and ice forecasting and management plans.
§ 550.224(a)—The operator describes vessels and aircraft it would use during
exploration, including storage capacity of fuels.
§ 550.202—BOEM must review plans to ensure they are safe and do not
cause undue or serious harm or damage to the human, marine, or coastal
environment.
§ 550.211(a)—The operator includes a schedule and discussion of objectives
for its exploration program.
§ 550.220 (c)(1)—The operator describes how drilling activities account for Arctic OCS conditions.
§ 550.220(c)(2)—The operator describes weather and ice forecasting and management plans.
§ 550.220(c)(6)(ii) (proposed)—The operator would describe the termination of
drilling operations consistent with the well control planning requirements
under § 250.472 of this title.
§ 550.220(c)(2)—The operator describes weather and ice forecasting and management plans.
§ 550.220(b)—The operator would describe critical operations and curtailment
procedures.
§ 550.220 (c)(1)—The operator describes how drilling activities account for Arctic OCS conditions.
§ 550.220(c)(2)—The operator describes weather and ice forecasting and management plans.
§ 550.202—BOEM must review plans to ensure they are safe and do not
cause undue or serious harm or damage to the human, marine, or coastal
environment.
§ 550.211(c)—The operator would describe the drilling unit, associated equipment, safety features, and storage of fuels and oils.
§ 550.220 (c)(1)—The operator describes how drilling activities account for Arctic OCS conditions.

§ 550.204(d)—The operator describes general abandonment
plans for wells;

§ 550.204(e)—The operator describes its plans for responding
and managing ice hazards and weather events;

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§ 550.204(f)—The operator describes work to be performed by
contractors;

§ 550.204(g)—The operator describes how it will ensure operational safety;

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TABLE 1—CROSSWALK BETWEEN THE IOP PROVISIONS PROPOSED FOR REMOVAL AND EXISTING EP REGULATIONS AND
REVIEW PRACTICES—Continued
Coverage in BOEM’s continuing regulations, operator EPs, and
review practices

IOP provision
§ 550.204(h)—The operator describes oil spill response plans;
§ 550.204(i)—The operator describes efforts to minimize impacts to local community infrastructure;
§ 550.204(j)—The operator describes how it could rely on local
communities for parts of its exploratory drilling program.

The following information that was
previously required as part of the IOP
submission, but not included in the EP

requirements, is proposed to be added
to the relevant sections of the EP:

Existing regulation text

New provision

§ 550.204(a)—The operator describes how vessels and equipment were designed for Arctic OCS conditions;

§ 550.220(c)(1)—The operator describes how the exploratory drilling (including
vessels and equipment) would account for Arctic OCS conditions, including
any allowances or limitations its vessels have from a classification society
and/or the USCG.
§ 550.211(b)—the operator describes how it will ensure operational safety.

§ 550.204(g)—The operator describes how it will ensure operational safety;

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§ 550.219 (a) and § 550.219 (b)—The operator would describe its oil spill response plan and associated spill modeling report.
§ 550.216 (c)—the operator must analyze socioeconomic resources associated
with its exploratory program.
§ 550.227 (b)(7)—The operator must describe socioeconomic resources including employment and subsistence resources and harvest practices.
§ 550.220 (c)(5)—The operator describes agreements it has with third parties
in the event of an oil spill or emergency.
§ 550.219 (a) and § 550.219 (b)—The operator would describe its oil spill response plan and associated spill modeling report.
§ 550.227 (b)(7)—The operator must describe socioeconomic resources including employment and subsistence resources and harvest practices.

To the extent that there is not an exact
correlation between the information
required in the IOP and that required in
the EP, BOEM and BSEE believe that the
additional information required in the
IOP that is not in the EP is not necessary
and certainly not necessary in advance
of the EP.
Furthermore, the BOEM Anchorage,
Alaska OCS Office meets with members
of the Interagency Working Group on
Alaska Energy Permitting and other
relevant agencies, before an EP is
submitted or deemed submitted.
Although BOEM previously argued that
the IOP would not delay, but in fact,
speed development by encouraging
earlier review and coordination between
regulatory agencies, BOEM no longer
believes that is the case. While it is true
that the IOP might speed up BOEM’s
review and approval of an EP, by
encouraging earlier review and
coordination among agencies, such
acceleration would not shorten the
overall planning process undertaken by
the operator to prepare and submit an
EP. The operator should conduct the
same degree of planning with or without
an IOP, because such planning is
necessitated by the EP requirements.
The IOP merely shifts some of the
agency review to earlier in the process.
With or without a prescriptive
requirement for an IOP, the operator’s
thorough advance planning and

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coordination between BOEM, the
operator, and other agencies prior to
submission, will result in fewer
unexpected issues overall. In practice,
the entire planning process from initial
concept to actual drilling should be the
same, with or without an IOP. What is
more important in terms of timeline, is
the detailed work the operator would
conduct in preparing and submitting a
well-crafted EP.
How do I submit the EP, DPP, or DOCD?
(§ 550.206)
BOEM proposes to delete all
references to the IOP in this section. The
substantive provisions of this section
that relate to EPs, DPPs, and DOCDs
would remain unchanged.
What must the EP include? (§ 550.211)
BOEM proposes to move existing
§ 550.204(g) to § 550.211 as a new
paragraph (b). All other provisions of
§ 550.211 would remain unchanged.
The addition of the provision from
§ 550.204 into § 550.211 is designed to
describe operational safety procedures
that the operator has developed specific
to conditions relevant on the Arctic
OCS. These requirements were
previously included in the IOP and not
specifically enumerated as part of the
requirements for an EP, although
similar, more general requirements are
already part of paragraphs (a),

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Description, objectives, and schedule,
and (c), Drilling unit of this section.
Paragraph (c) requires the operator to
describe the drilling unit, associated
equipment, safety features, and storage
of fuels and oils.
Without the current IOP provisions,
the applicant would already need to
have the information required by this
paragraph in order to comply with
BSEE’s regulations that currently
require operators to develop,
implement, and maintain a safety and
environmental management system
(SEMS) program (Subpart S, §§ 250.1900
to 250.1933), and as a result, moving
this requirement from §§ 550.204 to
550.211 does not add any burden.
Retaining this important provision as
part of the requirements for exploratory
drilling on the Arctic OCS ensures
consistency with the goals of this
rulemaking and to better align BOEM’s
rules with those of BSEE. The following
is a description of the provision that is
being retained. The section describes
how an operator will ensure operational
safety while working in Arctic OCS
conditions, including but not limited to:
(1) The safety principles that it
intends to apply to itself and its
contractors;
(2) The accountability structure
within its organization for
implementing such principles;

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(3) How it will communicate such
principles to its employees and
contractors; and
(4) How it will determine successful
implementation of such principles.
The text of this transferred regulation
provision is identical to what it was in
§ 550.204(g). As such, this addition to
§ 550.211 will not impose any new
burden on lessees or operators. BOEM
believes that retaining this important
safety and environmental protection is a
necessary part of ensuring that energy
exploration and development activity is
safe and environmentally responsible.
If I propose activities in the Arctic OCS
Region, what planning information must
accompany the EP? (§ 550.220)
BOEM proposes to revise paragraphs
(c)(1) and (4), and (c)(6)(ii) of § 550.220
to conform to BSEE’s proposed changes
to § 250.472, What are the additional
well control equipment or relief rig
requirements for the Arctic OCS?
Existing paragraph (c)(1) of § 550.220
would be revised to add text to account
for the text in existing § 550.204(a),
which would be removed. With the
elimination of § 550.204, BOEM
proposes to combine the requirements
of these two sections into a revised
§ 550.220(c)(1) that would require the
operator to describe how its exploratory
drilling (including vessels and
equipment) would account for Arctic
OCS conditions, including any
allowances or limitations its vessels
have from a classification society and/
or the USCG.
BOEM is proposing to add a new
informational requirement for modified
vessels. BOEM is seeking to confirm that
the operator meets the requirements of
other entities with authority over
vessels, not to impose requirements on
those vessels. Although this revised
paragraph would appear to add new
requirements, in fact this revision
would simply clarify and formalize the
existing arrangements between BOEM
and these other entities. This provision
is proposed in order to avoid any
potential confusion that might
otherwise arise regarding the
incorporation of the existing IOP
requirements into the EP and how they
may relate to the regulations and
jurisdiction of the United States Coast
Guard, or the flag state of the vessel.
According to this proposed revision, for
vessel modifications, the operator
would describe any approvals from the
flag state and vessel classification
society and include in that description
any allowances or limitations placed
upon the vessel by the classification
society and/or USCG. Vessel
modifications may include the

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suitability of vessels for Arctic
conditions. These vessels may have or
acquire classification from a
‘‘recognized organization’’ under the
USCG’s Alternative Compliance
Program (ACP).52 This specification
provides the operator with guidance on
what information the EP should contain
to show that its vessels would be able
to operate safely in the Arctic OCS. The
specification would also show that
BOEM is not duplicating regulations
from USCG by acknowledging that the
flag state, USCG, and/or the
classification society have authority for
approvals, allowances, and limitations
placed upon modified vessels. For these
reasons, this change would impose no
material additional burden on lessee or
operators beyond that which already
exists and which has already been
accounted for in the information
collection burden for this section.
To ensure consistency with BSEE’s
proposed regulatory changes, BOEM is
proposing to revise paragraphs (c)(4)
and (c)(6)(ii) by requiring the operator to
provide a general description of how
they will comply with § 250.472,
including a description of the
termination of their operations. BSEE is
proposing to revise § 250.472 to provide
the operator with the option to either
use an SSID or have access to a relief
rig, as an additional means to secure the
well in the event of a loss of well
control, if the operator will be
conducting exploratory drilling
operations from a MODU.
III. Additional Comments Solicited
To assist BSEE and BOEM in these
revisions, we are requesting public
comments on specific issues discussed
in the preamble. We will consider these
comments while developing final
regulations. To provide necessary
context, we included the requests for
public comments in appropriate
locations throughout the preamble. For
ease of commenting, we consolidated
the requests for comments in this
section of the preamble. While BSEE
and BOEM are soliciting comment on
specific topics associated with the
proposed rule, the bureaus welcome the
public to submit information or
comment on any other topics relevant to
this rulemaking that may not necessarily
pertain to the bureaus’ specific
solicitation. At this stage, the bureaus
are open to considering any option that
would improve the regulatory changes
proposed, including maintaining the
original requirement as part of the final
rule. In all cases, please provide
52 33 U.S.C. 3316 and 46 CFR part 8 implement
the USCG’s ACP.

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supporting reasons and data for your
responses.
(i) Well Design When Using an SSID
(§ 250.472(a))—BSEE is seeking
comments on how well design could be
better addressed in this rulemaking to
enhance the overall safety of operations
on the Arctic OCS. More specifically,
BSEE would like to know whether the
well design requirement in proposed
§ 250.472(a) is adequate to address
situations the operator may encounter if
a well is shut-in with an SSID over an
entire winter season (e.g., six to nine
months). These situations could include
cases where the wellbore pressure
profile may increase to reservoir
pressures at the top of the well over the
course of the winter season. BSEE
would also like to know whether there
are other scenarios that may occur in a
shut-in well over the ice season.
(ii) SSID Efficacy Relative to the Relief
Rig and SSRW—BSEE is proposing to
revise the relief rig and SSRW
requirement with the intent to minimize
environmental damage due to a
prolonged ongoing well control event.
When drilling a relief well, there is a
delay in stopping the uncontrolled flow
of oil and other fluid into the marine
environment while relief well drilling
operations are taking place. When
properly functioning as designed, there
is usually no delay for operational use
of an SSID compared to the process of
utilizing the relief rig or capping stack.
If the SSID does not initially function,
the SSID may still be activated through
the ROV intervention equipment and
capabilities that BSEE is proposing as a
SSID design requirement. The SSID
would operate independently from the
BOP. By having two independent,
redundant components, as part of the
well control system, the overall
reliability and effectiveness of the entire
system increases. BSEE would like to
know of any cases or data, in addition
to what we have already discussed in
the preamble, regarding the performance
and reliability of the SSID and its
effectiveness compared to drilling a
relief well.
(iii) NPC Report and Bratslavsky and
SolstenXP Study—The NPC 2019 Report
and the Bratslavsky and SolstenXP
study have been valuable tools that were
not available when promulgating the
2016 Arctic Exploratory Drilling Rule.
BSEE requests the public to provide
additional information or clarification
related to those portions of these reports
that the Bureau relied upon in this
rulemaking.
(iv) SSID Capability to Preserve
Isolation Over the Winter Season
(§ 250.472(a)(1)(iv))—BSEE proposes to
require that the SSID must be capable of

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preserving isolation through the winter
season without solely relying on the
elastomer elements of the rams (e.g., by
using a well cap) and allow re-entry
during the following open-water season.
BSEE understands that the operator is
able to achieve long-term isolation by
installing a well cap (i.e., a metal-tometal cap) on the SSID before leaving
the device on the seafloor over the
winter season. BSEE would like to know
if there are means by which isolation
would be preserved through the winter
season in cases where a late-season
emergency situation may not provide
adequate time or ability to access the
SSID to install a well cap.
(v) SSID Dual Shear Requirement in
Proposed § 250.472(a)(2)(i)—The NPC
2019 Report describes the SSID used in
the Kara Sea Project as having dual
blind shear rams. BSEE does not
propose requiring the SSID to be
equipped with dual blind shear rams.
However, BSEE is seeking comment on
the advantages or disadvantages
between dual blind shear rams and
using dual shear rams, with ram locks,
with one ram being a blind shear ram.
(vi) SSID Redundant Control System
Capabilities (§ 250.472(a)(2)(ii))—BSEE
proposes to require the SSID to use a
redundant control system that includes
ROV capabilities and a control station
on the rig that is independent from the
BOP control system. BSEE is
contemplating whether it may be more
appropriate to require the SSID’s
redundant control system capabilities to
be separate from its ROV’s capabilities,
and to be consistent with the fully
redundant control system requirements
described in API Spec. 16D,
Specification for Control Systems for
Drilling Well Control Equipment and
Control Systems for Diverter Equipment,
Second Edition, July 2004, reaffirmed
August 2013; incorporated by reference
at § 250.198(e)(90); (e.g., yellow pod and
blue pod). In addition to meeting the
ROV requirements in existing
§ 250.734(a)(5), BSEE is also considering
whether there should be an additional
manual method (separate from the
redundant control system) to close the
SSID’s rams with the ROV and whether
it may be appropriate to require a
standby or tending vessel with an ROV.
There could be cases where the SSID’s
control system on the drilling rig is not
available (e.g., due to failure or an
evacuation of the rig).
(vii) SSID Testing Requirements
(§ 250.472(a)(5))—BSEE is seeking
comment on whether it is appropriate to
align the SSID’s proposed testing
requirements with BSEE’s existing BOP
testing requirements in § 250.737, What
are the BOP system testing

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requirements?, or whether there are
more appropriate and reliable testing
methods for SSIDs. BSEE would like to
receive information on what testing
procedures have been used in the past
to test an SSID when it was deployed,
or what testing procedures are being
developed for future projects.
(viii) Relief Rig Staging and Capping
Stack Positioning Requirements—BSEE
proposes to revise the staging and
positioning requirement for the relief rig
and capping stack, respectively, by
providing an opportunity to the operator
to adjust the point in time during its
operations when it must stage or
position these pieces of equipment,
from ‘‘when drilling below or working
below the surface casing’’ to ‘‘when
drilling below or working below the last
casing point prior to penetrating a zone
capable of flowing hydrocarbons in
measurable quantities.’’ If the operator
is able to demonstrate to BSEE that the
operations it plans to conduct below the
surface casing would not encounter any
abnormally high-pressured or other
geologic hazards before reaching the last
casing point prior to penetrating a zone
capable of flowing hydrocarbons in
measurable quantities, then BSEE would
allow the operator to delay staging of its
relief rig or positioning of its SCCE until
reaching that point. BSEE would like to
know whether there are more
appropriate criteria, other than
‘‘abnormally high-pressured zones or
other geologic hazards,’’ that should be
used to determine whether to allow the
operator to delay positioning of the
capping stack and relief rig. BSEE is also
requesting comment on what types of
information, other than what is listed in
proposed § 250.471(a) and § 250.472
(b)—risk modeling data, off-set well
data, analog data, and seismic data,
could be used to demonstrate the
absence of abnormally pressured zones
or other geologic hazards, and how
burden on the operator could change—
increase or decrease—if BSEE were to
require submission of that information
in its APD.
(ix) Alternative Regulatory Approach
to the Relief Rig and Capping Stack
Positioning Requirements—BSEE is
considering an alternative regulatory
approach in which BSEE would revise
the staging and positioning requirement
for the relief rig and capping stack,
respectively, by adjusting the point in
time during its operations when it must
stage or position these pieces of
equipment, from ‘‘when drilling below
or working below the surface casing’’ to
‘‘when drilling below or working below
the last casing point prior to penetrating
a zone capable of flowing hydrocarbons
in measurable quantities.’’ However,

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there could be cases where the operator
or BSEE may not have sufficient G&G or
analogous well data on a proposed
project to confidently identify the
location of the first formation that the
operator may encounter that is capable
of flowing hydrocarbons in measurable
quantities. BSEE is soliciting the
public’s comments about this regulatory
approach. BSEE is also soliciting
comment about the need for the
operator to verify, on a case-by-case
basis, zones not capable of flowing
hydrocarbons in measurable quantities.
(x) Installing and Operating an SSID
in a Mudline Cellar—BSEE is requesting
more information about whether there
are any operational or installation
challenges the operator may encounter
in attempting to operate the SSID when
it is installed in a mudline cellar. In
areas of ice scour, BSEE’s current
regulations at §§ 250.734(a)(13) and
250.738(h) require placement of subsea
BOP systems in mudline cellars. In
addition, proposed § 250.720(c)(2)
requires placement of the wellhead in a
mudline cellar in areas of ice scour.
Proposed § 250.472(a)(4)(i) would
require installation of the SSID below
the BOP.
(xi) Operating an SSID with a Subsea
BOP Installed on the Seafloor—
Historically, drilling in the Beaufort Sea
and the Chukchi Sea has occurred in
waters less than 167 feet deep, and as
recent as April 2020,53 there were active
leases in the Beaufort Sea where an
SSID could have been deployed. If the
operator installs all well control systems
on the seafloor (subsea BOP systems and
SSIDs), there could be as much as 128
feet of water column taken up by these
systems and a ship’s hull (if a drillship
is used). BSEE would like to know what
challenges operators could face in cases
where there is little room to operate.
BSEE would also like to know how
operators addressed those challenges in
the past, or how such challenges could
be addressed in future operations.
(xii) Fail-Safe Mechanisms Used on
an SSID—BSEE is seeking comment on
what fail-safe mechanisms exist that
could be applied to an SSID in cases
where a subsea BOP system is used.
BSEE is contemplating whether it may
be necessary to require mechanisms,
such as autoshear or deadman for the
SSID, to address emergency situations,
such as a sunken MODU, where the
53 In April of 2020, the only leases with potential
projects that would be subject to the Arctic OCS’s
SSID requirements were relinquished. However,
there are other active leases in the Beaufort Sea
located nearer to shore in shallower waters where
exploration and development projects are actively
being pursued (primarily through man-made gravel
islands).

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subsea BOP system may have failed and
the SSID could no longer be functioned
via the rig or ROV (due to lack of
access). BSEE currently has fail-safe
requirements for subsea BOP systems
(autoshear and deadman systems),
which could be applied to SSIDs.
However, there could be unintended
consequences from applying these failsafe systems on an SSID when a subsea
BOP system is used. BSEE is seeking
comment on what fail-safe mechanisms
could be deployed to address cases
where the BOP fails and the SSID is
inaccessible by an ROV or a MODU
control station. If an autoshear system or
a deadman system are appropriate failsafe mechanisms, BSEE is seeking input
on what criteria should be used to
function these systems, to ensure they
do not function at the wrong time or
interfere with or impact the subsea
BOP’s autoshear and deadman systems.
(xiii) Autoshear and Deadman System
Requirements for Surface BOPs—BSEE
is contemplating establishing autoshear
and deadman system requirements in
cases where operators use a surface
BOP. BSEE does not currently require
the use of an autoshear or deadman
system with surface BOPs. BSEE is
seeking comment on what criteria
should be established to function the
autoshear or deadman systems in
connection with a surface BOP. BSEE
welcomes any other comments,
unrelated to autoshear or deadman
systems, which require additional
consideration in those cases where a
surface BOP is used.
(xiv) Outcome-based Well Control
System Requirements—BSEE is seeking
comment on other appropriate
approaches to well-control operations in
the Arctic. The NPC 2019 Report
recommends accepting the use of an
SSID in place of the requirement for
SSRW capability. However, it also
recommends replacing the relief rig and
SSRW requirements with requirements
that specify desired outcomes (i.e., to
stop the flow of a well and allow the
operator to propose equivalent
technology and demonstrate its
capabilities). BSEE assumes that the
NPC recommendation would entail a
performance-based approach to the
regulations, in which the operator could
propose and demonstrate new
technologies to meet a stated objective,
rather than being required to use certain
technologies, such as a relief rig.
(xv) Suspension of Operations—BSEE
is considering the option of limiting the
period during which a suspension
would remain in effect to the period
between one drilling season and the
next when the operator is prevented
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leaseholding activities due to seasonal
conditions. BSEE is seeking comment
on this regulatory option for the new
SOO provision it is proposing in a new
paragraph (d) of § 250.175, or any other
option that could avoid or minimize the
additional burdens associated with
making requests on an annual basis (if
the duration of the suspension needs to
be longer), but still assure diligent lease
exploration and development.
(xvi) Other Solicited Comments—
BSEE is also requesting comments on
the specific costs and operational
implications of each of the regulatory
changes included in this proposed rule.
IV. Procedural Matters
A. Regulatory Planning and Review
(Executive Orders (E.O.) 12866, 13563,
and 13771)
Executive Order 12866 provides that
the Office of Information and Regulatory
Affairs (OIRA) within OMB will review
all significant rules. This proposed
action is an economically significant
regulatory action that was submitted to
OMB for review, as it would have an
annual effect on the economy of $100
million or more. BSEE and BOEM
developed an economic analysis to
assess the anticipated costs and
potential benefits of the proposed rule.
Due to uncertainty surrounding the
outcome of ongoing litigation regarding
the availability of Arctic OCS planning
areas for future leasing and energy
development, BSEE and BOEM
developed two baseline activity level
forecasts: (1) Activity levels expected if
the full Beaufort and Chukchi Sea
planning areas are reopened (i.e., the
Full Arctic baseline), and (2) reduced
activity levels if these areas remain
withdrawn from leasing (i.e., the
Restricted Beaufort baseline). Under
either scenario, the proposed action
would be economically significant as a
result of the estimated cost savings of
this proposed rule. BSEE and BOEM
estimate the amendments proposed in
this rulemaking would provide
annualized net benefits of $142 million
under the Full Arctic baseline, or $121
million under the Restricted Beaufort
baseline, discounted at 7 percent.
Details on the estimated cost savings
of this proposed rule can be found in
the rule’s Initial Regulatory Impact
Analysis (IRIA). The net quantified
benefits for this proposed rule are based
on cost savings less forgone benefits.
The cost savings to both government
and industry result from removing
regulatory redundancies, reduction in
paperwork burdens, provision for
alternative methods of compliance, and
adoption of improved industry

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technology. Forgone benefits result from
slight increases in the risks to
subsistence hunters and fishermen and
wildlife stemming from an increased
probability of small or catastrophic oil
spills. The cost savings exceed the
forgone benefits, leading to the net
benefits summarized in the following
paragraphs.
This proposed rule would revise
regulatory provisions in 30 CFR part
250, subparts A, C, D, and G, and 30
CFR part 550, subpart B. BSEE and
BOEM have reassessed a number of the
provisions promulgated through the
2016 Arctic Exploratory Drilling Rule
and are proposing to revise some
provisions to reflect performance-based
standards rather than prescriptive
requirements. Other revisions remove
redundant regulatory oversight
provisions and provide regional
flexibility in the administration of
suspensions and associated lease term
extensions, without significantly
impacting the current levels of safety
and environmental protection. The
bureaus sought the best available data
and information to analyze the
economic impact of these changes. The
IRIA for this rulemaking can be found
in the https://www.regulations.gov/
docket (Docket ID: BSEE–2019–0008).
BSEE and BOEM are proposing to
revise certain regulations promulgated
through the 2016 Arctic Exploratory
Drilling Rule based on new information
generated since the 2016 rule was
finalized, and to support the goals of the
Administration’s regulatory reform
initiatives, while ensuring safety and
environmental protection. This
proposed rule would revise certain
existing regulations—§§ 250.105;
250.175; 250.198; 250.300(b);
250.470(b), (f), and (h); 250.471(a) and
(b); 250.472(a), (b), and (c); 250.720(c);
550.200; 550.204; 550.206; 550.211; and
550.220(c). The bulk of the net benefits
are derived from cost savings driven by
a proposed revision to existing
§ 250.472(b) and (c), which is discussed
below. The analysis suggests forgone
benefits are small compared to the cost
savings, and the primary forgone
benefits are from possible impacts on
the environment and subsistence
hunting and whaling communities, that
could be caused by an oil spill of greater
duration and higher discharge volumes
in the event the BOP, SSID, and capping
stack were to fail in sequence, and a
containment dome and flow system
would be needed to capture oil flowing
from the well while relief-well drilling
operations are underway. These, and the
other provisions, are discussed in
greater detail within the IRIA.

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The largest contributor to net benefits
attributable to the proposed rule is the
proposed revision to existing § 250.472
paragraphs (a), (b), and (c). As
promulgated under the 2016 Arctic
Exploratory Drilling Rule, this provision
currently requires the use of a ‘relief rig’
and adoption of a 45-day shoulder
season. The relief rig is a secondary
drilling vessel that is available and
capable of drilling an SSRW in the event
of a loss of well control. The 45-day
‘‘shoulder season’’ was the maximum
time permitted by the regulations to
mobilize the relief rig to an incident,
drill a relief well, kill and abandon the
original well, and abandon the relief
well prior to expected seasonal ice
encroachment at the drill site. This
shoulder season necessarily compresses
the already short Arctic drilling
timeframe and also limits the ability of
operators to drill and complete a well in
one season. The proposed revisions to
§ 250.472 would provide the operator
with the option to either use an SSID or
have access to a relief rig, as an
additional means to secure the well in
the event of a loss of well control, if the
operator will be conducting exploratory
drilling operations from a MODU. The
two features of this flexibility driving
the cost savings are the removal of the
shoulder season and removal of the
requirement for the secondary drilling
vessel, if the operator elects to install an
SSID to comply with § 250.472. Because
of the relative cost effectiveness of
procuring, and potential well control
advantages of installing an SSID versus
mobilizing a relief rig and the necessary
support vessels and personnel, BSEE

assumes operators will prefer this
option when using MODUs. This
proposed change would produce an
annualized cost savings of $142 million
under the Full Arctic baseline, or $121
million under the Restricted Beaufort
baseline, discounted at 7%.
This proposed rule would reduce the
burden imposed on industry, while
maintaining safety and environmental
protection. The forgone benefits of
adopting the proposed rule include
possible impacts on the environment,
subsistence hunting and whaling
communities, and an oil spill of greater
duration with higher discharge volumes
in the event a BOP and SSID were to
fail. As discussed earlier in the
preamble, BSEE proposes to require
operators to operate an SSID
independently from the BOP. By having
two independent, redundant
components (i.e., the BOP and the SSID)
as part of the well control system, the
overall reliability and effectiveness of
the entire system increases. In the event
both devices were to fail, the capping
stack would still be used as required in
the permitted timeframe. When a
capping stack is used to contain a well,
the relief well can be drilled without an
ongoing active spill event. If the capping
stack were to fail, the containment dome
and flow system would be used to
capture the oil flowing from the well
while relief-well drilling operations are
underway.
Given that the proposed rule would
remove the arrival timing requirement
for these pieces of equipment, there may
be a delay in their arrival, in
comparison to the existing regulations.
The amount of oil flowing from the well

during that delayed period, would be
the contributing factor to the proposed
rule’s forgone benefits. However, as
discussed in the IRIA, the probability of
a catastrophic spill event (as a result of
the BOP and SSID systems experiencing
total failures) is low. Coupled with a
scenario in which a BOP, SSID, and
capping stack were all to fail, the
probability of realizing these forgone
benefits may be even lower.
Nonetheless, the possibility exists and if
the BOP were to fail and the SSID were
to function as designed, there would be
no forgone benefits in comparison to the
existing regulations (and there might be
a gained benefit since the SSID would
activate immediately).
As part of the final rule, BSEE and
BOEM are contemplating the
preparation of a sensitivity analysis for
the Final RIA and are soliciting
comments on ways to make the analysis
as accurate as possible. The information
we receive through public input on this
proposed rule regarding the SSID’s
performance, reliability, and
effectiveness may inform the
preparation of a sensitivity analysis.
The timeframe of the present analysis
is 24 years, composed of an initial 4
years with no activity followed by 20
years of activities beginning in 2024.
The two tables below summarize BSEE’s
and BOEM’s estimates of the total and
annual net benefits derived from all
proposed revisions and additions.
Additional information on the time
horizon, compliance costs, savings,
benefits, and forgone benefits may be
found in the IRIA published in the rule
docket.

20-YEAR ESTIMATED ANNUALIZED NET BENEFITS ASSOCIATED WITH PROPOSED AMENDMENTS TO 30 CFR PART 250
SUBPARTS A, C, D, AND G, AND 30 CFR PART 550, SUBPART B UNDER FULL-ARCTIC BASELINE ASSUMPTIONS
Year (2024–2043)
Annualized (millions) ................................................................................................................................................

Discounted to
2019 at 3%

Discounted to
2019 at 7%

$149.8

$142.2

20-YEAR ESTIMATED ANNUALIZED NET BENEFITS ASSOCIATED WITH PROPOSED AMENDMENTS TO 30 CFR PART 250
SUBPARTS A, C, D, AND G, AND 30 CFR PART 550, SUBPART B UNDER RESTRICTED BEAUFORT BASELINE ASSUMPTIONS
Year (2024–2043)

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Annualized (millions) ................................................................................................................................................

This proposed rule would revise
multiple provisions in the current
regulations to implement performancebased provisions based upon reasonably
obtainable information on safety,
technical, economic, and other issues.
Redundant or unnecessary reporting
requirements are also being eliminated.

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BSEE and BOEM are providing industry
flexibility, when practical, to meet the
safety or equipment standards, rather
than specifying the compliance method.
Based on a consideration of the
qualitative and quantitative safety and
environmental factors related to the
rule, BSEE and BOEM determined that

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Discounted to
2019 at 3%

Discounted to
2019 at 7%

$126.0

$120.9

the proposed revisions would be
consistent with the policies of the
applicable E.O.s and the OCSLA.
Executive Order 13563 reaffirms the
principles of E.O. 12866 while calling
for improvements in the Nation’s
regulatory system to promote
predictability, to reduce uncertainty,

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and to use the best, most innovative,
and least burdensome tools for
achieving regulatory ends. The E.O.
directs agencies to consider regulatory
approaches that reduce burdens and
maintain flexibility and freedom of
choice for the public where these
approaches are relevant, feasible, and
consistent with regulatory objectives.
E.O. 13563 emphasizes that regulations
must be based on the best available
science and that the rulemaking process
must allow for public participation and
an open exchange of ideas. Furthermore,
it promotes retrospective review of
existing regulations that may be
outmoded, ineffective, insufficient, or
excessively burdensome. BSEE and
BOEM have reviewed the existing
regulations as amended by the 2016
Rule and have developed this proposed
rule in a manner consistent with E.O.
13563.
Executive Order 13771 requires
Federal agencies to take proactive
measures to reduce the costs associated
with complying with Federal
regulations. This proposed rule is an
E.O. 13771 deregulatory action.
B. Regulatory Flexibility Act and Small
Business Regulatory Enforcement
Fairness Act
The Regulatory Flexibility Act (RFA),
5 U.S.C. 601–612, requires agencies to
analyze the economic impact of
regulations when there is likely to be a
significant economic impact on a
substantial number of small entities and
to consider regulatory alternatives that
will achieve the agency’s goals while
minimizing the burden on small
entities. The proposed rule would affect
operators and Federal oil and gas lessees
that could conduct exploratory drilling
on the Arctic OCS. The RFA defines
small entities as small businesses, small
nonprofits, and small governmental
jurisdictions. No small nonprofits or
small governmental jurisdictions have
been identified that would be impacted
by this rule.
Businesses subject to this proposed
rule fall under North American Industry
Classification System (NAICS) codes
211111 (Crude Petroleum and Natural
Gas Extraction) and 213111 (Drilling Oil
and Gas Wells). For these
classifications, a small business is
defined as one with fewer than 1,250
employees (NAICS code 211111) and
fewer than 1,000 employees (NAICS
code 213111), respectively. A small
entity is one that is ‘‘independently
owned and operated and which is not
dominant in its field of operation.’’
According to BOEM’s list of Arctic
OCS leaseholders, four businesses
currently hold lease interests on the

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Arctic OCS. This proposed rule would
directly affect all four Arctic lessees.
Based on the small entity criterion, none
of the four businesses are considered a
small entity. No small companies hold
leases on the Arctic OCS. Previously, a
single small company with only one
lease held acreage on the Arctic OCS.
This company relinquished its lease in
March 2016.
BSEE and BOEM prepared an Initial
Regulatory Flexibility Analysis (IRFA),
which can be found in Section VII of the
IRIA. Given the challenging
environment and associated costs of
drilling in the Arctic OCS planning
areas, no small entities are expected to
operate in these areas for the foreseeable
future. Therefore, BSEE and BOEM
preliminarily conclude that no small
entities would be affected by these
proposed amendments, however the
agency has prepared an IRFA and is
seeking public comment on any small
business impacts from the proposed
amendments.
This proposed rule would meet the
E.O. 12866 criteria for an economically
significant rule because it would likely
have an annual effect on the economy
of $100 million or more in at least one
year of the 20-year period analyzed, and
BSEE/BOEM comply with the RFA and
the Small Business Regulatory
Enforcement Fairness Act by providing
a regulatory flexibility analysis. The
requirements would apply to all entities
operating on the Arctic OCS regardless
of company designation as a small
business. For more information on the
small business impacts, see the IRFA
section in the IRIA. Small businesses
may send comments on the actions of
Federal employees who enforce, or
otherwise determine compliance with,
Federal regulations to the Small
Business and Agriculture Regulatory
Enforcement Ombudsman, and to the
Regional Small Business Regulatory
Fairness Board. The Ombudsman
evaluates these actions annually and
rates each agency’s responsiveness to
small business. If you wish to comment
on actions by employees of BSEE or
BOEM, call 1–888–REG–FAIR (1–888–
734–3247).
C. Unfunded Mandates Reform Act of
1995 (UMRA)
This proposed rule would not impose
an unfunded Federal mandate on State,
local, or tribal governments and would
not have a significant or unique effect
on State, local, or tribal governments.
The requirements in this proposed rule
would apply to Arctic OCS oil and gas
lessees and operators, not to State, local,
and tribal governments. Thus, the
proposed rule would not have

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disproportionate budgetary effects on
these governments. BSEE and BOEM
have determined the proposed changes
in this rulemaking would result in cost
savings annually to regulated entities.
Therefore, a written statement under the
Unfunded Mandates Reform Act (2
U.S.C. 1531 et seq.) is not required.
D. Takings Implication Assessment
Under the criteria in E.O. 12630, this
proposed rule would not have
significant takings implications. The
proposed rule is not a governmental
action capable of interference with
constitutionally protected property
rights. A Takings Implication
Assessment is not required.
E. Federalism (E.O. 13132)
Under the criteria in E.O. 13132, this
proposed rule would not have
federalism implications. This proposed
rule would 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 proposed rule would not
affect that role. A Federalism
Assessment is not required.
F. Civil Justice Reform (E.O. 12988)
This proposed rule complies with the
requirements of E.O. 12988.
Specifically, this rule:
1. Meets the criteria of section 3(a)
requiring that all regulations be
reviewed to eliminate errors and
ambiguity and be written to minimize
litigation; and
2. Meets the criteria of section 3(b)(2)
requiring that all regulations be written
in clear language and contain clear legal
standards.
G. Consultation With Indian Tribes (E.O.
13175)
Under the criteria in E.O. 13175,
Consultation and Coordination with
Indian Tribal Governments (dated
November 6, 2000), DOI’s Policy on
Consultation with Indian Tribes and
Alaska Native Corporations (512
Departmental Manual 4, dated
November 9, 2015), and DOI’s
Procedures for Consultation with Indian
Tribes (512 Departmental Manual 5,
dated November 9, 2015), we evaluated
the subject matter of this rulemaking
and determined that it would have tribal
implications for Alaska Natives. As
described earlier, future Arctic OCS
exploratory drilling activities conducted
pursuant to this proposed rule could
affect Alaska Natives, particularly their
ability to engage in subsistence and
cultural activities. However, as
discussed earlier in Section I.

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Background, Subsection E. Partner
Engagement in Preparation for This
Proposed Rule, Item 2. Summary of
Comments Received, BOEM’s
environmental studies program has
provided nearly $500 million over the
last 46 years to scientific research on the
Alaska OCS, which includes the Arctic
OCS. Since July 2016, BOEM has
completed 35 environmental studies
and has 23 ongoing studies that cover
the Arctic, totaling nearly $72 million.
While this proposed rule would change
how operators could explore for OCS
resources in the Arctic, there are ample
opportunities to permit these activities
consistent with ESA, MMPA, NEPA,
and consultation with Alaska Native
communities. BOEM’s environmental
studies program provides the
information that is used to evaluate the
potential environmental effects of
leasing OCS lands for exploration and
development and helps ensure BOEM
and BSEE have the best science
available for the public, industry, and
federal permitting decisions.

In addition, Alaska Natives may also
be beneficiaries of the proposed rule, to
the extent they are partners in any
exploratory activities. There are
additional unquantified benefits in
situations where a SSID is available to
immediately shut-in a flowing well
rather than waiting for a relief well to
be drilled.
BSEE and BOEM are committed to
regular and meaningful consultation
and collaboration with Alaska Native
Tribes and ANCSA Corporations on
policy decisions that have tribal
implications, including, as an initial
step, through complete and consistent
implementation of E.O. 13175, together
with related orders, directives, and
guidance. Therefore, BSEE and BOEM
engaged in Government-to-Government
tribal consultations, Government-toANCSA Corporations consultations, and
meetings with municipal leaders (i.e.,
mayors or their respective
representatives), to discuss the subject
matter of the proposed rule and solicit
input in the development of the
proposed rule.

Tribal entity name

Type of entity

Meeting date

Native Village of Utqiagvik ...............................
Native Village of Wainwright ............................
Olgoonik Native Corporation ............................
Doyon Limited ..................................................
Arctic Slope Regional Corporation ...................
Native Village of Kotzebue ...............................
Northwest Arctic Borough Mayor .....................
Native Village of Point Hope ............................
Tikigaq Native Corporation ...............................
Point Hope Mayor ............................................
Alaska Eskimo Whaling Commission ...............
Cully Corporation ..............................................
North Slope Borough Mayor ............................
City of Utqiagvik Mayor ....................................
Native Village of Nuiqsut ..................................
Kuukpik Corporation .........................................
Nuiqsut Mayor ..................................................
Inupiat Community of the Arctic Slope ............
Native Village of Kaktovik ................................
Kaktovik Inupiat Corporation ............................
Kaktovik Mayor .................................................
Tanana Chiefs Conference ..............................
Native Village of Point Lay ...............................

Tribal Government ..........................................
Tribal Government.
Native Corporation.
Native Corporation.
Native Corporation ..........................................
Tribal Government ..........................................
Municipal Government.
Tribal Government ..........................................
Native Corporation.
Municipal Government.
Non-tribe that consults on tribe’s behalf .........
Native Corporation ..........................................
Municipal Government ....................................
Municipal Government.
Tribal Government ..........................................
Native Corporation.
Municipal Government.
Non-tribe that consults on tribe’s behalf.
Tribal Government ..........................................
Native Corporation.
Municipal Government.
Tribal Government ..........................................
Tribal Government ..........................................

November 29, 2018 ...

Anchorage.

December 7, 2018.
December 10, 2018 ...

Kotzebue.

December 11, 2018 ...

Point Hope.

December 13, 2018 ...
December 14, 2018.
December 17, 2018 ...

Anchorage.
Utqiagvik.

December 18, 2018 ...

Nuiqsut.

December 19, 2018 ...

Kaktovik.

December 20, 2018 ...
January 30, 2019 .......

Fairbanks.
Conference Call.

Kikiktagruk Corporation ....................................

Native Corporation ..........................................

NANA Regional Corporation ............................

Native Corporation.

All Alaska Native input provided
during the meetings was subsequently
provided to DOI in writing and has been
included in the administrative record
for this proposed rule.
As previously discussed in part E of
the background section in this
preamble, BSEE and BOEM heard a
variety of perspectives during their
meetings with Alaska Natives. The most

common comment received was a
concern over food security. Subsistence
resources, including bowhead and
beluga whales, other marine mammals,
fish, and birds, are a key food source for
many people’s diets in the native
villages. Another common comment
recommended inclusion of a
requirement for an oil and gas operator
to establish an agreement with those

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On September 20, 2018, BSEE and
BOEM began reaching out to leaders
from Alaska Native Tribes, ANCSA
Corporations, and municipalities to
determine which partners were
interested in having conversations with
BSEE and BOEM about the rulemaking.
Consultations entailed meetings in
Alaska, at locations and times
convenient to the Alaska Native
communities and corporations, to
ensure they can have proper
representation during the meetings.
Accordingly, the timing of these
meetings was critical. BSEE and BOEM
scheduled the meetings around
important traditional subsistence and
cultural activities, such as whaling, that
take place during specific times of the
year, particularly in the early fall.
Between November 29, 2018 and
January 30, 2019, BSEE and BOEM met
with a majority of the tribal entities (23
of 25) originally invited to consult. The
following table lists all 25 invited tribal
entities, and the dates and locations of
the meetings with the 23 entities.
Location

BSEE and BOEM made multiple attempts to
contact these corporations. However, the bureaus did not receive a response from either
organization.

whaling communities potentially
affected by a planned drilling project.
Certain tribal representatives and most
ANCSA corporations were supportive of
this proposed rulemaking because it
could help attract more economic
opportunities to their villages. Other
comments provided during the
consultation meetings included a
recommendation to provide broader

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outreach by presenting this rulemaking
to the tribal assemblies and to citizens
within the communities. One of the
ANCSA corporations also recommended
that this rulemaking take into account
the NPC 2019 Report. Please refer to the
discussions above in Part E (Partner
Engagement in Preparation for This
Proposed Rule) of the background
section of this preamble for a
description of how BSEE and BOEM are
addressing this input during the
rulemaking process. BSEE and BOEM
intend to continue consultation with
affected tribes and ANCSA Corporations
following publication of this proposed
rule.
H. Effects on Environmental Justice for
Minority and Low-Income Populations
(E.O. 12898)
E.O. 12898 requires Federal agencies
to make achieving environmental justice
part of their mission by identifying and
addressing disproportionately high and
adverse human health or environmental
effects of their programs, policies, and
activities on minority and low-income
populations. DOI has determined that
this proposed rule would not have a
disproportionately high or adverse

the following OMB control numbers to
the current ICs:
• 1014–0025 (BSEE), 30 CFR part 250,
Applications for Permit to Drill (APD
and revised APD) (expires 06/30/2023),
and in accordance with 5 CFR 1320.10,
an agency may continue to conduct or
sponsor this collection of information
while the renewal submission is
pending at OMB.
• 1010–0151 (BOEM), 30 CFR part
550, subpart B Plans and Information
(exp. 06/30/2021), and in accordance
with 5 CFR 1320.10, an agency may
continue to conduct or sponsor this
collection of information while the
renewal submission is pending at OMB.
The IC aspects affecting each bureau
are discussed separately. Additionally,
BOEM is seeking to renew these
information collections for three years
with this rulemaking. Instructions on
how to comment follow those
discussions.
The following table details proposed
changes to the annual estimated hour
burdens and non-hour costs; as well as
associated wage cost changes for both
BSEE and BOEM information
submission activities described below:

human health or environmental effect
on native, minority, or low-income
communities because its provisions are
designed to maintain environmental
protection and minimize any impact of
exploration drilling on subsistence
activities and Alaska Native community
resources and infrastructure.
I. Paperwork Reduction Act (PRA)
This proposed rule contains existing
and new information collection (IC)
requirements for both BSEE and BOEM
regulations, and a submission to OMB
for review under the Paperwork
Reduction Act of 1995 (44 U.S.C. 3501
et seq.) is required. Therefore, each
bureau will submit an IC request to
OMB for review and approval. We 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.
OMB has previously reviewed and
approved the existing information
collection requirements associated with
Outer Continental Shelf drilling
permits, plans, and related information
collection, which would be altered by
this proposed rule. OMB has assigned

BSEE
Existing regulations
Requirement

Number of
responses

Submit signed SSID and Well Design
certification § 250.470(h) ................
Submit request to delay access to
your SCCE—§ 250.471(a) and
§ 250.472(b) ....................................

Proposed rule

Number of
burden hours

Number of
responses

Total changes

Number of
burden hours

Change of
responses

Change of
burden hours

Changes in
wage cost

0

0

2

6

+2

+6

+$848

0

0

2

2

+2

+2

+$286

There are no changes to non-hour
costs for BSEE requirements.

BOEM
Existing regulations
Requirement

Number of
responses

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Submit IOP, including all required information § 550.204 ........................
Submit required Arctic-specific information with EP § 550.220 ..............

There are no changes to non-hour
costs for BOEM requirements.
BSEE Information Collection—30 CFR
Part 250
The proposed regulations would
establish new and/or revise current
requirements and the submission of
information for safe and

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Proposed rule

Number of
burden hours

Number of
responses

Total changes

Number of
burden hours

Change of
responses

Change of
burden hours

Changes in
wage cost

1

2,880

0

0

(1)

(2,880)

($316,800)

1

350

1

400

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

+50

+5,500

environmentally responsible Arctic OCS
oil and gas exploration in an APD. BSEE
would use the information in our efforts
to protect life and the environment,
conserve natural resources, and prevent
waste.
The following provides a breakdown
of the paperwork and non-hour cost
burdens for this proposed rule. For the

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current requirements retained in the
proposed rule, we used OMB’s
approved estimated hour and non-hour
cost burdens.
As discussed in the Preamble Sectionby-Section above, and in the supporting
statement available at RegInfo.gov, this
proposed rule would modify language
in §§ 250.175(d), 250.300(b),

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250.470(f)(3), and 250.720(c)(2);
however, there would be no change in
hour burden or non-hour costs
associated with these revisions.
In § 250.470(h), we would add a
requirement to submit with an APD a
certification signed by a registered
professional engineer that your SSID
and well design (including casing and
cementing program) meet the design
requirements in § 250.472 (+ 2
responses and 6 hours for PE
Certification).
In §§ 250.471(a) and 250.472(b), we
would add a requirement for operators
to submit, with an APD, documentation
demonstrating that having access to
SCCE and the relief rig can be safely
delayed until the last casing point prior
to penetrating a zone capable of flowing
hydrocarbons in measurable quantities.
BSEE will grant this approval if the
operator adequately demonstrates to the
Bureau that it will not encounter any
abnormally high-pressured zones or

other geological hazards before that
casing point (+ 2 responses and 2 hours
per request).
Because not all APDs submitted to
BSEE would involve Arctic OCS
exploration drilling, we are separating
the Arctic-specific requirements and
burdens from the national APD
requirements. The burden table below
outlines the revised requirements and
burdens associated with this proposed
rulemaking.
Title of Collection: Revisions to the
Requirements for Exploratory Drilling
on the Arctic Outer Continental Shelf—
Application for Permit to Drill (APD,
Revised APD).
OMB Control Number: 1014–0025.
Form Number: BSEE–0123 (APD) and
BSEE–0123S (Supplemental APD).
Type of Review: Revision of a
currently approved collection.
Respondents/Affected Public:
Potential respondents comprise Federal
OCS oil, gas, and sulfur lessees/

operators and holders of pipeline rightsof-way.
Total Estimated Number of Annual
Respondents: Currently there are
approximately 60 Oil and Gas Drilling
and Production Operators in the OCS.
Not all the potential respondents would
submit information at any given time,
and some may submit multiple times.
Total Estimated Number of Annual
Responses: 11,331.
Estimated Completion Time per
Response: Varies from 1 hour to 2,800
hours depending on activity.
Total Estimated Number of Annual
Burden Hours: 77,945.
Respondent’s Obligation: Most
responses are mandatory, while others
are required to obtain or retain benefits.
Frequency of Collection: Generally, on
occasion and as required in the
regulations.
Total Estimated Annual Nonhour
Burden Cost: $4,400,470.

BURDEN TABLE
[Changes due to the proposed rule shown in bold]
Citation 30 CFR 250;
application for permit to drill
(APD)

Reporting or recordkeeping requirement *

Average number
of responses

Hour burden

Annual
burden hours
(rounded)

Non-hour cost burden
Subparts A, C, D, E, G, H, P ....

Apply for permit to drill, sidetrack, bypass, or
deepen a well submitted via Forms BSEE–
0123 (APD) and BSEE–0123S (Supplemental
APD). (This burden represents only the filling
out of the forms, the requirements are listed
separately below.).

1

190 applications ............

190

$2,113 fee × 190 = $401,470
Subparts D, E, G .......................

Obtain approval to revise your drilling plan or
change major drilling equipment by submitting
a Revised APD and Supplemental APD [no
cost recovery fee for Revised APDs]. (This
burden represents only the filling out of the
forms, the requirements are listed separately
below.).

1

730 submittals ...............

730

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

920 responses ..............

920

$401,470 non-hour cost burdens
Subpart A
125 ............................................

Submit evidence of your fee for services receipt

Exempt under 5 CFR 1320.3(h)(1)

0

197 ............................................

Written confidentiality agreement .........................

Exempt under 5 CFR 1320.5(d)(2)

0

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Subpart C
300(b)(1), (2) .............................

150

1 request .......................

150

Subpart C subtotal ............................................................................................................................

1 response ....................

150

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Obtain approval to add petroleum-based substance to drilling mud system or approval for
method of disposal of drill cuttings, sand, &
other well solids, including those containing
Naturally Occurring Radioactive Material
(NORM).

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Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules

79311

BURDEN TABLE—Continued
[Changes due to the proposed rule shown in bold]
Citation 30 CFR 250;
application for permit to drill
(APD)

Reporting or recordkeeping requirement *

Average number
of responses

Hour burden

Annual
burden hours
(rounded)

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Subpart D
408; 414(h) ................................

Request approval of alternate procedures or
equipment during drilling operations.

409 ............................................

Request departure approval from the drilling requirements specified in this subpart; identify
and discuss.

1

370 approvals ...............

370

410(b); 417(b); 713 ...................

Reference well and site-specific information in
case it is not approved in your Exploration
Plan, Development and Production Plan, Development Operations Coordination Document.
Burdens pertaining to EPs, DPPs, DOCDs are
covered under BOEM 1010–0151.

8

1 submittal ....................

8

410(d) ........................................

Submit to the District Manager: An original and
two complete copies of APD and Supplemental APD; separate public information copy
of forms per § 250.186.

0.5
R–0.5

380 submittals ...............
380 submittals ...............

190
190

411; 412 ....................................

Submit plat showing location of the proposed
well and all the plat requirements associated
with this section.

2

380 submittals ...............

760

411; 413; 414; 415; 420 ............

Submit design criteria used and all description
requirements; drilling prognosis with description of the procedures you will follow; and casing and cementing program requirements.

15

707 submittals ...............

10,605

411; 416; 731 ............................

Submit diverter and BOP systems descriptions
and all the regulatory requirements associated
with this section.

11

380 submittals ...............

4,180

411; 713 ....................................

Provide information for using a MODU and all
the regulatory requirements associated with
this section.

10

682 submittals ...............

6,820

411; 418 ....................................

Additional information required when providing
an APD include, but not limited to, rated capacities of drilling rig and equipment if not already on file; drilling fluids program, including
weight materials; directional plot; H2S contingency plan; welding plan; and information we
may require per requirements, etc.

20

380 submittals ...............

7,600

414(c) ........................................

Request preapproval to use alternative equivalent downhole mud weight prior to submitting
APD.

1

15 requests ...................

15

420(a)(7) ....................................

Include signed registered professional engineer
certification and related information.

3

1,034 certifications ........

3,102

423(c) ........................................

Submit for approval casing pressure test procedures and criteria. On casing seal assembly
ensure proper installation of casing or liner
(subsea BOP’s only).

3

527 procedures & criteria.

1,581

428(b) ........................................

Submit to District Manager for approval revised
casing setting depths or hole interval drilling
depth; include certification by PE.

125

1 submittal ....................

125

428(k) ........................................

Submit a description of the plan to use a
valve(s) on the drive pipe during cementing
operations for the conductor casing, surface
casing, or liner.

125

1 submittal ....................

125

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Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules
BURDEN TABLE—Continued
[Changes due to the proposed rule shown in bold]

Citation 30 CFR 250;
application for permit to drill
(APD)

Reporting or recordkeeping requirement *

Average number
of responses

Hour burden

Annual
burden hours
(rounded)

432 ............................................

Request departure from diverter requirements;
with discussion and receive approval.

8

53 requests ...................

424

460(a) ........................................

Include your projected plans if well testing along
with the required information.

17

2 plans ..........................

34

462(c) ........................................

Submit a description of your source control and
containment capabilities to the Regional Supervisor and receive approval; all required information.

125

1 submittal ....................

125

470(h) ........................................

Submit certification signed by PE that SSID
and well design meet requirements of
§ 250.472. (Alaska only).

3

2 certs. .........................

6

471(a); 472(b) ...........................

Submit, to Regional Supervisor, a request to
delay access to your SCCE and relief rig, if
applicable, including adequate documentation (such as, but not limited to, risk modeling data, off-set well data, analog data,
seismic data). Demonstrate you will not encounter any abnormally high-pressured
zones or other geologic hazards. (Alaska
only).

1

2 requests ....................

2

490(c) ........................................

Request to classify an area for the presence of
H2S.

3

91 requests ...................

273

Support request with available information such
as G&G data, well logs, formation tests, cores
and analysis of formation fluids.

3

73 submittals .................

219

Submit a request for reclassification of a zone
when a different classification is needed.

1

4 requests .....................

4

Due to the difficulties of drilling in Alaska, along
with the shortened time window allowed for
drilling, Alaska hours are done here as standalone requirements. Also, note that these specific hours are based on the first APD in Alaska in more than 10 years.

2,800

1 request .......................

2,800

Subpart D subtotal ............................................................................................................................

5,467 responses ...........

39,558

Alaska Region: 410; 412 thru
418; 420; 442; 444; 449; 456;
470; 471; 472.

Subpart E
513 ............................................

Obtain written approval to begin well completion
operations. If completion is planned and the
data are available you may submit on forms.

3
R–3

288 requests .................
1 request .......................

864
3

Submit description of well-completion, schematics, logs, any H2S..

18.5
R–26

295 submittals ...............
1 submittal ....................

5,458
26

Subpart E subtotal ............................................................................................................................

585 responses ..............

6,351

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Subpart G
701; 720 ....................................

Identify and discuss your proposed alternate procedures or equipment.

Burden covered under subpart A, 1014–
0022

0

702 ............................................

Identify and discuss departure requests. .............

Burden covered under subpart A, 1014–
0022

0

713(b) ........................................

Submit plat of the rig’s anchor pattern for a
moored rig approved in your EP, DPP, or
DOCD.

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1 submittal ....................

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Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules
BURDEN TABLE—Continued
[Changes due to the proposed rule shown in bold]
Citation 30 CFR 250;
application for permit to drill
(APD)

Reporting or recordkeeping requirement *

Average number
of responses

Hour burden

Annual
burden hours
(rounded)

713(e) ........................................

Provide contingency plan for using dynamically
positioned MODU and all the regulatory requirements associated with this section.

10

682 submittals ...............

6,820

713(g) ........................................

Describe specific current speeds when implementing rig shutdown and/or move-off procedures for water depths > 400 meters; discussion of specific measures you will take to curtail rig operations/move-off location.

45

1 submittal ....................

45

720(b) ........................................

Request approval to displace kill-weight fluid; include reasons why along with step-by-step
procedures.

5

518 approval requests ..

2,590

721(g)(4) ....................................

Submit test procedures and criteria for a successful negative pressure test for approval. If
any change, submit changes for approval.

2.5 R–4

355 submittals, 1
change.

8,884

731 ............................................

Submit complete description of BOP system and
components; schematic drawings; certification
by ITP (additional I3P if BOP is subsea, in
HPHT, or surface on floating facility);
autoshear, deadman, EDS systems.

114

129 submittals ...............

14,706

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$31,000 × 129 submittal = $3,999,000
733(b) ........................................

Describe annulus monitoring plan; and how the
well will be secured if leak is detected.

67

1 submittal ....................

67

734(b) ........................................

Submit verification report from ITP documenting
repairs and that BOP is fit for service.

R–64

1 report .........................

64

734(c) ........................................

Submit revision, including all verifications required, before drilling out surface casing.

R–66

1 submittal ....................

66

737(a) ........................................

Request approval from District Manager to omit
BOP pressure test. Indicate which casing
strings and liners meet the criteria for this request.

1

358 casing/liner info ......

358

737(b)(2) ....................................

Request approval of test pressures (RAM BOPs)

2

353 requests .................

706

737(b)(3) ....................................

Request approval of pressure test (annular
BOPs).

2

380 requests .................

760

737(d)(2) ....................................

Submit test procedures for approval for surface
BOP.

2.5

507 submittals ...............

1,268

737(d)(3); (d)(4) .........................

Submit test procedures, including how you will
test each ROV intervention function, for approval (subsea BOPs only).

2

507 submittals ...............

1,014

737(d)(12) ..................................

Submit test procedures (autoshear and deadman
systems) for approval. Include documentation
of the controls/circuitry system used for each
test; describe how the ROV will be utilized
during this operation.

2.5

507 submittals ...............

1,268

738(b) ........................................

Submit a revised permit with a written statement
from an independent third party documenting
the repairs, replacement, or reconfiguration
and certifying that the previous certification in
§ 250.731(c) remains valid.

.5

50 submittals .................

25

738(m) .......................................

Request approval to use additional well control
equipment, including BAVO report; as well as
other information required by District Manager.

66

1 request .......................

66

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Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules
BURDEN TABLE—Continued
[Changes due to the proposed rule shown in bold]

Citation 30 CFR 250;
application for permit to drill
(APD)
738(n) ........................................

Reporting or recordkeeping requirement *

Average number
of responses

Hour burden

Submit which pipe/variable bore rams have no
current utility or well control purposes.

Annual
burden hours
(rounded)

64

1 submittal ....................

64

Subpart G subtotal ............................................................................................................................

4,177 response .............

16,396

13

1 submittal ....................

13

Subpart H subtotal ............................................................................................................................

1 response ....................

13

Subpart H
807(a) ........................................

Submit detailed information that demonstrates
the SSSVs and related equipment are capable
of performing in HPHT.

Subpart P
Note that for Sulfur Operations, while there may be 49 burden hours listed, we have not had any sulfur leases for numerous years, therefore,
we have submitted minimal burden.
1605(b)(3) ..................................

Submit information on the fitness of the drilling
unit.

6

1 submittal ....................

6

1617 ..........................................

Submit fully completed application (Form BSEE–
0123) include rated capacities of the proposed
drilling unit and of major drilling equipment; as
well as all required information listed in this
section.

40

1 submittal ....................

40

1622(b) ......................................

Submit description of well-completion or
workover procedures, schematic, and if H2S is
present.

3

1 submittal ....................

3

Subpart P subtotal ............................................................................................................................

3 responses ..................

49

Total Burden for APD ..............................................................................................................

11,331 Responses .......

77,945

$4,400,470 Non Hour Cost Burden

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* In the future, BSEE may require electronic filing of some submissions.

In addition, the PRA requires agencies
to estimate the total annual reporting
and recordkeeping non-hour cost
burden resulting from the collection of
information, and we solicit your
comments on this item. For reporting
and recordkeeping only, your response
should split the cost estimate into two
components: (1) Total capital and
startup cost component and (2) annual
operation, maintenance, and purchase
of service component. Your estimates
should consider the cost to generate,
maintain, and disclose or provide the
information. You should describe the
methods you use to estimate major cost
factors, including system and
technology acquisition, expected useful
life of capital equipment, discount
rate(s), and the period over which you
incur costs. Generally, your estimates
should not include equipment or
services purchased: (1) Before October
1, 1995; (2) to comply with
requirements not associated with the
information collection; (3) for reasons

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other than to provide information or
keep records for the Government; or (4)
as part of customary and usual business
or private practices.
As part of our continuing effort to
reduce paperwork and respondent
burdens, we invite the public and other
Federal agencies to comment on any
aspect of this information collection,
including:
(1) Whether the collection of
information is necessary, including
whether the information will have
practical utility;
(2) The accuracy of our estimate of the
burden for this collection of
information;
(3) Ways to enhance the quality,
utility, and clarity of the information to
be collected; and
(4) Ways to minimize the burden of
the collection of information on
respondents.
Send your comments and suggestions
on this information collection by the
date indicated in the DATES section to
the Desk Officer for the Department of

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the Interior at OMB–OIRA at (202) 395–
5806 (fax) or via the RegInfo.gov portal
(online). You may view the information
collection request(s) at http://
www.reginfo.gov/public/do/PRAMain.
Please provide a copy of your comments
to the BSEE Information Collection
Clearance Officer (see the ADDRESSES
section). You may contact Kye Mason,
BSEE Information Collection Clearance
Officer at (703) 787–1607 with any
questions. Please reference Revisions to
the Requirements for Exploratory
Drilling on the Arctic Outer Continental
Shelf (OMB Control No. 1014–0025), in
your comments.
BOEM Information Collection—30 CFR
Part 550
This proposed rule would add and
remove requirements related to
submitting exploration plans and other
information before conducting oil and
gas exploration drilling activities on the
Arctic OCS. If final regulations become
effective, the information collection
burdens for this rulemaking would be

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Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules
consolidated into the existing collection
for Subpart B, Control Number 1010–
0151, and will be adjusted as necessary.
BOEM is requesting OMB approve the
modified collections of information for
OMB Control Number 1010–0151 with
the final rule publication.
Pertaining to this proposed
rulemaking, BOEM would collect the
information to ensure that planned
operations will be safe; will not
adversely affect the marine, coastal, or
human environments; will respond to
the special conditions on the Arctic
OCS; and will conserve the resources of
the Arctic OCS. BOEM would use the
information to ensure, through
advanced planning, that operators are
capable of safely operating in the unique
environmental conditions of the Arctic
and to make informed decisions on
whether to approve EPs as submitted or
whether modifications are necessary.
BOEM proposes to remove the
Integrated Operations Plan (IOP)
regulations by deleting § 550.204 and
removing the corresponding references
to the IOP from §§ 550.200 and 550.206.
BOEM’s existing requirement to submit
the IOP at least 90 days before the lessee
or operator files an EP would be
eliminated. The data and information
requested in the IOP is largely
unnecessary in light of the information
already collected in the EP. The current
approval for OMB Control Number
1010–0151 counts the similar burdens
associated with IOPs and EPs in both.
Therefore, BOEM would remove the
burdens attributed to the IOPs, and keep
the burdens attributed to EPs. Removing
the IOP provision would decrease the
annual burden hours by 1 response and
2,880 hours (- 1 response and 2,880
annual burden hours).
The proposed rule would add a
requirement to § 550.211(b) to describe
operational safety procedures that the
operator has developed specific to

conditions relevant on the Arctic OCS
in the EP. These requirements were
previously included in the IOP
requirements that are removed from this
rulemaking. Retaining this provision
would lessen the 2,880-burden hour
decrease by 50 annual burden hours
(i.e., by retaining 50 annual burden
hours).
BOEM proposes to revise
§ 550.220(c)(1) to require a description
of how exploratory drilling will be
designed and conducted, including how
all vessels and equipment will be
designed, built, and/or modified, to
account for Arctic OCS conditions and
how such activities will be managed
and overseen as an integrated endeavor,
and in the description of vessel
modifications, a description of any
approvals from the flag state and the
vessel classification society, including
any allowances or limitations placed
upon the vessel by the classification
society and/or the USCG. Vessel
modifications may include the
suitability of vessels for Arctic
conditions. These vessels may have or
acquire classification from a
‘‘recognized organization’’ under the
USCG’s Alternative Compliance
Program (ACP).54 BOEM is seeking to
confirm that the operator meets the
requirements of other entities with
authority over vessels, not to impose
requirements on those vessels. BOEM
believes that this change would not
impose any material additional burdens
on the lessees or operators. BOEM is
also proposing to revise § 550.220(c)(4)
and (6) by requiring the operator to
provide a general description of how
they will comply with § 250.472,
including a description of the
termination of their operations.
BOEM estimates that the proposed
revisions would remove 2,880 annual
burden hours that correlate to the
removal of the existing IOP requirement.

79315

These changes would result in a net
decrease of 2,830 annual burden hours.
Because not all EPs submitted to
BOEM would involve Arctic OCS
exploration drilling, we are separating
the burden associated with the Arcticspecific requirements and burdens from
the national EP requirements. The
burden table that follows this paragraph
outlines the revised requirements and
burdens associated with this
rulemaking. BOEM has not identified
any non-hour cost burdens associated
with these proposed requirements.
Title of Collection: Revisions to the
Requirements for Exploratory Drilling
on the Arctic Outer Continental Shelf—
30 CFR part 550, subpart B, Plans and
Information.
OMB Control Number: 1010–0151.
Form Number:
• BOEM–0137, OCS Plan Information
Form
• BOEM–0138, EP Air Quality
Screening Checklist
• BOEM–0139, DOCD/DPP Air
Quality Screening Checklist.
• BOEM–0141, ROV Survey Report.
• BOEM–0142, Environmental Impact
Analysis Worksheet.
Type of Review: Revision of a
currently approved collection.
Respondents/Affected Public:
Respondents are Federal oil and gas or
sulfur lessees or operators.
Total Estimated Number of Annual
Response: 4,265 respondents.
Total Estimated Number of Annual
Burden Hours: 433,608 hours.
Respondent’s Obligation: Some
responses to the information collection
are required to obtain or retain a benefit,
and some are mandatory.
Frequency of Collection: The
frequency of the response varies, but
primarily responses are required only
on occasion.
Total Estimated Annual Nonhour
Burden Cost: $3,939,435.

BURDEN BREAKDOWN
[Current requirements in regular font; proposed expanded requirements shown in italic font]
Citation 30 CFR 550
subpart B and NTLs

Reporting & recordkeeping requirement

Average number of
annual responses

Hour burden

Burden hours

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Non-hour costs
200 thru 206 ......................

General requirements for plans and information;
fees/refunds, etc.

Burden included with specific requirements
below.

0

201 thru 206; 211 thru
228: 241 thru 262.

BOEM posts EPs/DPPs/DOCDs on FDMS and receives public comments in preparation of EAs.

Not considered IC as defined in 5 CFR
1320.3(h)(4).

0

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

0 .......................................

54 33 U.S.C. 3316 and 46 CFR part 8 implement
the USCG’s ACP.

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Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules
BURDEN BREAKDOWN—Continued
[Current requirements in regular font; proposed expanded requirements shown in italic font]

Citation 30 CFR 550
subpart B and NTLs

Reporting & recordkeeping requirement

Average number of
annual responses

Hour burden

Burden hours

Non-hour costs
Ancillary Activities
208; NTL 2009–G34 * .......

Notify BOEM in writing, and if required by the Regional Supervisor notify other users of the OCS
before conducting ancillary activities.

11

61 notices ........................

671

208; 210(a) ........................

Submit report summarizing & analyzing data/information obtained or derived from ancillary activities.

2

61 reports ........................

122

208; 210(b) ........................

Retain ancillary activities data/information; upon request, submit to BOEM.

2

61 records ........................

122

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

183 responses .................

91

Contents of Exploration Plans (EP)
209; 231(b); 232(d); 234;
235; 281; 283; 284; 285;
NTL 2015–N01.

Submit new, amended, modified, revised, or supplemental EP, or resubmit disapproved EP, including
required information; withdraw an EP.

150

345 changed plans3 ........

51,750

209; 211 thru 228; NTL
2015–N01.

Submit EP and all required information (including,
but not limited to, submissions required by BOEM
Forms 0137, 0138, 0142; lease stipulations; reports, including shallow hazards surveys, H2S,
G&G,
archaeological
surveys
&
reports
(§ 550.194) ***, in specified formats. Provide notifications.

600

163 ...................................

97,800

$3,673 × 163 EP surface locations = $598,699
210; 220(a)–(c); 291; 292

For existing Arctic OCS exploration activities: revise
and resubmit Arctic-specific information, as required.

700

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

700

202; 211; 216; 219,
220(a)–(c); 224, 227;.

For new Arctic OCS exploration activities: submit required Arctic-specific information with EP.

400

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

400

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

510 responses .................

150,650

$598,699 Non-hour costs
Review and Decision Process for the EP
235(b); 272(b); ..................
281(d)(3)(ii) .......................

Appeal State’s objection ............................................

Burden exempt as defined in 5 CFR
1320.4(a)(2), (c).

0

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Contents of Development and Production Plans (DPP) and Development Operations Coordination Documents (DOCD)
209; 266(b); 267(d);
272(a); 273; 281; 283;
284; 285; NTL 2015–
N01.

Submit amended, modified, revised, or supplemental DPP or DOCD, including required information, or resubmit disapproved DPP or DOCD.

235

353 changed plans ..........

82,955

241 thru 262; 209; NTL
2015–N01.

Submit DPP/DOCD and required/supporting information (including, but not limited to, submissions
required by BOEM Forms 0137, 0139, 0142;
lease stipulations; reports, including shallow hazards surveys, archaeological surveys & reports
(§ 550.194)), in specified formats. Provide notification.

700

268 ...................................

187,600

$4,238 × 268 DPP/DOCD wells = $1,135,784.
Subtotal ..........................................................................................................................................

621 responses .................
$1,135,784 Non-hour costs

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BURDEN BREAKDOWN—Continued
[Current requirements in regular font; proposed expanded requirements shown in italic font]
Citation 30 CFR 550
subpart B and NTLs

Reporting & recordkeeping requirement

Average number of
annual responses

Hour burden

Burden hours

Non-hour costs
Review and Decision Process for the DPP or DOCD
267(a) ................................

Once BOEM deemed DPP/DOCD submitted; Governor of each affected State, local government official; etc., submit comments/recommendations.

Not considered IC as defined in 5 CFR
1320.3(h)(4).

0

267(b) ................................

General public comments/recommendations submitted to BOEM regarding DPPs or DOCDs.

Not considered IC as defined in 5 CFR
1320.3(h)(4).

0

269(b) ................................

For leases or units in vicinity of proposed development and production activities RD may require
those lessees and operators to submit information
on preliminary plans for their leases and units.

3

1 response .......................

3

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

1 response .......................

3

Post-Approval Requirements for the EP, DPP, and DOCD
280(b) ................................

In an emergency, request departure from your approved EP, DPP, or DOCD.

Burden included under 1010–0114.

0

281(a) ................................

Submit various BSEE applications for approval and
submit permits.

Burdens included under appropriate subpart or form (1014–0003; 1014–0011;
1014–0016; 1014–0018).

0

282 ....................................

Retain monitoring data/information; upon request,
make available to BOEM.

4

150 records ......................

600

Prepare and submit monitoring plan for approval .....

2

6 plans .............................

12

282(b) ................................

Prepare and submit monitoring reports and data (including BOEM Form 0141 used in GOMR).

3

12 reports ........................

36

284(a) ................................

Submit updated info on activities conducted under
approved EP/DPP/DOCD.

4

56 updates .......................

224

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

224 responses .................

872

14 documents ..................

5,250

Submit CIDs
296(a); 297 ........................

Submit CID and required/supporting information;
submit CID for supplemental DOCD or DPP.

375

$27,348 × 14 = $382,872
296(b); 297 ........................

Submit a revised CID for approval ............................

100

13 revisions .....................

1,300

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

27 responses ...................

6,550

$382,872 Non-hour costs
Seismic Survey Mitigation Measures and Protected Species Observer Program NTL

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NTL 2016–G02; 211 thru
228; 241 thru 262.

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Submit to BOEM observer training requirement materials and information.

1.5 hours

2 sets of material .............

3

Training certification and recordkeeping ...................

1 hour

1 new trainee ...................

1

During seismic acquisition operations, submit daily
observer reports semi-monthly.

1.5 hours

344 reports ......................

516

If used, submit to BOEM information on any passive
acoustic monitoring system prior to placing it in
service.

2 hours

6 submittals .....................

12

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BURDEN BREAKDOWN—Continued
[Current requirements in regular font; proposed expanded requirements shown in italic font]

Citation 30 CFR 550
subpart B and NTLs

Reporting & recordkeeping requirement

Average number of
annual responses

Hour burden

Burden hours

Non-hour costs
During seismic acquisition operations, submit to
BOEM marine mammal observation report(s)
semi-monthly or within 24 hours if air gun operations were shut down.

1.5 hours

1,976 reports ...................

2,964

During seismic acquisition operations, when air
guns are being discharged, submit daily observer
reports semi-monthly.

1.5 hours

344 reports ......................

516

Observation Duty (3 observers fulfilling an 8-hour
shift each for 365 calendar days × 4 vessels =
35,040 man-hours). This requirement is contracted out; hence the non-hour cost burden.

3 observers × 8 hrs × 365 days = 8,760 hours × 4 vessels
observing = 35,040 man-hours × $52/hr = $1,822,080.

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

2,673 responses ..............

4,012

$1,822,080 Non-hour costs
Vessel Strike Avoidance and Injured/Protected Species Reporting NTL
NTL 2016–G01; 211 thru
228; 241 thru 262.

Notify BOEM within 24 hours of strike, when your
vessel injures/kills a protected species (marine
mammal/sea turtle).

1 hour

1 notice ............................

1

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

1 response .......................

1

2

25 requests ......................

50

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

25 responses ...................

50

Total Burden ............................................................................................................................

4,265 responses ..............

433,608

General Departure
200 thru 299 ......................

General departure and alternative compliance requests not specifically covered elsewhere in Subpart B regulations.

$3,939,435 Non-hour costs

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* The identification number of NTLs may change when NTLs are reissued periodically to update information.

In addition, the PRA requires agencies
to estimate the total annual reporting
and recordkeeping non-hour cost
burden resulting from the collection of
information, and we solicit your
comments on this item. For reporting
and recordkeeping only, your response
should split the cost estimate into two
components: (1) Total capital and
startup cost component and (2) annual
operation, maintenance, and purchase
of service component. Your estimates
should consider the cost to generate,
maintain, and disclose or provide the
information. You should describe the
methods you use to estimate major cost
factors, including system and
technology acquisition, expected useful
life of capital equipment, discount
rate(s), and the period over which you
incur costs. Generally, your estimates
should not include equipment or
services purchased: (1) Before October
1, 1995; (2) to comply with

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requirements not associated with the
information collection; (3) for reasons
other than to provide information or
keep records for the Government; or (4)
as part of customary and usual business
or private practices.
As part of our continuing effort to
reduce paperwork and respondent
burdens, we invite the public and other
Federal agencies to comment on any
aspect of this information collection,
including:
(1) Whether the collection of
information is necessary, including
whether the information will have
practical utility;
(2) The accuracy of our estimate of the
burden for this collection of
information;
(3) Ways to enhance the quality,
utility, and clarity of the information to
be collected; and
(4) Ways to minimize the burden of
the collection of information on
respondents.

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Send your comments and suggestions
on this information collection by the
date indicated in the DATES section to
the Desk Officer for the Department of
the Interior at OMB–OIRA at (202) 395–
5806 (fax) or via the portal at
RegInfo.gov (online). You may view the
information collection request(s) at
http://www.reginfo.gov/public/do/
PRAMain. Please provide a copy of your
comments to the BOEM Information
Collection Clearance Officer (see the
ADDRESSES section). You may contact
Anna Atkinson, BOEM Information
Collection Clearance Officer at (703)
787–1025 with any questions. Please
reference Revisions to the Requirements
for Exploratory Drilling on the Arctic
Outer Continental Shelf (OMB Control
No. 1014–0151), in your comments.
J. National Environmental Policy Act of
1969 (NEPA)
BSEE and BOEM developed a draft
Environmental Assessment (EA) to

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Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules
determine whether this proposed rule
would have a significant impact on the
quality of the human environment
under the NEPA. The draft EA is
available for review in conjunction with
this proposed rule at
www.regulations.gov (in the Search box,
enter BSEE–2019–0008).
K. Data Quality Act
In developing this proposed rule, we
did not conduct or use a study,
experiment, or survey requiring peer
review under the Data Quality Act (44
U.S.C. 3516 note).
L. Effects on the Nation’s Energy Supply
(E.O. 13211)
Although this proposed rule is a
significant regulatory action under E.O.
12866, it is not a significant energy
action under the definition of that term
in E.O. 13211 because:
1. It is not likely to have a significant
adverse effect on the supply,
distribution or use of energy; and
2. It has not been designated as a
significant energy action by the
Administrator of OIRA.
Thus, a Statement of Energy Effects is
not required.
While offshore Arctic OCS oil and gas
studies indicate the potential of vast
resources, there is currently little
exploration activity and very little
production of oil and gas on the Arctic
OCS, largely due to the inherent
practical difficulties of exploration and
production in the area. The only
existing oil production from the Arctic
OCS is through the Northstar Island
facility.

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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:
1. Be logically organized;
2. Use the active voice to address
readers directly;
3. Use clear language rather than
jargon;
4. Be divided into short sections and
sentences; and
5. Use lists and tables wherever
possible.
If you believe we have not met these
requirements, send us comments by one
of the methods listed in the ADDRESSES
section. To better help us revise the
rule, your comments should be as
specific as possible. For example, you
should tell us the numbers of the
sections or paragraphs that you find
unclear, which sections or sentences are
too long, or the sections where you
believe lists or tables would be useful.

16:49 Dec 08, 2020

30 CFR Part 250
Administrative practice and
procedure, Continental shelf,
Environmental impact statements,
Environmental protection, Government
contracts, Incorporation by reference,
Investigations, Oil and gas exploration,
Penalties, Pipelines, Public lands–
mineral resources, Public lands—rights
of-way, Reporting and recordkeeping
requirements, Sulphur.
30 CFR Part 550
Administrative practice and
procedure, Continental shelf,
Environmental impact statements,
Environmental protection, Mineral
resources, Oil and gas exploration,
Pipelines, Reporting and recordkeeping
requirements, Sulfur.
Katharine MacGregor,
Deputy Secretary, U.S. Department of the
Interior.

For the reasons stated in the
preamble, BSEE and BOEM amend 30
CFR parts 250 and 550 as follows:
Title 30—Mineral Resources
CHAPTER II—BUREAU OF SAFETY AND
ENVIRONMENTAL ENFORCEMENT,
DEPARTMENT OF THE INTERIOR
SUBCHAPTER B—OFFSHORE

PART 250—OIL AND GAS AND
SULPHUR OPERATIONS IN THE
OUTER CONTINENTAL SHELF
1. The authority citation for 30 CFR
part 250 continues to read as follows:

■

Authority: 30 U.S.C. 1751, 31 U.S.C. 9701,
33 U.S.C. 1321(j)(1)(C), 43 U.S.C. 1334.

M. Clarity of Regulations

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2. Amend § 250.105 by revising the
definition of ‘‘Capping stack’’ to read as
follows:

■

§ 250.105

Definitions.

*

*
*
*
*
Capping stack means a mechanical
device that can be installed on top of a
subsea or surface wellhead or blowout
preventer to stop the uncontrolled flow
of fluids into the environment.
*
*
*
*
*
■ 3. Amend § 250.175 by adding
paragraph (d) to read as follows:
§ 250.175 When may the Regional
Supervisor grant an SOO?

*

*
*
*
*
(d) For leases or units on the Arctic
OCS, you may request, and the Regional
Supervisor may grant, an SOO when
you have conducted leaseholding
operations during the drilling season
immediately preceding the period for
which you are seeking a suspension,

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79319

and you satisfy one of the following
conditions:
(1) You are conducting drilling
operations from a Mobile Offshore
Drilling Unit (MODU), but you are not
able to safely continue leaseholding
operations due to the presence of
seasonal ice;
(2) You are conducting drilling
operations from an artificial gravel
island or a gravity-based structure, but
you are not able to safely continue
leaseholding operations due to
temporary seasonal restrictions in your
approved oil spill response plan; or
(3) You are conducting drilling
operations from an artificial ice island,
but you are not able to safely continue
leaseholding operations due to seasonal
temperature changes.
■ 4. Amend § 250.198 by revising
paragraph (e)(73) to read as follows:
§ 250.198 Documents incorporated by
reference.

*

*
*
*
*
(e) * * *
(73) API RP 17H, Remotely Operated
Tools and Interfaces on Subsea
Production Systems, Second Edition,
June 2013; Errata, January 2014;
incorporated by reference at
§§ 250.472(a) and 250.734(a);
*
*
*
*
*
■ 5. Amend § 250.300 by revising
paragraphs (b)(1) and (2) to read as
follows:
§ 250.300

Pollution prevention.

*

*
*
*
*
(b)(1) The District Manager may
restrict the rate of drilling fluid
discharges or prescribe alternative
discharge methods. The District
Manager may also restrict the use of
components that could cause
unreasonable degradation to the marine
environment. No petroleum-based
substances, including diesel fuel, may
be added to the drilling mud system
without prior approval of the District
Manager. For Arctic OCS exploratory
drilling, you must capture all
petroleum-based mud to prevent its
discharge into the marine environment.
(2) You must obtain approval from the
District Manager of the method you plan
to use to dispose of drill cuttings, sand,
and other well solids. For Arctic OCS
exploratory drilling, you must capture
all cuttings from operations that use
petroleum-based mud to prevent their
discharge into the marine environment.
*
*
*
*
*
■ 6. Amend § 250.470 by:
■ a. Revising paragraphs (b)(11) and
(12);
■ b. Adding paragraph (b)(13);
■ c. Revising paragraph (f)(3); and

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d. Adding paragraph (h).
The revisions and additions read as
follows:

■

§ 250.470 What additional information
must I submit with my APD for Arctic OCS
exploratory drilling operations?

*

*
*
*
*
(b) * * *
(11) Pick up the oil spill prevention
booms and equipment;
(12) Offload the drilling crew; and
(13) Recover the subsea isolation
device (SSID), where applicable.
*
*
*
*
*
(f) * * *
(3) Where applicable, proof of
contracts or membership agreements
with cooperatives, service providers, or
other contractors who will provide you
with the necessary SCCE or related
supplies and services if you do not
possess them. The contract or
membership agreement must include
provisions for ensuring the availability
of the personnel and/or equipment on a
24-hour per day basis while you are
drilling below or working below the
surface casing, or before the last casing
point prior to penetrating a zone capable
of flowing hydrocarbons in measurable
quantities, as approved by the Regional
Supervisor.
*
*
*
*
*
(h) If you plan to install a subsea
isolation device (SSID) on your well in
accordance with § 250.472(a), a
certification signed by a registered
professional engineer that your SSID
and well design (including casing and
cementing program) meet the design
requirements in § 250.472 and the
design is appropriate for the purpose for

which it is intended under expected
wellbore conditions.
■ 7. Amend § 250.471 by revising
paragraph (a) introductory text, and
paragraphs (a)(2) and (3) and (b) to read
as follows:
§ 250.471 What are the requirements for
Arctic OCS source control and
containment?

*

*
*
*
*
(a) If you use a MODU, you must have
access to the SCCE as described in
paragraphs (a)(1) through (3) of this
section capable of controlling and
containing the flow from an out-ofcontrol well when drilling below or
working below the surface casing.
However, the Regional Supervisor will
approve delaying access to your SCCE
until your operations have reached the
last casing point prior to penetrating a
zone capable of flowing hydrocarbons in
measurable quantities, provided that
you submit adequate documentation
(such as, but not limited to, risk
modeling data, off-set well data, analog
data, seismic data), with your APD,
demonstrating that you will not
encounter any abnormally highpressured zones or other geologic
hazards. The Regional Supervisor will
base the determination on any
documentation you provide as well as
any other available data and
information.
*
*
*
*
*
(2) A cap and flow system that can be
deployed as directed by the Regional
Supervisor pursuant to paragraph (h) of
this section. The cap and flow system
must be designed to capture at least the
amount of hydrocarbons equivalent to

the calculated worst case discharge rate
referenced in your BOEM-approved EP;
and
(3) A containment dome that can be
deployed as directed by the Regional
Supervisor pursuant to paragraph (h) of
this section. The containment dome
must have the capacity to pump fluids
without relying on buoyancy.
(b) You must conduct a monthly
stump test of dry-stored capping stacks.
*
*
*
*
*
■ 8. Revise § 250.472 to read as follows:
§ 250.472 What are the additional well
control equipment or relief rig requirements
for the Arctic OCS?

If you will be conducting exploratory
drilling operations from a Mobile
Offshore Drilling Unit (MODU), you
must either use a Subsea Isolation
Device (SSID) or have access to a relief
rig as an additional means to secure the
well in the event of a loss of well
control. If you satisfy this requirement
through use of an SSID, you must meet
the requirements in paragraph (a) in this
section. If you satisfy this requirement
through maintaining access to a relief
rig, you must meet the requirements in
paragraph (b) in this section.
(a) Subsea Isolation Device (SSID). If
you use an SSID to satisfy this
requirement, your SSID and well
(including the casing and cementing
program) must be designed to achieve a
full shut-in, without causing an
underground blowout or having
reservoir fluids broach to the seafloor.
Your SSID must also meet the following
requirements:

TABLE 1 TO PARAGRAPH (a)
Your SSID must
(1) Be designed to: ..............................................

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(2) Include the following equipment:

(3) Include ROV intervention equipment and capabilities. Your ROV equipment and capabilities must:

(i) Close and seal the wellbore, independent of the BOP;
(ii) Perform under the maximum environmental and operational conditions anticipated to occur
at the well;
(iii) Be left on the wellhead in the event the drilling rig is moved off location (e.g., due to
storms, ice incursions, or emergency situations);
(iv) Preserve isolation through the winter season without relying on the elastomer elements of
the rams (e.g., by using a well cap) and allow re-entry during the following open-water season; and
(v) In the event of a loss of well control, preserve isolation until other methods of well intervention may be completed, including the need to drill a relief well.
(i) Dual shear rams, including ram locks; one ram must be a blind shear ram;
(ii) A redundant control system, independent from the BOP control system, that includes ROV
capabilities and a control station on the rig;
(iii) Independent, dedicated subsea accumulators with the capacity to function all components
of the SSID; and
(iv) Two side inlets for intervention; one inlet must be located below the lowest ram on the
SSID.
(i) Be able to close each shear ram under MASP conditions, as defined for the operation;
(ii) Include an ROV panel that is compliant with API RP 17H (as incorporated by reference in
§ 250.198);
(iii) Meet the ROV requirements in § 250.734(a)(5); and
(iv) Have the ability to function the SSID in any environment (e.g., when in a mudline cellar).

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TABLE 1 TO PARAGRAPH (a)—Continued
Your SSID must
(4) Be installed: ...................................................

(i) Below the BOP;
(ii) At or before the time that you first install your BOP; and
(iii) To provide protection from deep ice keels, in the event it must remain in place over the
winter season (e.g., installed in a mudline cellar).
According to the BOP testing requirements in § 250.737.

(5) Be tested: ......................................................

(b) Relief Rig. If you choose to satisfy
this requirement by having access to a
relief rig, you must have access to your
relief rig at all times when you are
drilling below or working below the
surface casing during Arctic OCS
exploratory drilling operations.
However, the Regional Supervisor will
approve delaying access to your relief
rig until your operations have reached
the last casing point prior to penetrating
a zone capable of flowing hydrocarbons
in measurable quantities, provided that
you submit adequate documentation
(such as, but not limited to, risk
modeling data, off-set well data, analog
data, seismic data), with your APD,
demonstrating that you will not
encounter any abnormally highpressured zones or other geologic
hazards. The Regional Supervisor will
base the determination on any
documentation you provide as well as
any other available data and
information. Your relief rig must be
different from your primary drilling rig,
staged in a location, such that it would
be available to arrive on site, drill a
relief well, kill and abandon the original
well, and abandon the relief well no
later than 45 days after the loss of well
control.
(1) Your relief rig must comply with
all other requirements of this part
pertaining to drill rig characteristics and
capabilities, and it must be able to drill
a relief well under anticipated Arctic
OCS conditions.
(2) In the event of a loss of well
control, the Regional Supervisor may
direct you to drill a relief well using a
relief rig that is able to kill and
permanently plug an out-of-control well
as described in your APD.
■ 9. Amend § 250.720 by revising
paragraph (c)(2) to read as follows:

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§ 250.720
well?

When and how must I secure a

*

*
*
*
*
(c) * * *
(2) In areas of ice scour, you must use
a well mudline cellar or an equivalent
means of minimizing the risk of damage
to the well head and wellbore. You may
request, and the Regional Supervisor
may approve, an alternate procedure or

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16:49 Dec 08, 2020

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equipment in accordance with
§§ 250.141 and 250.408.
*
*
*
*
*
CHAPTER V—BUREAU OF OCEAN
ENERGY MANAGEMENT, DEPARTMENT OF
THE INTERIOR
SUBCHAPTER B—OFFSHORE

PART 550—OIL AND GAS AND
SULPHUR OPERATIONS IN THE
OUTER CONTINENTAL SHELF
10. The authority citation for 30 CFR
part 550 continues to read as follows:

■

Authority: 30 U.S.C. 1751; 31 U.S.C. 9701;
43 U.S.C. 1334.
§ 550.220

[Amended]

11. Amend § 550.200 by removing the
words ‘‘IOP means Integrated
Operations Plan.’’ in paragraph (a).
■ 12. Remove and reserve § 550.204.
■

§ 550.204

[Reserved]

13. Amend § 550.206 by revising the
section heading, paragraph (a)
introductory text, and paragraphs (a)(3),
(b), and (c) to read as follows:

■

§ 550.206
DOCD?

How do I submit the EP, DPP, or

(a) Number of copies. When you
submit an EP, DPP, or DOCD to BOEM,
you must provide:
*
*
*
*
*
(3) Any additional copies that may be
necessary to facilitate review of the EP,
DPP, or DOCD by certain affected States
and other reviewing entities.
(b) Electronic submission. You may
submit part or all of your EP, DPP, or
DOCD and its accompanying
information electronically. If you prefer
to submit your EP, DPP, or DOCD
electronically, ask the Regional
Supervisor for further guidance.
(c) Withdrawal after submission. You
may withdraw your proposed EP, DPP,
or DOCD at any time for any reason.
Notify the appropriate BOEM Regional
Office if you do.
■ 14. Amend § 550.211 by redesignating
paragraphs (b) through (d) as paragraphs
(c) through (e), respectively, and adding
new paragraph (b) to read as follows:
§ 550.211

*

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*

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*

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*

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(b) A description of how you will
ensure operational safety while working
in Arctic OCS conditions, including but
not limited to:
(1) The safety principles that you
intend to apply to yourself and your
contractors;
(2) The accountability structure
within your organization for
implementing such principles;
(3) How you will communicate such
principles to your employees and
contractors; and
(4) How you will determine
successful implementation of such
principles.
*
*
*
*
*
■ 15. Amend § 550.220 by revising the
section heading, paragraphs (c)(1) and
(4), and (c)(6)(ii) to read as follows:
§ 550.220 If I propose activities in the
Arctic OCS Region, what planning
information must accompany the EP?

*

*
*
*
*
(c) * * *
(1) A description of how your
exploratory drilling will be designed
and conducted, (including how all
vessels and equipment will be designed,
built, and/or modified) to account for
Arctic OCS conditions and how such
activities will be managed and overseen
as an integrated endeavor. In your
description of vessel modifications,
describe any approvals from the flag
state and the vessel classification
society, including any allowances or
limitations placed upon the vessel by
the classification society and/or the
United States Coast Guard.
*
*
*
*
*
(4) Additional well control equipment
requirements for the Arctic OCS. A
general description of how you will
comply with § 250.472 of this title.
(6) * * *
(ii) The termination of drilling
operations consistent with the well
control planning requirements under
§ 250.472 of this title.
[FR Doc. 2020–25818 Filed 12–8–20; 8:45 am]
BILLING CODE 4310–VH–P; 4310–MR–P

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09DEP2