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Proposed Rule2026-15953

Oil and Gas and Sulfur Operations on the Outer Continental Shelf-Revisions to the Requirements for Exploratory Drilling on the Arctic Outer Continental Shelf

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Published

August 6, 2026

Issuing agencies

Interior DepartmentSafety and Environmental Enforcement BureauOcean Energy Management Bureau

Abstract

The Department of the Interior (DOI or Department), acting through BSEE and BOEM (collectively, "the Bureaus"), 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.\1\ 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") (see 81 FR 46478). This proposed rule would modify existing Arctic OCS blowout preventer (BOP) real-time monitoring requirements and add new provisions to BSEE's regulations pertaining to requirements for crane operations on artificial islands, suspensions of operations (SOO), and suspensions of production (SOP). This proposed rule would also revise certain parts of the Exploration Plan (EP) and Development and Production Plan (DPP) regulations implemented by BOEM. ---------------------------------------------------------------------------

Full Text

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<title>Federal Register, Volume 91 Issue 150 (Thursday, August 6, 2026)</title>
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[Federal Register Volume 91, Number 150 (Thursday, August 6, 2026)]
[Proposed Rules]
[Pages 50998-51056]
From the Federal Register Online via the Government Publishing Office [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[FR Doc No: 2026-15953]

[[Page 50997]]

Vol. 91

Thursday,

No. 150

August 6, 2026

Part III

Department of the Interior

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Bureau of Safety and Environmental Enforcement

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30 CFR Parts 250 and 254

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Bureau of Ocean Energy Management

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30 CFR Part 550

Oil and Gas and Sulfur Operations on the Outer Continental Shelf--
Revisions to the Requirements for Exploratory Drilling on the Arctic
Outer Continental Shelf; Proposed Rule

Federal Register / Vol. 91, No. 150 / Thursday, August 6, 2026 /
Proposed Rules

[[Page 50998]]

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DEPARTMENT OF THE INTERIOR

Bureau of Safety and Environmental Enforcement

30 CFR Part 250 and 254

Bureau of Ocean Energy Management

30 CFR Part 550

[Docket ID: BSEE-2026-0133 EEEE500000-256E1700D2-ET1SF0000.EAQ000]
RIN 1082-AA05

Oil and Gas and Sulfur Operations on the Outer Continental
Shelf--Revisions to the Requirements for Exploratory Drilling on the
Arctic Outer Continental Shelf

AGENCY: Bureau of Safety and Environmental Enforcement (BSEE); Bureau
of Ocean Energy Management (BOEM), Interior.

ACTION: Proposed rule.

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SUMMARY: The Department of the Interior (DOI or Department), acting
through BSEE and BOEM (collectively, ``the Bureaus''), 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.\1\ 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'') (see 81 FR 46478). This proposed rule
would modify existing Arctic OCS blowout preventer (BOP) real-time
monitoring requirements and add new provisions to BSEE's regulations
pertaining to requirements for crane operations on artificial islands,
suspensions of operations (SOO), and suspensions of production (SOP).
This proposed rule would also revise certain parts of the Exploration
Plan (EP) and Development and Production Plan (DPP) regulations
implemented by BOEM.
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\1\ Outer Continental Shelf Lands Act, sec. 3, 43 U.S.C. 1332.

DATES: Submit comments on this proposed rule to BSEE on or before
October 5, 2026. The Bureaus 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 September 8, 2026. The deadline for comments on the information
collection burden does not affect the deadline for the public to
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comment to the Bureaus on the proposed regulations.

ADDRESSES: You may submit comments on the proposed rule by any of the
following methods. Please use the Regulation Identifier Number (RIN)
1082-AA05 as an identifier in your message. See also Public
Availability of Comments under Procedural Matters.
<bullet> Federal eRulemaking Portal: <a href="https://www.regulations.gov">https://www.regulations.gov</a>.
In the entry entitled, ``Enter Keyword or ID,'' enter BSEE-2026-0133,
then click search. Follow the instructions to submit public comments
and view supporting and related materials available for this
rulemaking, including a plain language summary of the proposed rule as
required by 5 U.S.C. 553(b)(4). The Bureaus may post all submitted
comments.
<bullet> 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-AA05, ``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.
<bullet> Email: <a href="/cdn-cgi/l/email-protection#ec9e898b9fac8e9f8989c28b839a">[email&#160;protected]</a>.
<bullet> 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 <a href="https://www.reginfo.gov/public/do/PRAMain">https://www.reginfo.gov/public/do/PRAMain</a>. From this main web page, you can
find and submit comments on this particular information collection by
proceeding to the boldface heading ``Currently under Review,''
selecting ``Department of the Interior'' in the ``Select Agency'' pull
down menu, clicking ``Submit,'' then, checking the box ``Only Show ICR
for Public Comment'' on the next web page, scrolling to this proposed
rule, and clicking the ``Comment'' button at the right margin.
Alternatively, you may use the search function on the main web page.
Please also send a copy to the Bureaus by one of the means previously
described, and reference ``OMB Control Number 1014-[TBD] (Revisions to
the Requirements for Exploratory Drilling on the Arctic Outer
Continental Shelf) for BSEE-related comments or OMB Control Number
1010-[TBD] (Revisions to the Requirements for Exploratory Drilling on
the Arctic Outer Continental Shelf) for BOEM-related comments, as
applicable, in the subject line of your comments.
<bullet> Public Availability of Comments: Please be aware that
BOEM's and BSEE's practice is to make comments, including the names and
addresses of individuals, available for public inspection. Before
including your address, phone number, email address, and any personally
identifiable information in your comment, please be advised that your
entire comment, including your personally identifiable information, may
be made publicly available at any time. For the Bureaus to consider
withholding from disclosure your personally identifiable information,
you must identify, in a cover letter, any information contained in your
comments that, if released, would constitute a clearly unwarranted
invasion of your personal privacy. You must also briefly describe any
possible harmful consequences of the disclosure of information, such as
embarrassment, injury, or other harm.
Even if the Bureaus withhold your information in the context of
this proposed rule, your submission is subject to the Freedom of
Information Act (FOIA). If your submission is requested under the FOIA,
your information will only be withheld if BOEM or BSEE determines that
one of the FOIA exemptions to disclosure applies. Such a determination
will be made in accordance with the Department's FOIA regulations and
applicable law.
The Bureaus will make available for public inspection all comments,
in their entirety, submitted by organizations and businesses (except as
provided material marked and exempted as proprietary information) or by
individuals identifying themselves as representatives of organizations
or businesses.

FOR FURTHER INFORMATION CONTACT: For technical questions related to
regulatory changes BSEE is proposing in Part 250, contact Bobby Kurtz,
BSEE, Acting Alaska OCS Regional Director, <a href="/cdn-cgi/l/email-protection#fdbf929f9f84d3b6888f8987bd9f8e9898d39a928b">[email&#160;protected]</a>, 805-
384-6359. For technical questions related to regulatory changes BOEM is
proposing in Part 550, contact Joel Immaraj, BOEM, Alaska Regional
Office, <a href="/cdn-cgi/l/email-protection#d7bdb8b2bbf9bebabab6a5b6bd97b5b8b2baf9b0b8a1">[email&#160;protected]</a>, (907) 334-5238. For procedural questions
contact Bryce Barlan, BSEE, Regulations and Standards Branch,
<a href="/cdn-cgi/l/email-protection#027067657142607167672c656d74">[email&#160;protected]</a>, (703) 787-1126.

SUPPLEMENTARY INFORMATION:

Executive Summary

Executive Orders (E.O.) and Secretary's Orders (S.O.) issued in
2017

[[Page 50999]]

directed 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. E.O. 13795, Implementing an America-First Offshore Energy
Strategy (see 82 FR 20815), which specifically called for a review of
the 2016 Arctic Exploratory Drilling Rule, and S.O. 3350, America-First
Offshore Energy Strategy, are discussed in more detail below in Section
I. Background, Subsection B. Executive and Secretary's Orders.\2\
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\2\ These Orders do not dictate outcomes; rather, they directed
a review in accordance with applicable law.
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In response to these orders, the Bureaus undertook a review of the
regulations promulgated through the 2016 Arctic Exploratory Drilling
Rule and, on December 9, 2020, the Bureaus issued a proposed rule
titled Revisions to the Requirements for Exploratory Drilling on the
Arctic Outer Continental Shelf (``2020 Proposed Revisions to the Arctic
Exploratory Drilling Rule'') (see 85 FR 79266). However, on June 29,
2021, the Bureaus withdrew the 2020 Proposed Revisions to the Arctic
Exploratory Drilling Rule (see 86 FR 34172) due to a change in
administration and policy.
Subsequently, in January 2025, the President signed E.O. 14153,
Unleashing Alaska's Extraordinary Resource Potential (see 90 FR 8347)
and E.O. 14154, Unleashing American Energy (see 90 FR 8353), which
aimed to expand natural resource development throughout the Nation and
in Alaska to promote American energy independence. These E.O.s. also
call upon the heads of Federal Agencies, including the Secretary of the
Interior (Secretary) to review all existing regulations, orders,
guidance documents, policies, and any other similar agency actions, and
rescind, revoke, revise, amend, defer, or grant exemptions from those
that limit energy development on Federal lands and waters. In response
to these E.O.s, the Secretary issued S.O. 3422, Unleashing Alaska's
Extraordinary Resource Potential, and S.O. 3418, Unleashing American
Energy, both of which were intended to implement the policies in E.O.
14153 and E.O. 14154.
This proposed rule responds to the 2025 E.O.s and S.O.s and is also
consistent with the efforts the Bureaus previously undertook through
the 2020 Proposed Revisions to the Arctic Exploratory Drilling Rule. It
would create more flexible and less costly compliance options in BSEE's
and BOEM's regulations and is designed 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. In particular, this proposed rule would revise certain
provisions in 30 Code of Federal Regulations (CFR) Part 250, Subparts
C, D, and G, 30 CFR part 254, subparts A and E, and 30 CFR part 550,
subpart B, that were promulgated through the 2016 Arctic Exploratory
Drilling Rule and pertain to:
1. Definition of the ``Arctic OCS'';
2 Pollution prevention;
3. Arctic OCS Source Control and Containment Equipment (SCCE);
4. BOP real-time monitoring requirements for the Arctic OCS;
5. Relief rig capabilities for the Arctic OCS;
6. Mudline cellars;
7. Oil spill response plan-holder reviews;
8. Timing and submission requirements related to Integrated
Operations Plans (IOP) for proposed Arctic exploratory drilling;
9. What must be included in the IOP; and
10. What data and information must accompany the EP and DPP.
This proposed rule would also revise certain provisions in 30 CFR
part 250, subpart A, that are not addressed by the 2016 Arctic
Exploratory Drilling Rule, but are relevant to the Arctic OCS or the
Alaska OCS region and, therefore, are appropriate to address as part of
this proposed rulemaking. These provisions pertain to:
1. The factors that the BSEE Regional Supervisor may evaluate in
assessing whether to grant an SOO or grant or direct an SOP to address
unique and specific conditions relevant only to exploration and
development activities in the Alaska OCS region; and
2. Cranes used for operations on artificial islands.

Table of Contents:

I. Background
A. BSEE and BOEM Statutory and Regulatory Authority and
Responsibilities
B. Executive and Secretary's Orders
C. Purpose and Summary of the Rulemaking
D. Procedures for Incorporation by Reference and Availability of
Incorporated Documents for Public Viewing
II. Section-by-Section Discussion of Proposed Changes
A. Key Revisions Proposed by BSEE
Title 30, Chapter II, Subchapter B, Part 250
Subpart A--General
<bullet> Definitions (Sec. 250.105)
<bullet> What requirements must I follow for cranes and other
material-handling equipment? (Sec. 250.108)
<bullet> What requirements must I follow for cranes and other
material-handling equipment? (Sec. 250.108)
<bullet> How long does a suspension last? (Sec. 250.170)
<bullet> How do I request a suspension? (Sec. 250.171)
<bullet> When may the Regional Supervisor grant or direct an
SOP? (Sec. 250.174)
<bullet> When may the Regional Supervisor grant an SOO? (Sec.
250.175)
<bullet> Documents Incorporated by Reference. (Sec. 250.198)
Subpart C--Pollution Prevention and Control
<bullet> Pollution Prevention. (Sec. 250.300)
Subpart D--Oil and Gas Drilling Operations
<bullet> What are the real-time monitoring requirements for
Arctic OCS exploratory drilling operations? (Sec. 250.452)
<bullet> What additional information must I submit with my APD
for Arctic OCS exploratory drilling operations? (Sec. 250.470)
<bullet> What are the requirements for Arctic OCS source control
and containment? (Sec. 250.471)
<bullet> What are the additional well control equipment or
relief rig requirements for the Arctic OCS? (Sec. 250.472)
Subpart G--Well Operations and Equipment
<bullet> When and how must I secure a well? (Sec. 250.720)
<bullet> What are the real-time monitoring requirements? (Sec.
250.724)
Title 30, Chapter II, Subchapter B, Part 254
Subpart A--General
<bullet> Definitions. (Sec. 254.6)
Subpart E--Oil-Spill Response Requirements for Facilities
Located on the Arctic OCS
<bullet> What are the additional requirements for facilities
conducting exploratory drilling from a MODU on the Arctic OCS?
(Sec. 254.70)
B. Key Revisions Proposed by BOEM
Title 30, Chapter V, Subchapter B, Part 550
Subpart B--Plans and Information
<bullet> Definitions. (Sec. 550.105)
<bullet> Removal of Sec. 550.204, When must I submit my IOP for
proposed Arctic exploratory drilling operations and what must the
IOP include?
<bullet> How do I submit the EP, DPP, or DOCD? (Sec. 550.206)
<bullet> What must the EP include? (Sec. 550.211)
<bullet> If I propose activities in the Arctic OCS Region, what
planning information must accompany the EP? (Sec. 550.220)
III. Additional Comments Solicited
IV. Procedural Matters
A. Regulatory Planning and Review (E.O. 12866 and 13563)

[[Page 51000]]

B. Reducing Regulatory Burdens (E.O. 14192)
C. Unleashing American Energy and Alaska's Extraordinary
Resource Potential (E.O.s 14153 and 14154)
D. Regulatory Flexibility Act and Small Business Regulatory
Enforcement Fairness Act
E. Unfunded Mandates Reform Act of 1995 (UMRA)
F. Takings Implication Assessment
G. Federalism (E.O. 13132)
H. Civil Justice Reform (E.O. 12988)
I. Consultation with Indian Tribes (E.O. 13175)
J. Paperwork Reduction Act (PRA)
K. National Environmental Policy Act of 1969 (NEPA)
L. Data Quality Act
M Effects on the Nation's Energy Supply (E.O. 13211)
N. National Technology Transfer and Advancement Act (NTTAA)
O. Clarity of Regulations
P. Severability

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 Oil and Gas and Sulfur Operations on
Rule. the Outer Continental Shelf-
Requirements for Exploratory
Drilling on the Arctic Outer
Continental Shelf, see 81 FR 46478,
July 15, 2016 (available at <a href="https://www.federalregister.gov/documents/2016/07/15/2016-15699/oil-and-gas-and-sulfur-operations-on-the-outer-continental-shelf-requirements-for-exploratory">https://www.federalregister.gov/documents/2016/07/15/2016-15699/oil-and-gas-and-sulfur-operations-on-the-outer-continental-shelf-requirements-for-exploratory</a> exploratory)
2020 Proposed Revisions to the Oil and Gas and Sulfur Operations on
Arctic Exploratory Drilling Rule. the Outer Continental Shelf-
Revisions to the Requirements for
Exploratory Drilling on the Arctic
Outer Continental Shelf, see 85 FR
79266, December 9, 2020 (available
at <a href="https://www.federalregister.gov/documents/2020/12/09/2020-25818/oil-and-gas-and-sulfur-operations-on-the-outer-continental-shelf-revisions-to-the-requirements-for#h-63">https://www.federalregister.gov/documents/2020/12/09/2020-25818/oil-and-gas-and-sulfur-operations-on-the-outer-continental-shelf-revisions-to-the-requirements-for#h-63</a> 63)
ABS............................... American Bureau of Shipping
ACP............................... Alternative Compliance Program
ANCSA............................. Alaska Native Claims Settlement Act
APD............................... Application for Permit to Drill
API............................... American Petroleum Institute
Arctic OCS........................ OCS oil and gas planning areas that
include any portion of their
geographic extent located north of
66[deg]33' N latitude
ASME.............................. The American Society of Mechanical
Engineers
AWKS.............................. Alternative Well Kill System
BOEM.............................. Bureau of Ocean Energy Management
BOP............................... Blowout Preventer
Bratslavsky and SolstenXP 2018.... Suitability of Source Control and
Containment Equipment versus Same
Season Relief Well in the Alaska
Outer Continental Shelf Region,
October 2018
BSEE.............................. Bureau of Safety and Environmental
Enforcement
CFR............................... Code of Federal Regulations
CWA............................... Clean Water Act
Department........................ Department of the Interior
DNV GL............................ Det Norske Veritas and Germanischer
Lloyd
DOCD.............................. Development Operations Coordination
Document
DOI............................... Department of the Interior
DPP............................... Development and Production Plan
EA................................ Environmental Assessment
EIA............................... Environmental Impact Analysis
E.O............................... Executive Order
EP................................ Exploration Plan
EPA............................... Environmental Protection Agency
FACA.............................. Federal Advisory Committee Act
G&G............................... Geological and geophysical
IC................................ Information Collection
IOP............................... Integrated Operations Plan
RIA............................... Regulatory Impact Analysis
LMRP.............................. Lower Marine Riser Package
MASP.............................. Maximum Anticipated Surface
Pressures
MMS............................... Minerals Management Service
MODU.............................. Mobile Offshore Drilling Unit
NAICS............................. North American Industry
Classification System
NEPA.............................. National Environmental Policy Act of
1969
NPC............................... National Petroleum Council
NPC 2015 Report................... Arctic Potential: Realizing the
Promise of U.S. Arctic Oil and Gas
Resources
NPC 2019 Report................... Supplemental Assessment to the 2015
Report on Arctic Potential:
Realizing the Promise of U.S.
Arctic Oil and Gas Resources
NPDES............................. National Pollutant Discharge
Elimination System
NTL............................... Notice to Lessees and Operators
OCS............................... Outer Continental Shelf
OCSLA............................. Outer Continental Shelf Lands Act
ODCE.............................. Ocean Discharge Criteria Evaluations
OFR............................... Office of the Federal Register
OIRA.............................. Office of Information and Regulatory
Affairs
OMB............................... Office of Management and Budget
OSRP.............................. Oil Spill Response Plan
OSPD.............................. Oil Spill Preparedness Division
PRA............................... Paperwork Reduction Act
RIN............................... Regulation Identifier Number
ROV............................... Remotely Operated Vehicle
ROT............................... Remotely Operated Tool
RP................................ Recommended Practice

[[Page 51001]]

SCCE.............................. Source Control and Containment
Equipment
Secretary......................... Secretary of the Interior
S.O............................... Secretary's Orders
SEMS.............................. Safety and Environmental Management
Systems
SSID.............................. Subsea Isolation Device
SSRW.............................. Same Season Relief Well
SOO............................... Suspensions of Operations
SOP............................... Suspensions of Production
UMRA.............................. Unfunded Mandates Reform Act of 1995
U.S............................... United States
USCG.............................. U.S. Coast Guard
WCR............................... Well Control Rule
WCD............................... Worst Case Discharge

I. Background

A. BSEE and BOEM Statutory and Regulatory Authority and
Responsibilities

The OCSLA, 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
to lease the OCS for mineral development and to regulate oil and gas
exploration, development, and production operations on the OCS. As
described in case law, ``OCSLA allows the Secretary of the Interior to
regulate oil and gas leasing on the OCS. Id. Sec. 1334(a). He
delegated this power to two subordinate agencies, including [BOEM and
BSEE]. Dep't of Interior, Secretarial Order No. 3299 (May 19, 2010).
Under OCSLA, the Secretary `may at any time prescribe and amend such
rules and regulations as he determines to be necessary and proper in
order to provide for the prevention of waste and conservation of the
natural resources of the [OCS].' 43 U.S.C. 1334(a). The statute
specifies that `[t]he regulations prescribed by the Secretary under
this subsection shall include, but not be limited to' [the prompt and
efficient exploration and development of a lease area] . . . .'' Id.
Sec. 1334(a)(1)-(8).'' Gulf v. Bureau of Ocean Energy Mgmt., 2026 U.S.
Dist. LEXIS 60712, at *2-3 (D.D.C. Mar. 23, 2026).
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 and DOCD
administration; permitting of G&G activities; environmental analyses in
compliance with federal law and regulation; resource evaluation; oil
spill WCD determination; economic analysis and fair market value bid/
lease evaluations; management of the OCS renewable energy and marine
mineral programs; coordination with other entities at the local (e.g.,
North Slope Borough, Native Villages), State, and Federal levels (e.g.,
National Oceanic and Atmospheric Administration Fisheries, USCG), as
well as consultation with federally recognized ANCSA Tribes and
Corporations related to activities within BOEM's activities and areas
of responsibility.
BSEE is responsible for safety and environmental enforcement
functions, including, but not limited to, permitting activities,
inspections, investigations, summoning witnesses and ordering the
production of evidence; levying penalties; canceling or suspending
activities; \3\ compliance with federal environmental laws and
regulations; coordination with other entities at the local (e.g., North
Slope Borough, Native Villages), State, and Federal levels (e.g.,
National Oceanic and Atmospheric Administration Fisheries, USCG), as
well as consultation with federally recognized ANCSA Tribes and
Corporations; and overseeing safety, 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.
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\3\ Based on the plain language of OCSLA section 5, Congress
required the Department to issue regulations concerning suspensions.
``The [OCSLA] regulations prescribed by the Secretary under this
subsection shall include, but not be limited to, provisions . . .
for the suspension or temporary prohibition of any operation or
activity, including production, pursuant to any lease or permit (A)
at the request of a lessee, in the national interest, to facilitate
proper development of a lease or to allow for the construction or
negotiation for use of transportation facilities, or (B) if there is
a threat of serious, irreparable, or immediate harm or damage to
life (including fish and other aquatic life), to property, to any
mineral deposits (in areas leased or not leased), or to the marine,
coastal, or human environment . . . .'' 43 U.S.C. 1334(a)(1).
See also, Hornbeck Offshore Servs., L.L.C. v. Salazar, 696 F.
Supp. 2d 627, 638 (E.D. La. 2010). ``OCSLA permits suspension of
`any operation or activity . . . pursuant to any lease or permit.'
'' (Quoting, 43 U.S.C. 1334(a)(1)).
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BOEM evaluates EPs, and BSEE, thereafter, evaluates 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 the Bureaus' evaluations, they will
respectively either approve the operator's EP and APD, require the
operator to modify its submissions, or disapprove the EP or APD (Sec.
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,
Sec. 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 is 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 (Sec. Sec. 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 exploratory drilling. After BOEM approves the EP, the
operator must submit an APD to BSEE. BSEE then determines whether it
will approve the

[[Page 51002]]

APD. The operator must receive an approval from BSEE before it may
drill a well (43 U.S.C. 1340(d); Sec. 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 BOP systems, MODU (if one is to be
used), and any additional information requested by the BSEE Regional
Supervisor.

B. Executive and Secretary's Orders

On April 28, 2017, the President issued E.O. 13795, Implementing an
America-First Offshore Energy Strategy (see 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 OCS, 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.''
To further implement E.O. 13795, on May 1, 2017, the Secretary
issued S.O. 3350, America-First Offshore Energy Strategy, directing the
Bureaus to review the 2016 Arctic Exploratory 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. 13795 and S.O. 3350, the Bureaus reviewed the
regulations promulgated through the 2016 Arctic Exploratory Drilling
Rule and, on December 9, 2020, issued the 2020 Proposed Revisions to
the Arctic Exploratory Drilling Rule to reduce unnecessary burdens on
industry while maintaining safety and environmental protection. On June
29, 2021, the Bureaus withdrew the proposed rule (see 86 FR 34172) due
to a change in administration and policy, and in response to E.O.
13990, Protecting Public Health and the Environment and Restoring
Science to Tackle the Climate Crisis (see 86 FR 7037), which revoked
E.O. 13795.
In January 2025, the President signed E.O. 14153, Unleashing
Alaska's Extraordinary Resource Potential (see 90 FR 8347) and E.O.
14154, Unleashing American Energy (see 90 FR 8353). E.O. 14153
established new policy for the U.S. to fully avail itself of Alaska's
vast lands and resources for the benefit of the Nation and the American
citizens who call Alaska home. The E.O. called upon the heads of all
executive departments and agencies to rescind, revoke, revise, amend,
defer, or grant exemptions from any and all regulations, orders,
guidance documents, policies, and any other similar agency actions that
are inconsistent with the policy set forth in the E.O. In February
2025, the Secretary issued S.O. 3422, Unleashing Alaska's Extraordinary
Resource Potential, and S.O. 3418, Unleashing American Energy, to
implement the policies set forth in E.O. 14153 and E.O. 14154.
E.O. 14154 outlines a broad federal energy policy aimed at
expanding domestic energy production and reducing regulatory
constraints. The E.O. supports energy exploration and production on
Federal lands and waters, including on the OCS, in order to meet the
needs of our citizens and solidify the U.S. as a global energy leader
long into the future. To that end, it directs all Federal agencies to
review all agency actions, including existing regulations, to identify
those agency actions that impose an undue burden on the identification,
development, or use of domestic energy resources, with particular
attention to, among other resources, oil and natural gas, or that are
otherwise inconsistent with the policies set forth in the E.O. The
Bureaus are proposing the revisions contained in this rulemaking in
response to these recent E.O.s and S.O.s.

C. Purpose and Summary of the Rulemaking

Since publication of the 2016 Arctic Exploratory Drilling Rule, the
Bureaus 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 a 5-year period on
Alaska's Arctic OCS drilling seasons (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, RPs,
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 2018 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 rough sea states) in the
Chukchi Sea, 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 rigs and SCCE is the same. This is because the
Beaufort Sea has fewer ice-free days than the Chukchi Sea and ice helps
maintain calm sea state conditions.
The study also determined that water depth in the Arctic OCS is an
additional factor limiting the safe deployment of SCCE. Safe deployment
of SCCE is likely to be impaired in water depths shallower than 984
feet because the equipment could potentially encounter a gas boil at
the surface caused by a subsea blowing well (Bratslavsky and SolstenXP
2018 at 143). Water depths in the majority of both 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 capabilities of support vessels that could be used for the
safe deployment of SCCE.
The NPC \4\ 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 to
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

[[Page 51003]]

regulatory burdens associated with Arctic OCS development.
---------------------------------------------------------------------------

\4\ The NPC is a FACA-chartered advisory committee established
to provide advice, information, and recommendations to the Secretary
of Energy and the entire Executive Branch on matters related to oil
and natural gas or the oil and gas industries. The council's
membership encompasses all segments of the oil and gas industries,
including both large and small companies. Additionally, the NPC
includes members whose interests extend beyond oil and gas
operations, such as representatives from academic, financial, and
research institutions, Native American groups, and public interest
organizations.
---------------------------------------------------------------------------

Key findings from the NPC's 2019 supplemental assessment include
that the requirement to drill a SSRW to mitigate the risk of a late
season well control event continuing over the winter season is
``outdated.'' The NPC also concluded that SSID 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 2019Report 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. The Kara Sea is a
useful model for technical and operational challenges faced in the U.S.
Arctic OCS. Both areas have similar cold climates, seasonal sea ice,
and are located in isolated geographical regions with limited emergency
response capabilities. Equipment used in the Kara Sea--like SSIDs with
full well shut-in and winter isolation capabilities--could be applied
similarly to proposed operations in the Arctic OCS, given the similar
environmental and operational conditions between the two areas.
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 or operations to initiate production for a significant
portion of the term on a lease. BSEE is also addressing the use of
cranes for operations on artificial islands in the Arctic OCS. BSEE's
existing crane-related regulations expressly address fixed platforms
installed on open waters, which are not the same types of cranes used
on artificial islands. Cranes used on artificial islands are similar to
those used on land, i.e., mobile cranes, which are not fixed in place
(such as on an offshore facility) and may have wheels or tracks so as
to lift and transport materials on location. While these issues are in
addition to those addressed by the 2016 Arctic Exploratory Drilling
Rule, they are unique to the Alaska OCS region and, therefore, are
appropriate to address as part of this proposed rulemaking.
This proposed rule would leave most of the regulations promulgated
by the 2016 Arctic Exploratory Drilling Rule unaltered, except for
certain proposed changes to accommodate technological innovation and
encourage energy exploration on the Arctic OCS. Based on the
information gathered from the Bratslavsky and SolstenXP 2018 study, and
global practical experience gained over the 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-
by-Section Discussion of Proposed Changes of this preamble:
1. Definition of the ``Arctic OCS''--The Bureaus propose to modify
the definition of the ``Arctic OCS'' to include all OCS oil and gas
planning areas that include any portion of their geographic extent
located north of 66[deg]33' N latitude. Although the 1984 Arctic
Research and Policy Act extends the U.S. Arctic boundary to the
Aleutian chain, this proposed rule only applies to planning areas north
of 66[deg]33' N that are subject to and distinguished by persistent
Arctic oceanographic and meteorological conditions. This would mean
that, in addition to the Chukchi Sea and Beaufort Sea planning areas,
the new High Arctic Planning Area and existing Hope Basin Planning Area
would also be part of the Arctic OCS. In April 2025, as part of its
efforts to establish the 11th National OCS Oil and Gas Leasing Program,
BOEM revised the OCS planning areas used for agency planning and
administrative purposes for oil and gas activities to reflect
jurisdictional changes since they were last updated. This included the
establishment of a new High Arctic Planning Area.
2. Pollution Prevention (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 has created some uncertainty for the regulated industry,
because it appeared to overlap with regulation by the EPA and, if
implemented, might result in BSEE issuing requirements that contradict
EPA's requirements.
3. Arctic OCS SCCE--BSEE would preserve the requirement for the
operator to have access to its SCCE, which includes the capping stack,
cap and flow system, and containment dome, when drilling below or
working below the surface casing. However, with respect to the capping
stack, BSEE proposes to modify the equipment's positioning requirement
by providing 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. 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 high-pressured 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 relevant data and information.
The existing regulations also impose a positioning requirement on
the cap and flow system, and the containment dome when drilling below
or working below the surface casing--slightly different from the
capping stack. The cap and flow system and the containment dome must be
``positioned to ensure that it will arrive at the well location within
7 days after a loss of well control.'' BSEE 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 2018 study evaluated industry methods and standards for
deploying SCCE in Arctic OCS conditions, and determined that
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? (Sec. 250.471). It is not practical for the BSEE-
administered 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. BSEE would, however,
retain other existing containment dome and cap and flow system
requirements in Sec. 250.471, which provide that the operator must:

[[Page 51004]]

(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.
These changes 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. BOP Real-time Monitoring Requirements for the Arctic OCS--The
Arctic OCS's BOP real-time monitoring requirements are currently
inconsistent with the general BOP real-time monitoring requirements
that apply throughout the OCS. When the 2016 Arctic Exploratory
Drilling Rule was developed, BSEE was still working to establish
overarching real-time monitoring requirements in 30 CFR 250 subpart G.
Since 2016, these requirements have been revised and fully implemented,
making it unnecessary to maintain separate, duplicative requirements
for the Arctic. As a result, BSEE proposes to align the Arctic's BOP
real-time monitoring with the real-time monitoring requirements
applicable in other parts of the OCS.
5. Relief Rig Capabilities for the Arctic OCS--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. An operator would be able to delay the staging of
its relief rig until its operations have reached the ``last casing
point prior to penetrating a zone capable of flowing hydrocarbons in
measurable quantities,'' rather than below the ``surface casing.'' 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 high-
pressured 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.
6. Mudline Cellars--BSEE proposes to clarify the requirement that
an operator, in areas of ice scour, must 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 Sec. 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.
7. 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. BOEM is proposing to move certain
requirements for the IOP to the information required for EPs and delete
the remaining requirements that were for the IOP only.
8. Seasonal Conditions SOO--The unique seasonal conditions in the
Alaska OCS region 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 section 5,\5\ 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
Alaska, 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
interference by seasonal constraints unique to Alaska.
---------------------------------------------------------------------------

\5\ 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).
---------------------------------------------------------------------------

9. Initial and Continuing Development Obligations Lease
Suspensions--In addition to the proposed SOO, BSEE proposes to add
provisions to suspend unitized Alaska OCS leases greater than five
years in length when it would allow the lessee the time needed to
diligently complete their initial development obligations, or one or
more continuing development obligations approved by the BSEE Regional
Supervisor. These lease suspensions would exempt unitized Alaska OCS
leases from the requirement to provide a commitment to production when
requesting a suspension. The maximum 10-year term issued for Alaska OCS
leases is inadequate to sufficiently explore and develop the resources
on a lease and reach sustained production without the need for one or
more lease suspensions. The isolated nature of the region and the tough
seasonal conditions of the Alaska OCS make data collection, pre-
development planning efforts, and decision-making for the operator
difficult to achieve in a timely manner, and if an operator is able to
progress to the exploratory drilling stage, they face the challenge of
acquiring the drilling rigs or vessels suitable for the area's harsh
conditions. These lease suspensions would provide those operators that
can demonstrate they are working to diligently complete one or more
continuing development

[[Page 51005]]

obligations the time needed to properly develop and establish
production on their unitized Alaska OCS leases.
10. Cranes Used for Operations on Artificial Islands--As discussed
in the next section, BSEE proposes to incorporate by reference into the
regulations the ASME B30.5-2021, Mobile and Locomotive Cranes, which
addresses the construction, inspection, testing, maintenance, and
operation of mobile and locomotive cranes. BSEE's existing crane
regulations apply to fixed platforms installed on open waters, which
are not the same types of cranes used on artificial islands. Cranes
used on artificial islands are like those used on land, i.e., mobile
cranes, which are not fixed in place (such as on an offshore facility)
and may have wheels or tracks to lift and transport materials on
location. Incorporating this technical document into BSEE's regulations
would ensure that consistent, industry-based safety requirements for
cranes used on artificial islands are established.

D. Procedures for Incorporation by Reference and Availability of
Incorporated Documents for Public Viewing

BSEE frequently uses standards (e.g., codes, specifications, and
RPs) and other documents developed by standard development
organizations as a means of establishing requirements for activities on
the OCS. This practice, known as ``incorporation by reference,'' allows
the Department to incorporate the standards from technical documents
into the regulations so that the regulations reflect well accepted
industry standards without increasing the volume of the CFRs. The legal
effect of incorporation by reference is that the incorporated standards
become regulatory requirements. This incorporated material, like any
other regulation, has the force and effect of law. Operators, lessees,
and other regulated parties must comply with the documents incorporated
by reference in the regulations.
The OFR regulations at 1 CFR part 51 govern how BSEE and other
Federal agencies may incorporate documents by reference. Agencies may
incorporate a document by reference by publishing in the Federal
Register the document title, edition, date, author, publisher,
identification number, and other specified information. The preamble of
the proposed rule must also discuss the ways that the incorporated
materials are reasonably available to interested parties and how those
materials can be obtained by interested parties. The Director of the
Federal Register will approve each incorporation of a publication by
reference in a final rule that meets the criteria of 1 CFR part 51.
Incorporation by reference of a document or publication is limited to
the edition of the document or publication cited in the regulations.
This means that newer editions, amendments, or revisions to documents
already incorporated by reference in regulations are not part of BSEE-
administered regulations until they are incorporated by reference.
A standard that is proposed for incorporation by reference is
frequently referred to as a ``1st tier document.'' When a 1st tier
document references another document, the referenced document is
referred to as a ``2nd tier document''; these references are either
considered ``normative'' or ``informative.'' Each has their own
definitions of ``normative'' and ``informative.'' Generally speaking,
compliance with normative references is obligatory to fulfill the
provisions of the standard that cites it, while informative references
provide additional information that supports the 1st tier document. For
example, the API considers compliance with normative references to be
necessary for the fulfillment of the provisions of the primary
reference. Particularly, the API Document Format and Style Manual
(January 2009) and all API standards include the following statement
clarifying the importance of normative references: ``The following
referenced documents are indispensable for the application of this
document.'' The ASME also considers compliance with normative
references as necessary for complying with the primary reference.
Standards incorporated from the ASME contain a statement that normative
references are indispensable for the application of the primary
standard.
When a copyrighted publication is incorporated by reference into
BSEE's regulations, the bureau is obligated to observe and protect that
copyright. BSEE provides members of the public with website addresses
where these standards may be accessed for viewing--sometimes for free
and sometimes for a fee. Standards development organizations decide
whether to charge a fee. The regulations governing incorporation by
reference under 1 CFR part 51 provide that publications are eligible
for incorporation by reference if they are ``reasonably available to
and usable by the class of persons affected.'' (See 1 CFR 51.7(a)(3)).
BSEE is proposing to incorporate by reference for the first time
into the regulations the requirements found in the American Society of
Mechanical Engineers B30.5-2021, Mobile and Locomotive Cranes--Safety
Standard for Cableways, Cranes, Derricks, Hoists, Hooks, Jacks, and
Slings; 2021 Edition, December 17, 2021. This standard contains
provisions that address the construction, installation, operation,
inspection, testing, maintenance, and use of cranes and other lifting
and material-movement-related equipment. It applies to crawler cranes,
locomotive cranes, wheel-mounted cranes, and any variations thereof
that retain the same fundamental characteristics, and are basically
powered by internal combustion engines or electric motors. However,
side-boom tractors and cranes designed for railway and automobile wreck
clearance, digger derricks, cranes manufactured specifically for, or
when used for, energized electrical line service, knuckle boom, trolley
boom cranes, and cranes having a maximum rated capacity of 1 ton or
less are outside the scope of this standard.
ASME standards can be accessed at <a href="http://www.asme.org">http://www.asme.org</a> or by phone:
1-800-843-2763. However, for the convenience of members of the viewing
public who may not wish to purchase copies or view the ASME technical
document online, the document may be inspected by appointment at BSEE's
offices at 45600 Woodland Road, Sterling, Virginia 20166, or 1919 Smith
Street, Suite 14042, Houston, Texas 77002. To make an appointment to
inspect the material proposed for incorporation at the Houston BSEE
office, call 1-844-259-4779. An appointment is required to ensure
personnel are available to accommodate the request and to account for
competing agency obligations or concerns, including those related to
public health and natural disasters.
BSEE is also proposing to add an express reference to API
Recommended Practice (RP) 17H, Remotely Operated Tools and Interfaces
on Subsea Production Systems, Second Edition, June 2013; Errata,
January 2014, in proposed Sec. 250.472. This RP provides
recommendations for the development and design of remotely operated
subsea tools and interfaces on subsea production systems in order to
maximize the potential of standardizing equipment and design
principles. This document does not cover manned intervention, internal
wellbore intervention, internal flowline inspection, tree running, and
tree running equipment. However, all the related subsea ROV/ROT
interfaces are covered by this standard. It is applicable to the
selection, design, and operation of ROTs and ROVs, including ROV
tooling.

[[Page 51006]]

BSEE has reviewed the requirements in ASME B30.5-2021 and API RP
17H, and proposes to incorporate ASME B30.5-2021 by reference into the
regulations for the first time, and add an express reference to API RP
17H in proposed Sec. 250.472 to ensure that industry uses the best
available safety technologies on the OCS.

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 notice. 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. The BSEE-administered and BOEM-
administered regulations are found in the CFR at Title 30--Mineral
Resources, Volume 2; BSEE-administered regulations are in Chapter II,
and BOEM-administered regulations are in Chapter V.

A. Revisions Proposed by BSEE

Title 30, Chapter II, Subchapter B, Part 250
Oil and Gas and Sulphur Operations in the Outer Continental Shelf
Subpart A--General
Definitions. (Sec. 250.105)
BSEE proposes to modify the definition of ``Arctic OCS'' to mean
all OCS oil and gas planning areas that include any portion of their
geographic extent located north of 66[deg]33' N latitude. This proposed
change would make the new High Arctic Planning Area and existing Hope
Basin Planning Area parts of the Arctic OCS, thus, subjecting them to
the requirements promulgated by the 2016 Arctic Exploratory Drilling
Rule and the changes proposed in this rulemaking, thereby aligning the
regulation of exploration activities in those areas with the Beaufort
Sea and Chukchi Sea planning areas. The proposed designation of
``Arctic OCS'' as north of 66[deg]33' N is merely for functional
purposes, to identify the OCS oil and gas planning areas that define
the scope of where the requirements of this rulemaking and the 2016
Arctic Exploratory Drilling Rule would apply. The High Arctic and Hope
Basin planning areas experience the same type of Arctic weather
conditions, i.e., extreme cold, freezing spray, snow, and sea ice, as
the Beaufort Sea and Chukchi Sea planning areas. Therefore, BSEE
proposes to expand the definition of the ``Arctic OCS'' to make the
development requirements for all four planning areas consistent. As
BOEM has acknowledged throughout the planning process for the 11th
National OCS Oil and Gas Leasing Draft Proposed Program, BOEM estimates
the High Arctic to have negligible resource quantities and Hope Basin
to have measured resource potential but negligible development value.
BSEE also proposes to make a modification to the definition of
``Arctic OCS conditions.'' In the definition, BSEE proposes to replace
``on the Arctic OCS'' at the end of the first sentence with
``throughout the Alaska OCS region.'' BSEE would also replace
``characteristic of the Arctic region'' at the end of the last sentence
with ``characteristics present throughout the Alaska OCS region.''
These proposed changes recognize that extreme cold, freezing spray,
snow, extended periods of low light, strong winds, dense fog, sea ice,
strong currents, and dangerous sea-state conditions are not only
experienced in Arctic waters. They may also occur throughout the Alaska
OCS region.
Finally, 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 pre-positioned'' to the capping stack
definition (see 81 FR 46492).
As a practical matter, pre-positioned capping stacks are similar,
but not the same, as SSIDs. Accordingly, this modification that was
included 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 Sec. 250.471, What are the
requirements for Arctic OCS source control and containment? Section
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 Sec. 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
pre-positioned capping stack is a piece of equipment that is similar to
and aligns closely with an SSID. Given that BSEE is currently proposing
distinct SSID requirements under Sec. 250.472, What are the additional
well control equipment or relief rig requirements for the Arctic OCS?,
the proposed revision to the capping stack definition would provide
clarity concerning the capping stack requirements under Sec. 250.471.
More specifically, installation of an SSID under Sec. 250.472 does not
constitute compliance with the capping stack requirements under Sec.
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.
What requirements must I follow for cranes and other material-handling
equipment? (Sec. 250.108)
Section 250.108 currently requires operators and lessees to comply
with crane-specific provisions to ensure the safe design, construction,
and testing of all cranes mounted on any fixed platform installed on
the OCS. These requirements include, but are not limited to, compliance
with the API RP 2D, Operation and Maintenance of Offshore Cranes and
API RP 2C, Specification for Offshore Pedestal Mounted Cranes, which
requires cranes to be equipped with a functional anti-two block device,
and the management of records related to the operations of those
cranes.
BSEE proposes adding a new paragraph (g) to Sec. 250.108 that
would require all cranes positioned on artificial islands on the Alaska
OCS to meet the requirements of ASME B30.5-2021. BSEE also proposes to
modify:
(1) paragraph (b) to apply the requirement for cranes to be
equipped with a functional anti-two block device to ``OCS artificial
islands;'' and
(2) paragraph (e) to make the requirement to retain all design and
construction records for the life of the crane, all inspection,
testing, and maintenance records for at least 4 years, and the
qualification records of the crane operator and all rigger personnel
for at least 4 years applicable to cranes used on ``OCS artificial
islands.''
BSEE is proposing these modifications since the regulations

[[Page 51007]]

currently do not address cranes used on artificial islands on the OCS.
In more recent years, exploration activities on the Arctic OCS have
focused primarily on development from these man-made features. These
proposed changes would ensure the safe design, construction, and
testing of all cranes positioned on OCS artificial islands is being
applied consistently, based on best available technologies.
How long does a suspension last? (Sec. 250.170)
Section 250.170 specifies the length of time BSEE may issue a
suspension, which is 5 years per suspension, and describes the effect
of a suspension once it is granted, ends, or is terminated. BSEE
proposes to add a new provision in a new paragraph (f) to Sec. 250.170
that provides the Alaska OCS Regional Supervisor with the authority to
determine the length of an SOP for unitized leases in the Alaska OCS
and would not subject these leases to the 5-year suspension timeframe
currently described in this section. The length of the suspension would
be the amount of time the Regional Supervisor agrees is needed to
complete initial development obligations or continuing development
obligations justified by the lessee to ensure the maximum economic
recovery of unitized OCS lease resources to BSEE's satisfaction. BSEE's
determination would be based on the information the operator submits as
part of its suspension request, as well as any information about other
relevant associated development activities in proximity to the leases
covered under the suspension request.
``Continuing development obligations'' means a program of
development activities or operations an operator conducts that, after
the operator completes the initial development obligations defined in a
unit agreement or otherwise agreed to by the Regional Supervisor: (1)
meets or exceeds the rate of development activities or operations in
the vicinity of the unit; and (2) represents an investment
proportionate to the size of the area covered by the unit agreement.
Initial development obligations are a planned program of exploration
activities that, when completed, would allow the operator to estimate
the size and shape of the reservoir within the unit area and understand
the geologic conditions existing within the reservoir and unit area.
Initial development obligations are completed before continuing
development obligations.
For example, an initial development obligation could include:
(i) the number of wells to be drilled that an operator anticipates
will be necessary to assess the reservoir adequately;
(ii) the primary target for each well, a schedule for starting and
completing drilling operations for each well; and
(iii) the time between starting operations on a well to the start
of operations on the next well.
Continuing development obligations are activities that would be
performed after the operator completes its initial development
obligations, which, for example, could include:
(i) drilling, testing, or completing additional wells to the
primary target or other unit formations;
(ii) drilling or completing additional wells that establish
production of oil and gas;
(iii) recompleting wells or other operations that establish new
unit production; or
(iv) drilling existing wells to a deeper target.
As previously mentioned, the isolated nature and tough seasonal
conditions of the Alaska OCS region present multiple challenges that
make it difficult to initiate production within the current 10-year
timeframe of a lease. This proposed provision would allow the Regional
Supervisor to determine the appropriate length of a suspension that
would be necessary to complete proper development and initiate
production on a unitized Alaska OCS lease without having to rely on the
limits of the 5-year timeframe specified in this section, which may be
more applicable to other OCS regions.
How do I request a suspension? (Sec. 250.171)
This section specifies the information that must be included in a
suspension request, which includes a commitment to production for SOP
requests. BSEE proposes adding a provision for unitized Alaska OCS
leases that requires the operator to include a commitment to complete
the initial development obligations identified in its unit agreement or
otherwise approved by the Regional Supervisor. The commitment must
include, at minimum, drilling the producible well, as required by
250.171(c), and any additional initial development activities or
operations that the Regional Supervisor agrees are necessary to
sufficiently explore the lease and justify the lease earning the
benefits of unitization. In the case of continuing development
obligations, BSEE would require the operator to include a commitment to
complete one or more continuing development obligations that the
Regional Supervisor agrees are necessary to properly develop the lease.
BSEE would also modify existing paragraph (d) to clarify that the
commitment to production referenced in this paragraph applies to SOPs
for leases that are not unitized Alaska OCS leases.
This provision would allow the operator to request a suspension for
their unitized Alaska OCS leases if it is able to provide a commitment
to complete its initial development obligations or one or more of its
continuing development obligations. BSEE has existing guidance on what
constitutes such a commitment, as outlined in NTL 2019-G01. Based on
guidance from this NTL, examples of commitment may include: (1) a final
investment decision by the operator, (2) evidence that the venture will
be economically viable, (3) a written agreement or contract with any
third parties (such as pipeline companies or minority lessees) whose
resources are required for production to occur, and (4) geologic or
reservoir information that BSEE would need for evaluating the economic
viability. After the promulgation of this rule, the NTL would be
updated to include information relevant to phased development as
established under the proposed SOP. BSEE would consider granting a
suspension if the operator is able to demonstrate a commitment to
continued diligent development to ensure the maximum economic recovery
of unitized OCS lease resources, which may be longer than 5 years. This
provision could provide the certainty operators may need to commit
their resources in an area with extremely high investment risks for
success.
When may the Regional Supervisor grant or direct an SOP? (Sec.
250.174)
This section lists the criteria under which BSEE may grant or
direct an SOP when the suspension is in the National interest. BSEE
proposes adding a new criterion under proposed paragraph (e) for units
on the Alaska OCS whereby the Regional Supervisor may grant a
suspension if it allows the operator time to complete its initial
development obligations, or one or more continuing development
obligations. When an SOP is granted under proposed paragraph (e), only
the requirement to produce the undeveloped or underdeveloped lease(s)
would be suspended. As proposed, the lessee may continue to produce
from the properly developed unitized lease(s) as long as production
complies with 250.172(b) and production activities prevent waste,
conserve natural resources, and protect correlative rights, including
Federal royalty interests, of a

[[Page 51008]]

reasonably delineated and productive reservoir.
When may the Regional Supervisor grant an SOO? (Sec. 250.175)
BSEE proposes to revise Sec. 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 leases or units throughout the Alaska
OCS Region. This proposed revision is consistent with OCSLA's
requirement that the Secretary promulgate suspensions regulations that
``facilitate proper development of a lease . . . .'' \6\ The proposed
regulation would list the factors upon which BSEE may rely when
determining whether to grant an SOO and include when an operator:
---------------------------------------------------------------------------

\6\ OCSLA sec. 5, 43 U.S.C. 1334(a)(1).
---------------------------------------------------------------------------

(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:
(i) a MODU,
(ii) an artificial gravel island or a gravity-based structure, or
(iii) 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 OSRP, 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.\7\ 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 in the Alaska OCS can be
inaccessible for a significant portion of each year, due to seasonal
changes that make operating conditions unsafe or otherwise preclude
operations. While BOEM cannot award leases with more than the maximum
10-year primary lease term allowed under OCSLA, the Secretary's
statutorily delegated authority referenced above at 43 U.S.C.
1334(a)(1) allows for suspensions in certain circumstances that have
the effect of extending the lease term by a period equivalent to the
period of such suspension. This authority has been redelegated to BSEE,
to administer suspensions that can address and mitigate, as
appropriate, the effects of Arctic working conditions when they may
limit the operator's ability to perform leaseholding activities for
much of the year. See also 30 CFR 556.601(f) (How may I maintain my oil
and gas lease beyond the primary term?). Paragraph (f) of 30 CFR
556.601 references BSEE-administered suspension regulations at 30 CFR
250.168 through 250.180, in which Sec. 250.169(a) clarifies that a
suspension may extend the term of a lease and that the extension is
equal to the length of time the suspension is in effect, with respect
to operator-requested suspensions. This proposed rule clarifies the
factors that can be considered when issuing such suspensions.
---------------------------------------------------------------------------

\7\ 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).
The primary term commences on the effective date of the lease
(rather than on a calendar year basis). 30 CFR 556.521. The lease
may be maintained beyond the primary term in accordance with 30 CFR
556.601.
---------------------------------------------------------------------------

MODUs--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 non-existent or minimal. This practical
limitation, without considering other logistical problems unique to the
Alaska OCS, could mean that during a consecutive 10-year period, a
lease may be unavailable for operations for up to 70 percent of the
time.
Artificial Gravel Islands or Gravity-based Structures--Drilling
from artificial gravel islands and gravity-based structures is
prohibited during the spring/summer ice break-up and the fall/early
winter freeze-up periods due to potential interferences that weather
and ice conditions may have 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 cleanup efforts
for a large oil spill from an artificial gravel island or a gravity-
based 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 gravity-
based 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 one or more steel drilling caissons.
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 Sec. 250.175 would facilitate the proper
development of a lease by addressing those seasonal conditions that
limit leaseholding operations and 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 is contemplating the option of limiting the period for when
the suspension would remain in effect to assure commencement of
appropriate lease holding activities. The suspension would remain in
effect 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 appropriate operations occur for
lease exploration and development.
Documents Incorporated by Reference. (Sec. 250.198)
BSEE proposes to incorporate by reference ASME B30.5-2021, Mobile
and Locomotive Cranes--Safety

[[Page 51009]]

Standard for Cableways, Cranes, Derricks, Hoists, Hooks, Jacks, and
Slings; 2021 Edition, December 17, 2021, for the first time into the
regulations as a new paragraph (f)(4) to Sec. 250.198. ASME B30.5-2021
is an industry standard that addresses the construction, installation,
operation, inspection, testing, maintenance, and use of cranes and
other lifting and material-movement-related equipment operating on
artificial islands on the Arctic OCS. In connection with this new
incorporation by reference, BSEE would specify in the new paragraph
(f)(4) that ASME B30.5-2021 is expressly referenced in proposed Sec.
250.108(g) (``What requirements must I follow for cranes and other
material-handling equipment?'').
BSEE also proposes to add, in existing paragraph (e)(2)(i)(HH) of
Sec. 250.198, a reference to proposed Sec. 250.472(a). One of the
features in BSEE's proposed revisions to the existing relief rig and
SSRW requirements in Sec. 250.472, 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? (Sec.
250.472) section-by-section discussion, is a requirement for the SSID
to include ROV intervention equipment that has the capabilities to
function as the SSID. Under proposed Sec. 250.472(a)(3)(ii),
specifically, BSEE would require the ROV to have panels that are
compliant with API RP 17H to ensure that the operator's ROV
capabilities for the SSID follow BSEE's existing ROV panel requirements
for BOP systems. Adding a reference to Sec. 250.472(a) in Sec.
250.198(e)(2)(i)(HH) makes clear as to where API RP 17H would be
codified in the BSEE-administered regulations.
Subpart C--Pollution Prevention and Control
Pollution Prevention. (Sec. 250.300)
BSEE proposes to revise paragraphs (b)(1) and (b)(2) of Sec.
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 Sec. 250.300(b)(1) and (b)(2) that operators
capture all petroleum-based mud and associated cuttings while operating
on the Arctic OCS.
Existing Sec. 250.300(b)(1) and (b)(2) state that the BSEE
Regional Supervisor may exercise his or her discretionary authority to
restrict discharges of water-based 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 (b)(2) of
this section in light of EPA's authority to address water-based muds
and cuttings discharges. The CWA (Section 301(a), 33 U.S.C. 1311(a))
provides EPA with the authority to issue 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 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 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. 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.
When considering the multiple environmental factors under the ODCE for
the 2012 general permits (i.e., potential impacts on human health
through direct and indirect pathways, and the importance of the
receiving water area to the surrounding biological community), EPA
considered how discharges could impact subsistence activities, marine
resources, and coastal areas. The Beaufort Sea permit \8\ does not
allow the discharge of water-based muds and cuttings during the fall
bowhead whale hunt. However, the Chukchi Sea permit \9\ 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.\10\
---------------------------------------------------------------------------

\8\ <a href="https://www.epa.gov/sites/production/files/2017-12/documents/r10-npdes-beaufort-oil-gas-gp-akg282100-final-permit-2012.pdf">https://www.epa.gov/sites/production/files/2017-12/documents/r10-npdes-beaufort-oil-gas-gp-akg282100-final-permit-2012.pdf</a>.
\9\ <a href="https://www.epa.gov/sites/production/files/2017-12/documents/r10-npdes-chukchi-oil-gas-gp-akg288100-final-permit-2012.pdf">https://www.epa.gov/sites/production/files/2017-12/documents/r10-npdes-chukchi-oil-gas-gp-akg288100-final-permit-2012.pdf</a>.
\10\ <a href="https://www.epa.gov/sites/production/files/2017-12/documents/r10-npdes-chukchi-oil-gas-gp-akg288100-odce-2012.pdf">https://www.epa.gov/sites/production/files/2017-12/documents/r10-npdes-chukchi-oil-gas-gp-akg288100-odce-2012.pdf</a>. pp.
6-14 to 6-17.
---------------------------------------------------------------------------

Under this proposed rule, BSEE would preserve the requirements in
Sec. 250.300(b)(1) and (b)(2) that the operator capture all petroleum-
based mud and associated cuttings. This requirement is consistent with
a longstanding, OCS-wide 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 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 petroleum-based 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
Sec. 250.300(b)(1) and (b)(2) are not necessary. In particular, the
EPA already addresses the goals of protecting water quality

[[Page 51010]]

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 Sec. 250.300(b)(1) and (b)(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 (b)(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 (see 81 FR 46505). Given the policy in E.O. 14153 for all
Federal agencies to fully avail itself of Alaska's vast lands and
resources for the benefit of the Nation and the American citizens who
call Alaska home, and the E.O.'s direction to rescind, revoke, revise,
amend, defer, or grant exemptions from any and all regulations, orders,
guidance documents, policies, and any other similar agency actions that
are inconsistent with the policy set forth in the E.O., it is
appropriate to propose eliminating the water-based mud, and associated
cuttings, provisions in Sec. 250.300(b)(1) and (b)(2).
This proposed regulatory change does not suggest any change in
BSEE's recognition that it has a regulatory responsibility to ensure
that operators conduct oil and gas exploration and production
activities on the OCS in a safe and environmentally responsible manner
pursuant to OCSLA. Therefore, the proposed rule would not alter the
longstanding regulation at Sec. 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 Sec. 250.300(b)(1),
BSEE would be able to determine whether there is a need to require
operators to 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 (see 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
Sec. 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'' petroleum-based mud to prevent their
discharge into the marine environment. BSEE proposes to replace the
word ``utilize'' with ``use'' to improve the readability of the
regulation.
Subpart D--Oil and Gas Drilling Operations
What are the real-time monitoring requirements for Arctic OCS
exploratory drilling operations? (Sec. 250.452)
BSEE proposes to remove all provisions in Sec. 250.452 and require
operators to simply follow the BOP real-time monitoring requirements in
Sec. 250.724, which contains the real-time monitoring requirements for
subsea BOPs and surface BOPs used in other parts of the OCS. In
conjunction with this proposed change, BSEE also proposes to modify
paragraph (a) of Sec. 250.724 by adding ``all Arctic OCS drilling
operations'' to the list of environments/cases where BOP real-time
monitoring requirements would apply.
The Arctic OCS's BOP real-time monitoring requirements were
initially established as part of the 2016 Arctic Exploratory Drilling
Rule. The provisions in Sec. 250.452 were tailored to be consistent
with the real-time monitoring requirements established by the BOP
Systems and WCR promulgated that same year (see 81 FR 25888). However,
since 2016, the WCR's real-time monitoring requirements in Sec.
250.724 have been updated, but without a consistency-update to the
Arctic OCS's BOP real-time monitoring requirements. It is not necessary
to have two separate real-time monitoring requirements for BOPs used on
the OCS. Therefore, BSEE proposes to update BOP real-time monitoring
requirements for the Arctic OCS to be consistent with the Bureau's
overall BOP real-time monitoring requirements in Sec. 250.724.
What additional information must I submit with my APD for Arctic OCS
exploratory drilling operations? (Sec. 250.470)
BSEE proposes to revise paragraph (b) of Sec. 250.470 by adding
paragraph (13) to include ``Recover the subsea isolation device (SSID),
where applicable.'' This revision is necessary to address the SSID
alternative proposed in Sec. 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 operator will handle
it, prior to and after drilling operations. We also propose minor, non-
substantive edits to paragraphs (b)(11) and (12) to accommodate this
addition.
BSEE also 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
substantive changes BSEE is proposing to Sec. 250.471, which
establishes the substance of the Arctic OCS SCCE requirements.
Paragraph (f)(3) of Sec. 250.470 complements Sec. 250.471, by
requiring the operator, in cases where it obtains SCCE capabilities
through contracting, to provide proof of contracts or membership
agreements with cooperatives, service providers, or

[[Page 51011]]

other contractors. This includes information demonstrating the
availability of the personnel and/or equipment on a 24-hour per day
basis during operations ``below the surface casing.'' The proposed
changes to Sec. 250.471 are discussed in further detail below.
Finally, BSEE proposes to add a new paragraph (h) to complement the
proposed revisions to Sec. 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 well design (including casing and
cementing program) meet the design requirements in proposed Sec.
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 Sec. 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.
What are the requirements for Arctic OCS source control and
containment? (Sec. 250.471)
Section 250.471(a) currently requires the operator to have access
to the SCCE described in subparagraphs (a)(1) to (a)(3), which must be
capable of stopping or capturing the flow of an out-of-control well if
the operator will be using a MODU when drilling below or working below
the surface casing. Subparagraph (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.
Subparagraphs (a)(2) and (a)(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 Sec. 250.471 by:
(i) Adding a new provision to paragraph (a) that would allow the
operator to, subject to BSEE's determination, delay access to its SCCE
until operations have reached the last casing point prior to
penetrating a zone capable of flowing hydrocarbons in measurable
quantities provided that the operator submits adequate documentation
(such as, but not limited to, risk modeling data, off-set well data,
analog data, seismic data), with its APD, demonstrating that they will
not encounter any abnormally high-pressured zones or other geologic
hazards. This provision would make clear that BSEE will base its
determination on any documentation the operator provides, as well as
any other available data and information.
(ii) Replacing the language in paragraph (a) stating ``capable of
stopping or capturing the flow of an out-of-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
(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 (a)(3), which apply to the cap
and flow system and containment dome, respectively.
The changes described in item (i) in 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 high-pressured 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 subparagraph (a)(1) and proposed subparagraphs (a)(2) and
(a)(3), when drilling or working below the surface casing. While BSEE
does not propose changes to the capping stack provision in subparagraph
(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 described in item (ii) above are
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., Sec. 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 described in item (iii) above 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 subparagraphs (a)(2)
and (a)(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 regulations (i.e., Sec. 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. Additional information regarding BSEE's proposed revisions
to Sec. Sec. 250.471(a)(2) and 250.471(a)(3) are discussed in the
subsection below, entitled, Revisions to the Cap and Flow System, and
Containment Dome Requirements.
<bullet> Revisions to the Capping Stack Requirements
BSEE's proposed revisions to the capping stack requirements in
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.
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

[[Page 51012]]

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, 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, non-productive 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 a location within proximity to the
drilling location so as to be able to arrive within 24 hours of a
blowout. 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.
The criteria BSEE proposes to rely on to determine whether to grant
an exception (i.e., operator demonstrates to BSEE that it will not
encounter ``abnormally high-pressured zones or other geologic
hazards'') 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, i.e., loss of well control. The
capping stack must 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 criteria, other
than ``abnormally high-pressured 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, off-set 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 Arctic OCS. 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

[[Page 51013]]

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.
<bullet> Revisions to the Cap and Flow System, and Containment Dome
Requirements
As described at the beginning of this section-by-section
discussion, Sec. 250.471, BSEE is also proposing to revise paragraphs
(a)(2) and (a)(3) to 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, but still 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 Sec. 250.471.\11\
---------------------------------------------------------------------------

\11\ Existing Sec. 250.105 defines Cap and flow system and
Capping stack.
---------------------------------------------------------------------------

The changes proposed in paragraphs (a)(2) and (a)(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 Sec. 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 Sec. 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.
Since the promulgation of the 2016 Arctic Exploratory Drilling
Rule, the cap and flow system and containment dome have not been needed
to respond to a loss of well control event in the Arctic OCS. If Arctic
OCS exploration/production activities do increase at the rates
described in the RIA, there is potential for an increase in the risk of
longer duration oil spills if an event were to occur and this equipment
may be needed. Thus, the cost savings and forgone benefits should be
considered in that context.
BSEE proposes to remove the cap and flow system and containment
dome 7-day arrival timing requirements based on the Bratslavsky and
SolstenXP 2018 study, which determined that the time periods when SCCE
may be safely deployed throughout the Arctic OCS is limited based on
typical Arctic conditions. In the Chukchi Sea, 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 late-August and
early- to mid[hyphen]October in the historically active exploration
area. Beyond that, the probability for safe SCCE deployment decreases
rapidly in 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[hyphen]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). In April of 2020, the only leases
with potential projects that would be subject to the Arctic OCS's SCCE
requirements were relinquished.\12\ These leases were located in the
Beaufort Sea in water depths less than approximately 170 feet deep.
This water depth range limits the capabilities 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[hyphen]deployment technology to

[[Page 51014]]

remotely position SCCE over the blowing well in shallow water (id. at
A-35).
---------------------------------------------------------------------------

\12\ There are other 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).
---------------------------------------------------------------------------

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 (see 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 (see 81 FR 46520).
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 the study it commissioned to
Bratslavsky Consulting Engineers, Inc., and SolstenXP, Inc. According
to the Bratslavsky and SolstenXP 2018 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 2018 study when finalizing the 2016 Arctic Exploratory
Drilling Rule. BSEE's proposed changes to Sec. 250.471(a)(2) and
(a)(3) for the containment dome and cap and flow system responds to the
information it has gathered from the study.
BSEE recognizes that Bratslavsky and SolstenXP 2018 study data are
now over a decade old. Since then, there may have been changes in U.S.
and international regulations, standards, recommended practices,
specifications, technical reports and common industry methods regarding
the safe deployment of SCCE versus a relief well in Arctic conditions.
Furthermore, data of the Arctic OCS's 2012 to 2016 drilling seasons in
the Beaufort and Chukchi Seas, and the resulting operating scenarios,
could be updated to provide additional insight to the forecast for the
RIA. BSEE will continue to review the Bratslavsky and SolstenXP 2018
study to ensure it remains relevant to the proposed provisions of this
rulemaking.
In light of these findings, BSEE proposes the revisions under Sec.
250.471 to the containment dome and cap and flow system deployment
requirements in paragraphs (a)(2) and (a)(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. 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).\13\
---------------------------------------------------------------------------

\13\ For example, the capping stack technology was used to shut-
in the Macondo well during the Deepwater Horizon incident.
---------------------------------------------------------------------------

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 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 (a)(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 Sec. 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 regulatory 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

[[Page 51015]]

consistency with BSEE's proposed revision to the definition of a
capping stack in Sec. 250.105 and the new SSID alternative BSEE is
proposing under Sec. 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 pre-positioned capping stacks to be
used below subsea BOPs when deemed technically and operationally
appropriate.
What are the additional well control equipment or relief rig
requirements for the Arctic OCS? (Sec. 250.472)
Paragraph (b) of Sec. 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-of-control 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 Sec. 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 Sec. 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
Sec. 250.472;
(iv) Adding a new provision that would apply if the operator elects
to have access to a relief rig, allowing the operator to, subject to
BSEE's determination, delay having access to the rig until operations
have reached the last casing point prior to penetrating a zone capable
of flowing hydrocarbons in measurable quantities provided that the
operator submits adequate documentation (such as, but not limited to,
risk modeling data, off-set well data, analog data, seismic data), with
its APD, demonstrating that they will not encounter any abnormally
high-pressured zones or other geologic hazards; and
(v) Eliminating the reference to expected seasonal ice encroachment
at the drill site, which applies to relief rig operations.
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 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.'' 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 Sec. 250.472 by Using an SSID
and Proposed Paragraph (b)--Complying with Sec. 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 Sec. 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 BSEE promulgated the 2016 Arctic Exploratory Drilling Rule, it
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 exploratory drilling
operations 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 2016 Arctic
Exploratory Drilling Rule's proposed rule (see 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 Sec. 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 other information regarding the
current relief rig and SSRW requirements in Sec. 250.472. BSEE used
the following information when developing the proposed requirements of
this section:

[[Page 51016]]

<bullet> 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 and Gas Resources.'' The
supplemental assessment evaluated 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).
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 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 America 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 America.
In the Arctic OCS, exploratory drilling operations conducted from MODUs
have taken place in waters less than 200 feet. In the Gulf of America,
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 America, 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.
<bullet> Suitability of SCCE Versus SSRW in the Alaska OCS Region
(Bratslavsky and SolstenXP 2018 Study)
In addition to the NPC 2019 Report, BSEE also considered
information about SSIDs through the Bratslavsky and SolstenXP 2018
study, discussed in the previous section in connection with the
proposed changes to the current Arctic OCS source control and
containment requirements in Sec. 250.471. As previously mentioned, the
Bratslavsky and SolstenXP 2018 study entailed a comprehensive review
and gap analysis of U.S. and international regulations, standards, RPs,
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 2018 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 2018 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 2018 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[hyphen]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 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 AWKS, which had two
shear rams that were capable of simultaneously shearing and sealing
heavier wall, larger diameter tubulars, and casings than was possible

[[Page 51017]]

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 2018 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 Sec. 250.471. As discussed in the 2016 Arctic
Exploratory Drilling Rule, 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). This rulemaking remains consistent with those objectives.
The SSID, well design, and BOPs, along with the capping stack
positioning requirement (which would be not be eliminated as part of
this rulemaking), are those redundant protective measures that serve as
controls and barriers, or immediate response mechanisms that prevent or
minimize the likelihood of loss of well control.
Other pertinent information from the Bratslavsky and SolstenXP 2018
study includes the statistical analysis of the Arctic OCS's 2012 to
2016 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 ABS and DNV GL, indicates the
vessel's capabilities. As ice concentrations increase, a vessel's
efficiency decreases. (Bratslavsky & SolstenXP 2018 at 23).
The study notes that the 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 vessels are used as
part of the drilling 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 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 2018 study, and BSEE's consideration of that
information, BSEE proposes to revise Sec. 250.472 in the following
manner:
<bullet> Proposed Paragraph (a)--Complying With Sec. 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.\14\ 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 (see 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 (see 81 FR 46531). Since the
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.
---------------------------------------------------------------------------

\14\ 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.'')
---------------------------------------------------------------------------

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, including the SSID's redundant control system
(i.e., under proposed Sec. 250.472(a)(2)(ii)) and subsea accumulators
(i.e., under proposed Sec. 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 Sec. 250.472. BSEE has determined that its

[[Page 51018]]

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
others' 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 Bratslavsky
and SolstenXP 2018 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, 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 Sec. 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 Sec. 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 shut-in. 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., prevents gas
migration in the shut-in wellbore). If the wellbore is compromised
during or after a full shut-in, an underground blowout or broach to the
seafloor may occur. BSEE reviewed available incident data on loss of
well control events,\15\ and determined that, on average, three loss of
well control events occurred each year on the OCS between 2007 and
2023, none of which occurred in the Arctic OCS.
---------------------------------------------------------------------------

\15\ See, BSEE's website at <a href="https://www.bsee.gov/stats-facts/offshore-incident-statistics">https://www.bsee.gov/stats-facts/offshore-incident-statistics</a>.
---------------------------------------------------------------------------

In addition, BSEE's predecessor, MMS, published a paper in July/
August of 2007 entitled, ``Absence of fatalities in blowouts
encouraging in MMS study of OCS incidents 1992-2006.'' You may download
and view the paper at <a href="http://drillingcontractor.org/dcpi/dc-julyaug07/DC_July07_MMSBlowouts.pdf">http://drillingcontractor.org/dcpi/dc-julyaug07/DC_July07_MMSBlowouts.pdf</a>. The paper summarizes MMS'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.
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 shut-in 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,

[[Page 51019]]

some of the liquid may bleed into the open formation(s). Eventually,
the 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
Sec. 250.472 contemplates allowing the operator to leave a well shut-
in from one open-water 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:
(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.
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., BOP).
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
metal-to-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 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:
(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 (remotely operated vehicle) 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 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 Sec. 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 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 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:
(i) Be able to close each shear ram under the MASP, as defined for
the operation;

[[Page 51020]]

(ii) Include an ROV panel that is compliant with API RP 17H
(incorporated by reference, see Sec. 250.198);
(iii) Meet the ROV requirements in existing Sec. 250.734(a)(5);
and,
(iv) 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 Sec. 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 Sec. 250.472(a)(3) to Sec.
250.198(e)(2)(i)(HH). Section 250.198(e)(2)(i)(HH) documents the
locations in the regulations where API RP 17H is incorporated by
reference as a regulatory requirement, which would include Sec.
250.472(a)(3) under this proposed rule. Adding the citation for Sec.
250.472(a)(3) to Sec. 250.198(e)(2)(i)(HH) would clarify that API RP
17H is a regulatory requirement when complying with Sec. 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 Sec. 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 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
Sec. Sec. 250.734(a)(13) and 250.738(h) require placement of subsea
BOP systems in mudline cellars when drilling occurs in areas subject to
ice-scouring. In addition, proposed Sec. 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 is proposing to require the use of ROVs in conjunction
with the application of an SSID because the device functions similarly
to a BOP, and the Bureau has extensive experience in applying ROV
requirements to BOPs.\16\ A 2014 BSEE-commissioned study \17\ evaluated
existing acoustic technologies for subsea well control and found that
it's use was for specific remote emergency signaling applications. ROVs
are more reliable for overall emergency, complex, or high-uncertainty
situations. 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.
---------------------------------------------------------------------------

\16\ Paragraph (a)(4) of 30 CFR 250.734 What are the
requirements for a subsea BOP system?
\17\ Final Report 02--BOP Monitoring and Acoustic Technology,
2014 (chrome-extension://efaidnbmnnnibpcajpcglclefindmkaj/https://
www.bsee.gov/sites/bsee.gov/files/tap-technical-assessment-program//
713ac.pdf#:~:text=Assessment%20of%20BOP%20Stack%20Sequencing%2C%20Mon
itoring%20and,02%20%2D%20BOP%20Monitoring%20and%20Acoustic%20Technolo
gy.)
---------------------------------------------------------------------------

Furthermore, although BSEE is not proposing to require the SSID to
have a self-actuating function, the Bureau is contemplating whether one
may be 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 2018 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. In April 2020, the only leases with potential projects
that would be subject to the Arctic OCS's SSID or SSRW requirements
were relinquished. 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 Sec. 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
LMRP. Also, existing Sec. 250.734(a)(6)(ii) requires a deadman system,
that is designed to automatically shut-in the wellbore in the event of
a

[[Page 51021]]

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 shut-in the well because a non-shearable drill string is
positioned across the rams. If the subsea BOP rams are experiencing
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 late-season 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:
(i) Below the BOP;
(ii) At or before the time they install their BOP; and
(iii) 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 Sec.
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, 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 open-water 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 incident data
from 2007 to 2023, which may be accessed on BSEE's website at <a href="https://www.bsee.gov/stats-facts/offshore-incident-statistics">https://www.bsee.gov/stats-facts/offshore-incident-statistics</a>, 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 <a href="https://www.bsee.gov/newsroom/latest-news/statements-and-releases/press-releases/drilling-of-relief-well-begins-at-south">https://www.bsee.gov/newsroom/latest-news/statements-and-releases/press-releases/drilling-of-relief-well-begins-at-south</a>).
Other loss of well control events during that timeframe were
successfully remedied with conventional well control methods. These
incidents occurred in the Gulf of America and were controlled by either
circulating heavier weighted muds into the well or closing the BOP (or
both), to control

[[Page 51022]]

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 Sec. 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 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
Sec. 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)?
<bullet> Proposed Paragraph (b)--Complying With Sec. 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 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).
[cir] 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 high-pressured 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 Sec. 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
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 until reaching that point.
The changes BSEE is proposing would make proposed paragraph (b) of
Sec. 250.472 and proposed paragraph (a) of Sec. 250.471 consistent,
with respect to providing a potential opportunity to the operator to
delay access to its SCCE (as described in Sec. 250.471(a)(1) and
proposed Sec. 250.471(a)(2) and (a)(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 Sec. 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

[[Page 51023]]

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, non-productive 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 GOA, there are many 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. A common risk for highly permeable or
fractured zones can include the potential for lost circulation. This
could cause a dynamic effect where drilling mud flows into the
permeable formation 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 section-by-section discussion of Sec. 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
hi

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