[Federal Register Volume 85, Number 237 (Wednesday, December 9, 2020)]
[Proposed Rules]
[Pages 79266-79321]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2020-25818]
[[Page 79265]]
Vol. 85
Wednesday,
No. 237
December 9, 2020
Part II
Department of the Interior
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Bureau of Safety and Environmental Enforcement
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30 CFR Part 250
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. 85 , No. 237 / Wednesday, December 9, 2020 /
Proposed Rules
[[Page 79266]]
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DEPARTMENT OF THE INTERIOR
Bureau of Safety and Environmental Enforcement
30 CFR Part 250
Bureau of Ocean Energy Management
30 CFR Part 550
[Docket ID: BSEE-2019-0008, EEEE500000, 21XE1700DX, EX1SF0000.EAQ000]
RIN 1082-AA01
Oil and Gas and Sulfur Operations on the Outer Continental
Shelf--Revisions to the Requirements for Exploratory Drilling on the
Arctic Outer Continental Shelf
AGENCIES: 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 BOEM and BSEE, has reviewed and is proposing to revise its
existing regulations for exploratory drilling and related operations on
the Arctic Outer Continental Shelf (OCS), to reduce unnecessary burdens
on stakeholders while ensuring that energy exploration on the Arctic
OCS is safe and environmentally responsible. In particular, this
proposed rule would revise certain requirements promulgated through the
rule entitled, Oil and Gas and Sulfur Operations on the Outer
Continental Shelf-Requirements for Exploratory Drilling on the Arctic
Outer Continental Shelf (``2016 Arctic Exploratory Drilling Rule'').
This proposed rule would also add new provisions to BSEE's regulations
pertaining to suspensions of operations (SOO), and BOEM's Exploration
Plan (EP) and Development and Production Plan (DPP) regulations.
DATES: Submit comments by February 8, 2021. BSEE and BOEM may not fully
consider comments received after this date. You may submit comments to
the Office of Management and Budget (OMB) on the information collection
burden in this proposed rule by January 8, 2021. The deadline for
comments on the information collection burden does not affect the
deadline for the public to comment to BSEE and BOEM on the proposed
regulations.
ADDRESSES: You may submit comments on BSEE's or BOEM's sections of the
rulemaking by any of the following methods. For comments on this
proposed rule, please use the Regulation Identifier Number (RIN) 1082-
AA01 as an identifier in your message. For comments specifically
related to the draft Environmental Assessment (EA) conducted under the
National Environmental Policy Act of 1969 (NEPA), please refer to NEPA
in the heading of your message. See also Public Availability of
Comments under Procedural Matters.
Federal eRulemaking Portal: http://www.regulations.gov. In
the entry entitled, ``Enter Keyword or ID,'' enter BSEE-2019-0008, then
click search. Follow the instructions to submit public comments and
view supporting and related materials available for this rulemaking.
BSEE and BOEM may post all submitted comments.
Mail or hand-carry comments to the DOI, BSEE and BOEM:
Attention: Regulations and Standards Branch, 45600 Woodland Road, VAE-
ORP, Sterling VA 20166. Please reference RIN 1082-AA01, ``Oil and Gas
and Sulfur Operations on the Outer Continental Shelf--Revisions to the
Requirements for Exploratory Drilling on the Arctic Outer Continental
Shelf,'' in your comments, and include your name and return address.
Send comments on the information collection in this rule
to: Interior Desk Officer 1082-AA01, Office of Management and Budget;
202-395-5806 (fax); or via the online portal at RegInfo.gov. Please
also send a copy to BSEE and BOEM by one of the means previously
described.
Public Availability of Comments--Before including your
address, phone number, email address, or other personal identifying
information in your comment, you should be aware that your entire
comment--including your personal identifying information--may be made
publicly available at any time. For BSEE and BOEM to withhold from
disclosure your personal identifying information, you must identify any
information contained in the submittal of your comments that, if
released, would constitute a clearly unwarranted invasion of your
personal privacy. You must also briefly describe any possible harmful
consequence(s) of the disclosure of information, such as embarrassment,
injury, or other harm. While you can ask us in your comment to withhold
your personal identifying information from public review, we cannot
guarantee that we will be able to do so.
FOR FURTHER INFORMATION CONTACT: For technical questions related to
regulatory changes BSEE is proposing in Part 250, contact Mark E.
Fesmire, BSEE, Alaska Regional Office, [email protected], (907)
334-5300. For technical questions related to regulatory changes BOEM is
proposing in Part 550, contact Joel Immaraj, BOEM, Alaska Regional
Office, [email protected], (907) 334-5238. For procedural questions
contact Bryce Barlan, BSEE, Regulations and Standards Branch,
[email protected], (703) 787-1126.
SUPPLEMENTARY INFORMATION:
Executive Summary
In response to BSEE- and BOEM-initiated environmental and safety
reviews of potential oil and gas operations on the Arctic OCS,
experiences gained from Shell's 2012 and 2015 Arctic operations, and
concerns expressed by environmental organizations and Alaska Natives,
BSEE and BOEM published the 2016 Arctic Exploratory Drilling Rule (see
81 FR 46478, July 15, 2016). The rule was narrowly focused, applying
solely to exploratory drilling operations conducted during the Arctic
OCS open-water drilling season by drilling vessels and ``jack-up rigs''
(collectively known as mobile offshore drilling units or MODU) in the
Beaufort Sea and Chukchi Sea Planning Areas. The regulations were
intended to ensure that Arctic OCS exploratory drilling operations are
conducted in a safe and responsible manner, while taking into account
the unique conditions of the Arctic OCS, as well as Alaska Natives'
cultural traditions and their need for access to subsistence resources.
BSEE and BOEM have since reviewed the 2016 Arctic Exploratory Drilling
Rule taking into account a Congressional declaration of purposes in the
Outer Continental Shelf Lands Act (OCSLA) to ``establish policies and
procedures for managing the oil and natural gas resources of the Outer
Continental Shelf which are intended to result in expedited exploration
and development of the Outer Continental Shelf in order to achieve
national economic and energy policy goals, assure national security,
reduce dependence on foreign sources, and maintain a favorable balance
of payments in world trade.'' \1\ The bureaus have also reviewed new
information about technological developments in an ice environment.
Based on that review, BSEE and BOEM are proposing revisions in this
proposed rule that are consistent with OCSLA, and would reduce
unnecessary burdens on stakeholders while still maintaining safety and
environmental protection.
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\1\ Outer Continental Shelf Lands Act, Public Law 95-372, sec.
102 (Sept. 8, 1978), 43 U.S.C. 1802(1)).
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Since publication of the 2016 Arctic Exploratory Drilling Rule, new
[[Page 79267]]
Executive Orders (E.O.) and Secretary's Orders (S.O.) called on Federal
agencies to review existing regulations that potentially burden the
development or use of domestically produced energy resources and
appropriately begin processes to potentially suspend, revise, or
rescind those regulations that are determined to unduly burden the
development of domestic energy resources, beyond the degree necessary
to protect the public interest or otherwise comply with the law.
Executive Order 13795, Implementing an America-First Offshore Energy
Strategy (82 FR 20815) and Secretary's Order 3350, America-First
Offshore Energy Strategy, which are discussed in more detail below in
Section I. Background, Subsection C. Executive and Secretary's Orders,
specifically called for a review of the 2016 Arctic Exploratory
Drilling Rule.\2\ In response to these E.O.s and S.O.s, BSEE and BOEM
undertook a review of the regulations promulgated through the 2016
Arctic Exploratory Drilling Rule with a view toward encouraging energy
exploration and production on the Arctic OCS, as appropriate and
consistent with applicable law, and reducing unnecessary regulatory
burdens, while ensuring that any such activity is safe and
environmentally responsible.
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\2\ These Orders did no dictate outcomes; rather, they directed
a review in accordance with applicable law.
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BSEE's and BOEM's views about certain features of the existing
regulations were also informed by new information that has become
available since the 2016 rule was finalized. This new information
includes a BSEE-commissioned Technology Assessment Program (TAP) study
entitled, Suitability of Source Control and Containment Equipment
versus Same Season Relief Well in the Alaska Outer Continental Shelf
Region (Bratslavsky and SolstenXP, 2018) and a National Petroleum
Council (NPC) report entitled, Supplemental Assessment to the 2015
Report on Arctic Potential: Realizing the Promise of U.S. Arctic Oil
and Gas Resources (NPC 2019 Report). BSEE also re-assessed the original
NPC report entitled, Arctic Potential: Realizing the Promise of U.S.
Arctic Oil and Gas Resources (NPC 2015 Report; together with the NPC
2019 Report, the NPC reports). Both NPC reports include discussions
about global Arctic operations. These global operations are discussed
in further detail below in Subsection 5. Industry Interest in the
Arctic OCS of Section I. Background, under the subheading entitled,
Global Arctic Exploration Activities. The Bratslavsky and SolstenXP
study was finalized in October 2018 and may be downloaded from BSEE's
TAP website at: https://www.bsee.gov/research-record/suitability-of-source-control-containment-equipment-versus-same-season-relief-well.
The NPC 2019 Report was finalized in April 2019 and may be downloaded
from an NPC website at: https://www.npc.org/ARSA-FINAL-052219-LoRes.pdf. The NPC 2015 Report was finalized in March 2015 and may be
downloaded from an NPC website at: http://www.npcarcticpotentialreport.org/index.html.
Based on the results of these reports, BSEE and BOEM are proposing
to amend, revise, or remove certain current regulatory provisions
promulgated through the 2016 Arctic Exploratory Drilling Rule, to
reduce unnecessary burdens on stakeholders while still maintaining
safety and environmental protection. This proposed rulemaking is
consistent with OCSLA's Congressional declaration of purposes to
``establish policies and procedures for managing the oil and natural
gas resources of the Outer Continental Shelf which are intended to
result in expedited exploration and development of the Outer
Continental Shelf in order to achieve national economic and energy
policy goals, assure national security, reduce dependence on foreign
sources, and maintain a favorable balance of payments in world trade.''
43 U.S.C. 1802(1).
BSEE and BOEM also considered another issue on the Arctic OCS in
addition to those addressed in the 2016 Arctic Exploratory Drilling
Rule, but is logical to address as part of this rulemaking to further
encourage safe and environmentally responsible exploration of this
region, where the areas known to have oil and gas have been explored or
studied. This issue pertains to the effective means by which BSEE and
the operator could address seasonal weather-related constraints in the
Arctic OCS that severely impact the operator's ability to safely
perform leaseholding operations for a significant portion of the term
on a lease.
Accordingly, this proposed rule would revise certain provisions in
30 Code of Federal Regulations (CFR) Part 250, Subparts A, C, D, and G,
and 30 CFR part 550, subpart B, that pertain to:
1. The factors that the BSEE Regional Supervisor may evaluate in
assessing whether to grant an SOO, to address unique and specific
conditions relevant only to exploration and development activities on
the Arctic OCS;
2. Pollution prevention;
3. Arctic OCS Source Control and Containment Equipment (SCCE);
4. Relief rig capabilities for the Arctic OCS;
5. Timing and submission requirements related to Integrated
Operations Plans (IOP) for proposed Arctic exploratory drilling;
6. What must be included in the IOP; and
7. What data and information must accompany the EP and DPP.
This proposed rule is designed to reflect the need to ensure the
safe, effective, and responsible exploration of Arctic OCS oil and gas
resources, while protecting the marine, coastal, and human
environments, and preserving Alaska Natives' cultural traditions and
their access to subsistence resources. This proposed rule is intended
to revise the regulations promulgated through the 2016 Arctic
Exploratory Drilling Rule by creating more flexible and less costly
compliance options in BSEE's and BOEM's regulations that could achieve
these objectives. While this proposed rule seeks to promulgate new
provisions in addition to those addressed in the 2016 Arctic
Exploratory Drilling Rule, these new provisions (i.e., provisions to
address leaseholding operations impacted by seasonal weather-related
constraints on the Arctic OCS) would further enhance BSEE's and BOEM's
abilities to ensure the safe, effective, and responsible exploration of
Arctic OCS oil and gas resources. They would do so while protecting the
marine, coastal, and human environments, and preserving Alaska Natives'
cultural traditions and access to subsistence resources. Through lease
stipulations related to the Conflict Avoidance Agreements (CAA), BOEM
currently requires operators to consult with affected subsistence
communities and describe in exploration and development plans the
mitigating practices the operator would undertake to avoid conflicts
with the communities. Conflict Avoidance Agreements provide a framework
for mitigating the adverse impacts a drilling project may have on
subsistence activities, values, and uses.
Table of Contents
I. Background
A. Overview of the Alaska Arctic Region
B. BSEE and BOEM Statutory and Regulatory Authority and
Responsibilities
C. Executive and Secretary's Orders
D. Purpose and Summary of the Rulemaking
E. Partner Engagement in Preparation for This Proposed Rule
II. Section-by-Section Discussion of Proposed Changes
A. Key Revisions Proposed by BSEE
[[Page 79268]]
Subpart A--General
Definitions. (Sec. 250.105)
When may the Regional Supervisor grant an SOO? (Sec.
250.175)
Documents incorporated by reference. (Sec. 250.198)
Subpart C--Pollution Prevention and Control
Pollution prevention. (Sec. 250.300)
Subpart D--Oil and Gas Drilling Operations
What additional information must I submit with my APD
for Arctic OCS exploratory drilling operations? (Sec. 250.470)
What are the requirements for Arctic OCS source control
and containment? (Sec. 250.471)
What are the additional well control equipment or
relief rig requirements for the Arctic OCS? (Sec. 250.472)
Subpart G--Well Operations and Equipment
When and how must I secure a well? (Sec. 250.720)
B. Key Revisions Proposed by BOEM
Subpart B--Plans and Information
Definitions. (Sec. 550.200)
Removal of Sec. 550.204, When must I submit my IOP for
proposed Arctic exploratory drilling operations and what must the
IOP include?
How do I submit the EP, DPP, or DOCD? (Sec. 550.206)
What must the EP include? (Sec. 550.211)
If I propose activities in the Arctic OCS Region, what
planning information must accompany the EP? (Sec. 550.220)
III. Additional Comments Solicited on the Same Season Relief Well
and Relief Rig Requirement
IV. Procedural Matters
A. Regulatory Planning and Review (Executive Orders (E.O.)
12866, 13563, and 13771)
B. Regulatory Flexibility Act and Small Business Regulatory
Enforcement Fairness Act
C. Unfunded Mandates Reform Act of 1995 (UMRA)
D. Takings Implication Assessment
E. Federalism (E.O. 13132)
F. Civil Justice Reform (E.O. 12988)
G. Consultation With Indian Tribes (E.O. 13175)
H. Environmental Justice in Minority Populations and Low-Income
Populations (E.O. 12898)
E.O. 12898
I. Paperwork Reduction Act (PRA)
J. National Environmental Policy Act of 1969 (NEPA)
K. Data Quality Act
L. Effects on the Nation's Energy Supply (E.O. 13211)
M. Clarity of Regulations
List of Acronyms and References
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Report to the Secretary of the Interior, review
60-Day report of Shell's 2012 Alaska Offshore Oil and Gas
Exploration Program
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2016 Arctic Exploratory Drilling Rule.......................... Oil and Gas and Sulfur Operations on the Outer
Continental Shelf-Requirements for Exploratory
Drilling on the Arctic Outer Continental
Shelf, 81 FR 46478, July 15, 2016 (available
at https://www.doi.gov/sites/doi.gov/files/migrated/news/pressreleases/upload/Shell-report-3-8-13-Final.pdf.).
ABS............................................................ American Bureau of Shipping.
ACP............................................................ Alternative Compliance Program.
ADNR........................................................... Alaska Department of Natural Resources.
AEWC........................................................... Alaska Eskimo Whaling Commission.
ANILCA......................................................... Alaska National Interest Lands Conservation
Act.
ANCSA.......................................................... Alaska Native Claims Settlement Act.
ANWR........................................................... Arctic National Wildlife Refuge.
APD............................................................ Application for Permit to Drill.
API............................................................ American Petroleum Institute.
Arctic OCS..................................................... OCS within the Beaufort Sea and Chukchi Sea
Planning Areas.
AWKS........................................................... Alternative Well Kill System.
BOEM........................................................... Bureau of Ocean Energy Management.
BOEMRE......................................................... Bureau of Ocean Energy Management, Regulation
and Enforcement.
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.
BLM............................................................ Bureau of Land Management.
CAA............................................................ Conflict Avoidance Agreement.
CFR............................................................ Code of Federal Regulations.
CZMA........................................................... Coastal Zone Management Act.
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.
EIS............................................................ Environmental Impact Statement.
E.O............................................................ Executive Order.
EP............................................................. Exploration Plan.
EPA............................................................ Environmental Protection Agency.
ESA............................................................ Endangered Species Act.
G&G............................................................ Geological and geophysical.
IC............................................................. Information Collection.
ICAS........................................................... Inupiat Community of the Arctic Slope.
IOP............................................................ Integrated Operations Plan.
IRIA........................................................... Initial Regulatory Impact Analysis.
IWC............................................................ International Whaling Commission.
LMRP........................................................... Lower Marine Riser Package.
MASP........................................................... Maximum Anticipated Surface Pressures.
MMPA........................................................... Marine Mammal Protection Act.
MMS............................................................ Minerals Management Service.
MODU........................................................... Mobile Offshore Drilling Unit.
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NAICS.......................................................... North American Industry Classification System.
NEPA........................................................... National Environmental Policy Act of 1969.
NMFS........................................................... National Marine Fisheries Service.
NOAA........................................................... National Oceanic and Atmospheric
Administration.
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.
NPR-A.......................................................... National Petroleum Reserve--Alaska.
NSB............................................................ North Slope Borough.
NTL............................................................ Notice to Lessees and Operators.
OCS............................................................ Outer Continental Shelf.
OCSLA.......................................................... Outer Continental Shelf Lands Act.
ODCE........................................................... Ocean Discharge Criteria Evaluations.
OIRA........................................................... Office of Information and Regulatory Affairs.
OMB............................................................ Office of Management and Budget.
ONRR........................................................... Office of Natural Resources Revenue.
OSRP........................................................... Oil Spill Response Plan.
PFD............................................................ Permanent Fund Dividend.
PRA............................................................ Paperwork Reduction Act.
psi/ft......................................................... pounds per square inch per foot.
RIN............................................................ Regulation Identifier Number.
ROV............................................................ Remotely Operated Vehicle.
RP............................................................. Recommended Practice.
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.
TAP............................................................ Technology Assessment Program.
TAPS........................................................... Trans-Alaska Pipeline System.
TCF............................................................ Trillion Cubic Feet.
UMRA........................................................... Unfunded Mandates Reform Act of 1995.
U.S............................................................ United States.
USCG........................................................... U.S. Coast Guard.
USFWS.......................................................... U.S. Fish and Wildlife Service.
USGS........................................................... United States Geological Survey.
Utquiavik...................................................... Barrow.
WCD............................................................ Worst Case Discharge.
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I. Background
A. Overview of the Alaska Arctic Region
1. History of Arctic Oil and Gas Development
Although Alaska's first oil production is attributable to the 1957
Swanson River discovery on the Kenai Peninsula, oil and gas resources
have been known to exist in the Arctic since as early as 1839. Early
explorers had reported that Alaska Natives on the Arctic coast used
oil-soaked tundra for fuel. The oil came from natural oil seeps on the
ground. However, the extent of the resource, as well as the State's
overall oil and gas endowment, would not be realized until the
discovery of the Arctic's Prudhoe Bay oil field on the North Slope and
completion of the Trans-Alaska Pipeline System (TAPS) in 1977.
The Prudhoe Bay field was discovered on March 12, 1968, with the
drilling of the Prudhoe Bay State #1 well. BP Exploration drilled a
confirmation well the following year. However, production did not come
online until June 20, 1977, after the TAPS was completed and other
companies with lease holdings in the area undertook a host of
activities to delineate the reservoir, resolve equity participation,
and put together initial infrastructure for the field. After over 40
years of production, Prudhoe Bay remains the largest oil field in North
America and is the 18th largest field ever discovered worldwide.\3\
According to data maintained by the Alaska Oil and Gas Conservation
Commission, Alaska's North Slope has produced over 17.3 billion barrels
of oil, with Prudhoe Bay contributing approximately 68 percent of that
amount.\4\ Currently, the only offshore Federal production in the
Arctic OCS \5\ is Hilcorp's Northstar field, which includes both State
and Federal acreage in the 8(g) Zone.\6\ Located in the Beaufort Sea
about 12 miles northwest of Prudhoe Bay, this prospect has been
producing since 2001. Over 150 million barrels of oil have been
produced to date at Northstar. In 2019, the Federal Government received
nearly $5 million in royalty payments from oil production on Federal
leases at Northstar, and from 2003 to 2018, royalty payments ranged
[[Page 79270]]
from $3 million to over $20 million in any given year. In 2019, the
Federal Government disbursed just over $1.5 million to the State of
Alaska for Northstar Federal leases in the 8(g) Zone.\7\
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\3\ https://dec.alaska.gov/spar/ppr/response/sum_fy06/060302301/factsheets/060302301_factsheet_PB.pdf.
\4\ http://aogweb.state.ak.us/DataMiner3/Forms/Production.aspx.
\5\ There are Federal OCS leases that do not have ongoing
production in the Cook Inlet, which is not considered part of the
Arctic.
\6\ Section 8(g) of the OCSLA requires the Federal Government to
share with the State of Alaska 27% of revenue from leases in the
8(g) Zone (the first three nautical miles of the Outer Continental
Shelf). 43 U.S.C. 1337(g).
\7\ https://revenuedata.doi.gov/downloads/disbursements/.
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The construction of TAPS enhanced the significance of the Arctic's
production to the State of Alaska. TAPS is an 800-mile-long pipeline
system that was designed to accommodate the transport of over 2 million
barrels of oil per day. The pipeline begins at Prudhoe Bay and
stretches south to Valdez in southern Alaska, which is the northernmost
ice-free port in North America. TAPS is one of the world's largest
pipeline systems, an engineering icon that was the biggest privately
funded construction project when it was constructed in the 1970s. At
peak flow in 1988, 11 pump stations helped to move 2.1 million barrels
of oil a day.\8\
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\8\ https://www.alyeska-pipe.com/TAPS.
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2. Budgetary Economic Impact on the People of Alaska
North Slope Alaska oil and gas exploration and production has been
a significant economic driver, not only to the State of Alaska and
Alaskan Native communities, but also to the national domestic energy
supply. The State's oil and gas endowments have provided greater
economic prosperity to its people than other important resources in the
State. Specifically, Alaska relies on revenues generated from oil and
gas resources, along with other revenue-generating streams, to fund a
major portion of the State's operating and capital budgets. This has
allowed Alaska to be the only State in the United States that does not
have either a State sales tax or personal income tax. Oil and gas
revenues are generated by means of a variety of taxes, royalties, and
other charges related to oil and gas development and production. Other
examples of revenue-generating streams for Alaska include corporate
income, fuel, alcohol, and tobacco taxes. In 2016, 72 percent of
Alaska's unrestricted general funds, which come from the State's
overall revenue-generating stream, were derived from oil and gas
revenues and were available to the State's budget.\9\ In 2012, as much
as 93 percent of Alaska's unrestricted general funds were derived from
oil and gas revenues and were also available to the State's budget.\10\
The reduced contribution of oil and gas-generated revenue to the
State's budget since 2012 is due primarily to declining oil production
in the North Slope, but also due to a general downward trend in oil
prices.
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\9\ https://www.legfin.akleg.gov/, Budget History Data (Excel)
(posted 1-15-2020), Row 59.
\10\ https://www.legfin.akleg.gov/, Budget History Data (Excel)
(posted 1-15-2020), Row 55.
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Aside from annual State operating and capital budgets, several
Statewide government programs established for the benefit of the people
of Alaska are largely dependent on oil and gas-related revenues, most
notably the Alaska Permanent Fund. In 1976, Alaska's State constitution
was amended to establish the Alaska Permanent Fund, which provides that
at least 25 percent of all mineral lease rentals, royalties, royalty
sale proceeds, Federal mineral revenue sharing payments, and bonuses
received by the State are to be placed in a permanent fund, known as
the Alaska Permanent Fund, the principal of which is used only for
income-producing investments. All income generated from the permanent
fund is available for distribution to all Alaskan residents--adults and
children--on an annual basis through the State's Permanent Fund
Dividend (PFD) program.\11\ Since 1978, this fund has grown to a total
fund value of $60 billion as of March 2020.\12\ Individual
distributions to Alaskans from the fund have ranged from $386 per
person to as high as $2,072 per person.\13\ These annual payments are
estimated to have lifted between 15,000 and 25,000 Alaskans above the
Federal poverty line.\14\
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\11\ https://apfc.org/frequently-asked-questions/#why-did-alaskans-create-the-fund.
\12\ https://apfc.org/our-performance/.
\13\ https://pfd.alaska.gov/Division-Info/Summary-of-Applications-and-Payments.
\14\ Berman, Matt., Random Reamy. ``Permanent Fund Dividends and
Poverty in Alaska.'' Institute of Social and Economic Research,
University of Alaska Anchorage. (November 2016), available online
at: https://iseralaska.org/static/legacy_publication_links/2016_12-PFDandPoverty.pdf. p. 25 of pdf.
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Much of the North Slope Borough's economy is tied to the oil and
gas industry, primarily in the greater Prudhoe Bay region. Some borough
residents have rotational work in the oilfields or in a position
supporting the oil industry, but the greatest contribution to the
economy is through tax revenue. The borough assesses property taxes on
infrastructure, the primary funding source for the borough's operations
and capital projects, which include building roads, operating schools,
and funding for other public services, such as health clinics and fire
departments.\15\
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\15\ http://www.north-slope.org/assets/images/uploads/13_Economic_Development_-_NSB_Comprehensive_Plan.pdf.
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In March and April of 2020, global oil prices experienced
significant volatility due to a confluence of events, including
decreased demand from coronavirus effects, as well as production output
negotiations between OPEC and Russia. These events caused the price of
oil to slide to 17-year lows. While prices have already partially
recovered and stabilized, this could affect interest and activity in
the region if the low-price environment continues into the future, as
drilling and other exploration activities in the Arctic are more
expensive than other regions. Given the long period of time before
exploratory drilling in the Arctic is expected to start and the short-
term nature of the underlying price events, the Bureaus expect that
prices will continue to rebound. The events in 2020 also underscore the
importance of ensuring that BOEM and BSEE regulations are no more
burdensome than necessary to protect safety and the environment.
3. Arctic Resource Potential and Geology
The Arctic region is characterized by its extensive oil and gas
resources. The Arctic Alaska Petroleum Province, which consists of up
to 43 geologic plays between the Chukchi Sea and the Beaufort Sea
planning areas, extends about 684 miles from the United States-Canadian
border westward to the maritime boundary with Russia, and from 62 to
372 miles northward from the Brooks Range to the approximate edge of
the Continental Shelf. Although the edge of the Continental Shelf
provides a well-defined physiographic boundary for the province, this
edge does not represent a geologic limit to potential petroleum
resources. The offshore part of the province is characterized by a
relatively narrow (62-mile-wide) shelf in the Beaufort Sea and a broad
(372-mile-wide) shelf in the Chukchi Sea. The province is bounded
onshore on the south by the Brooks Range-Herald mountain range and
offshore to the north by the passive continental margin of the Canada
Basin.\16\ In general, the formations are fairly continuous across the
Arctic Alaska Petroleum Province.
---------------------------------------------------------------------------
\16\ Houseknecht, D.W., and Bird, K.J., 2006, Oil and gas
resources of the Arctic Alaska petroleum province: U.S. Geological
Survey Professional Paper 1732-A, 11 p., available online at: http://pubs.usgs.gov/pp/pp1732/pp1732a/.
---------------------------------------------------------------------------
Although most of the Arctic's oil production to date is attributed
to the North Slope, most of the undiscovered resources are located off
the Arctic coast, within the Chukchi Sea and Beaufort Sea Planning
Areas. According to BOEM's 2016 Assessment of Undiscovered Technically
Recoverable Oil and Gas Resources of the Nation's
[[Page 79271]]
OCS (mean estimates available at http://www.boem.gov/National-Assessment-2016/), there are approximately 23.6 billion barrels of
undiscovered technically recoverable oil and about 104.4 trillion cubic
feet (TCF) of technically recoverable natural gas (mean estimates) in
the combined Beaufort Sea and Chukchi Sea Planning Areas. BOEM re-
assessed its Beaufort Sea Planning Area estimates due to recent onshore
discoveries in the National Petroleum Reserve-Alaska (NPR-A) from two
formations that extended offshore. In December 2017, BOEM published its
updated re-assessment (mean estimates available at https://www.boem.gov/2016a-National-Assessment-Fact-Sheet/), which estimated
that there are approximately 24.3 billion barrels of technically
recoverable oil and about 104. TCF of technically recoverable natural
gas in the combined Beaufort Sea and Chukchi Sea Planning Areas; an
increase of about 680 million barrels of oil and 100 billion cubic feet
of natural gas. Of the 24.3 billion barrels of oil, the Chukchi Sea
Planning Area makes up about 63% of the estimate, while the Beaufort
Sea Planning Area makes up 37%. With respect to gas, the Chukchi Sea
Planning Area makes up about 73% of the 104.5 TCF of gas and the
Beaufort Sea Planning Area makes up 27% of the estimate. These
estimates represent about one-quarter of the technically recoverable
oil resources and one-third of the technically recoverable gas
resources on the OCS.
While not as large, the Arctic's onshore undiscovered oil and gas
resources are also considerable. In January 2020, the United States
Geological Survey (USGS) published an assessment of undiscovered oil
and gas resources in the central portion of the Alaska North Slope,
(mean estimates available at https://pubs.usgs.gov/fs/2020/3001/fs20203001.pdf). The assessment estimated that there are approximately
3.6 billion barrels of undiscovered technically recoverable oil and
about 8.9 TCF of undiscovered technically recoverable natural gas
resources on State and Native lands, and State waters, east of the NPR-
A and west of the Arctic National Wildlife Refuge (ANWR). According to
a 2017 USGS assessment of undiscovered oil and gas resources in the
Alaska North Slope, (mean estimates available at https://pubs.usgs.gov/fs/2017/3088/fs20173088.pdf), there are approximately 8.8 billion
barrels of undiscovered technically recoverable oil and about 39 TCF of
undiscovered technically recoverable natural gas in the NPR-A. In
addition, USGS's assessment of the 1002 Area \17\ of the ANWR estimated
(mean estimates available at https://pubs.usgs.gov/of/2005/1217/pdf/2005-1217.pdf) there are 7.6 billion barrels of technically recoverable
oil and 7.04 \18\ TCF of technically recoverable natural gas. Efforts
are already underway to bring some of these new onshore resources
online. Collectively, these offshore and onshore assets are enormous,
and most of the resources are located offshore.\19\ However, the Arctic
OCS's vast potential has yet to be realized.
---------------------------------------------------------------------------
\17\ The Alaska National Interest Lands Conservation Act
(ANILCA) of 1980 required ANWR to be managed as a protected
wilderness. Section 1002 of ANILCA, however, deferred a decision
regarding future management of a 1.5 million-acre coastal plain
portion of ANWR (known as the ``1002'' area) in order to
continuously study the various natural resources on the coastal
plain, and analyze how oil and gas exploration, development, and
production could potentially impact those resources. Section 20001
of the Tax Cuts and Jobs Act of 2017 lifted a provision in Section
1003 of ANILCA that prohibits oil and gas leasing and production in
the 1002 area, and the BLM is in the process of developing an oil
and gas leasing program for that area.
\18\ This value represents the combined estimates of natural gas
that could technically be produced from gas fields as well as
associated gas that could be produced from oil fields.
\19\ D.L. Gautier et al., ``Circum-Arctic Resource Appraisal:
Estimates of Undiscovered Oil and Gas North of the Arctic Circle,''
U.S. Geological Survey, USGS Fact Sheet 2008-3049, 2008. M.E.
Brownfield et al., ``An Estimate of Undiscovered Conventional Oil
and Gas Resources of the World,'' U.S. Geological Survey, USGS Fact
Sheet 2012-3024, 2012, available at https://pubs.usgs.gov/fs/2008/3049/fs2008-3049.pdf.
---------------------------------------------------------------------------
In the Arctic, the circumstances associated with drilling from a
MODU can be different than those in the Gulf of Mexico. The geological
pressures in the hydrocarbon bearing zones in the shallow seas of
Alaska's Arctic are, in many cases, likely to be substantially lower
than those encountered during the Deepwater Horizon incident, reducing
certain risk factors of a major blowout. As reviewed by the NPC,
through the NPC 2019 Report, subsurface conditions (below the seafloor)
for the Arctic OCS--geology, pressure, resource depth, and drilling
depth--are much simpler as compared to other areas, such as the
deepwater Gulf of Mexico OCS. The NPC 2019 Report states that the
targeted Arctic potential reservoirs are shallow and normally
pressured, but that exploration and development are dominated by other
challenges, such as water depth, ice conditions, and the length of the
open-water season, which make the Arctic unique (NPC 2019 Report at
10). The NPC 2015 Report found, however, that most of the U.S. Arctic
offshore conventional oil and gas potential can be developed using
existing field-proven technology, which was reaffirmed by the NPC 2019
Report (NPC 2015 Report at 28).
As identified by the NPC, targeted potential reservoirs in the
Arctic OCS may be shallow and normally pressured.\20\ However, this
condition is not consistent throughout all areas in the Arctic OCS that
have already been explored. For example, a study published by the
American Rock Mechanics Association \21\ analyzed wells drilled in the
Chukchi Sea in order to provide an improved interpretation and
delineation of pore pressure in the Chukchi shelf region. A majority of
the wells contained significant overpressure at depths ranging from
1,098 to 2,317 meters (i.e., 3,602 to 7,601 feet) subsea. In the
Beaufort Sea, the Alaska Department of Natural Resources (ADNR) noted
that, as part of its findings to support Beaufort Sea areawide oil and
gas lease sales,\22\ operators may reasonably expect to encounter
extremely high pore pressures along the central Beaufort Sea region
where `` . . . Cenozoic strata (sedimentary layers) are very thick,
such as in the Kaktovik, Camden, and Nuwuk Basins,'' and suggests that
challenges from over pressured areas could be reduced by ``. . .
identifying locations of overpressured sediments via seismic data
analysis, and then adjusting the mud mixture accordingly as the well is
drilled.'' In the Point Thomson area, for example, where drilling has
taken place from an onshore facility into a reservoir located primarily
offshore, the pore pressure gradients were measured as high as 0.8
pounds per square inch per foot (psi/ft) at depths of 2.5 miles (13,200
feet). A pore pressure gradient of 0.433 psi/ft is considered normal in
this area.\23\
---------------------------------------------------------------------------
\20\ ``Normally pressured'' is not defined in the NPC 2019
Report. However, as a general matter, normal pressure generally
refers to the hydrostatic pressure within a well. ``Normally
pressured'' refers to conditions present when formation pressures
are predictable at any given depth and follow a normal formation
pressure gradient or ``hydrostatic pressure gradient.'' Normal
formation pressure, at any given depth, equals the normal formation
pressure gradient multiplied by the depth. The normal pressure is
expressed in pounds per square inch (psi).
\21\ Elowe, K.E., & Sherwood, K.W., 2017, ``Abnormal Formation
Pressure in the Chukchi Shelf, Alaska,'' American Rock Mechanics
Association Conference Paper, Document ID ARMA-2017-0194, available
online at https://www.onepetro.org/conference-paper/ARMA-2017-0194.
\22\ Alaska Department of Natural Resources, 2019, ``Beaufort
Sea Areawide Oil and Gas Lease Sales,'' p. 3-20, available online at
https://aws.state.ak.us/OnlinePublicNotices/Notices/View.aspx?id=193811.
\23\ Craig, J.D., K.W. Sherwood, and P.P. Johnson. 1985.
Geologic report for the Beaufort Sea planning area, Alaska: Regional
geology, petroleum geology, environmental geology. U.S. Department
of the Interior, Minerals Management Service, Alaska OCS Region, OCS
Report MMS 85-0111. Anchorage, Alaska. https://www.boem.gov/BOEM-Newsroom/Library/Publications/1985/85_0111.aspx.
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[[Page 79272]]
While these reports' findings do not fully align with the NPC's
findings, there are other sources of information confirming that, to a
certain degree, typical geologic conditions in the Arctic OCS are
normally pressured. For example, a BOEM report that studied the Chukchi
Sea's Burger gas discovery calculated the pore pressure gradient for
one of the Chukchi Sea wells in the study to be 0.44 psi/ft up to 4,850
feet subsea, which the report determined to be normally pressured.
However, beneath 4,850 feet, the pore pressure gradient became over-
pressurized having a pore pressure gradient of 0.88 psi/ft.\24\ For the
Beaufort Sea, a USGS report analyzed pressure data from five offshore
wells and found that the pressures in the area where the wells were
located were normally pressured (i.e., at hydrostatic pressure) up to
2,000 feet subsea, and increased only slightly above hydrostatic
pressure deeper into the well. By 10,000 feet, however, the pressure in
all five wells were over-pressured, 1.5 times higher than the
hydrostatic pressure.\25\ Over-pressure started to occur at around
6,700 feet subsea.
---------------------------------------------------------------------------
\24\ Craig, J.D., & Sherwood, K.W., 2001 (revised 2004),
``Economic Study of the Burger Gas Discovery, Chukchi Shelf,
Northwest Alaska,'' U.S. Department of the Interior, Minerals
Management Service, p. 67, available online at https://www.boem.gov/sites/default/files/boem-newsroom/Library/Publications/2004/Economic-Study-of-the-Burger-Gas-Discovery.pdf.
\25\ Hayba, D.O., Houseknecht, D.W., and Rowan, E., 1999,
``Stratigraphic, Hydrogeologic, and Thermal Evolution of the Canning
River Region, North Slope, Alaska,'' U.S. Department of the
Interior, U.S. Geological Survey, p. FF-21, available online at
https://pubs.usgs.gov/of/1998/ofr-98-0034/FF.pdf.
---------------------------------------------------------------------------
While it is not possible to confirm that all targeted potential
reservoirs would be shallow and normally pressured in all exploratory
drilling situations, BSEE and BOEM will have access to the relevant
geologic and geophysical information to help identify hydrocarbon
bearing zones and zones with potential geologic risk, such as over-
pressurized zones, that may be encountered during drilling operations.
These higher pressured, hydrocarbon zones are, in fact, the targeted
formations the industry has attempted to produce. For example, the BOEM
report analyzing the Chukchi Sea's Burger gas discovery illustrated the
regional geology of all the wells included in the study, and showed
that the higher pressured zones in the wells occurred at the same point
where the oil-bearing zones were located.\26\ The Bureaus have the
means, through access to relevant geological and geophysical (G&G) data
and drilling application regulatory reviews, to confirm that operators
identify and plan for these potential risks. For example, the bureaus
confirm that operators have properly designed well casing and drilling
programs and ensure that operators have access to properly designed
equipment that is readily available to quickly respond to an incident,
such as the availability of a capping stack in advance of drilling into
the targeted productive zones.
---------------------------------------------------------------------------
\26\ Craig, J.D., & Sherwood, K.W., 2001 (revised 2004),
``Economic Study of the Burger Gas Discovery, Chukchi Shelf,
Northwest Alaska,'' U.S. Department of the Interior, Minerals
Management Service, p. 72, available online at https://www.boem.gov/sites/default/files/boem-newsroom/Library/Publications/2004/Economic-Study-of-the-Burger-Gas-Discovery.pdf.
---------------------------------------------------------------------------
4. Partnership With Alaska Natives in Northern Alaska
The bowhead whale provides the largest subsistence resource
available to the native villages of Alaska's northern shores. In 1977,
Eskimo whalers from these villages established the Alaska Eskimo
Whaling Commission (AEWC), whose mission is to safeguard the bowhead
whale and its habitat, defend the Aboriginal Subsistence Whaling Rights
of their members, and preserve the cultural and traditional values of
their villages. Eskimo whalers established the AEWC in response to
actions taken by the International Whaling Commission (IWC) that
resulted in the IWC's assumption of direct jurisdiction over the
Alaskan Native bowhead whale subsistence hunt, without Alaska Native
input. The IWC assumed direct jurisdiction over Alaska Native's bowhead
whale subsistence in response to the IWC's concerns regarding the
decline in the western Arctic bowhead whale stock. The IWC's only
mechanism for protecting whale stocks is the setting of hunting quotas.
Therefore, the IWC's only recourse for addressing its concerns was to
prohibit the Alaska Native bowhead whale subsistence hunt. This action
devastated local communities, creating immediate and severe food
shortages. In response, in 1981, the AEWC was able to establish an
agreement with the Federal Government to co-manage the bowhead whale
hunting quotas.
Although the AEWC was able to regain control of its bowhead whale
hunting quotas, the organization shared a similar concern with the IWC
regarding the potential effects of offshore oil exploration and
development on the bowhead whale. Whalers observed how bowhead whales
were responding to the presence of ocean-going oil and gas industry
exploration vessels, which were making the whales skittish and
affecting the whalers' ability to effectively meet the quotas for their
communities. In response, the AEWC worked with industry stakeholders to
establish the ``Oil/Whaler Agreement,'' which was a communication plan
between whalers and exploration vessels that was intended to prevent
direct threats to the whalers' safety from industry vessels.
The AEWC and industry stakeholders eventually turned the ``Oil/
Whaler Agreement'' into a framework for understanding and addressing
indirect interference with hunting activities, resulting from
behavioral changes in bowhead whales as they react to the noise and
other pollutants accompanying oil and gas work. This framework of
understanding eventually formed the basis of what is now known as a
CAA.\27\ While DOI does not require executing a CAA, BSEE and BOEM
highly encourage operators to work with the AEWC to establish CAAs,
since these agreements essentially acknowledge, within CAA provisions,
that both subsistence hunting activities and oil and gas development
can and should coexist. See discussion in Section I.E.3, History and
Background on the Conflict Avoidance Agreement, of this preamble
describing the provisions typically included in a CAA. This
longstanding process allows for industry representatives to sit, in
council, with members of the AEWC, local tribes, and village and
regional corporations to determine cultural circumstances and
situations that could cause conflict--and thus avoid them. For example,
during whale (or walrus) hunting seasons in the spring and fall, the
CAA may include provisions whereby industry will avoid construction or
production noise and related activities during those times when whales
are transiting nearby, and the hunters are in the area. With this early
initiative, direct collaboration with local hunters, specifically the
whaling captains and their representative organization, the AEWC,
became a critical element of offshore industrial development planning
and management in the Alaskan Arctic.
---------------------------------------------------------------------------
\27\ Conflict Avoidance Agreements are contracts signed by the
operators and the Alaska native communities to which BOEM is not a
party.
---------------------------------------------------------------------------
Today, the AEWC includes registered whaling captains and their
crews from eleven whaling communities of the
[[Page 79273]]
Arctic Alaska coast: Gambell, Savoonga, Wales, Little Diomede,
Kivalina, Point Hope, Point Lay, Wainwright, Barrow \28\ (Utquiavik),
Nuiqsut, and Kaktovik. The AEWC often represents the Inupiat Community
of the Arctic Slope (ICAS) in matters pertaining to energy exploration
or development specifically for the OCS. The ICAS is a unique federally
recognized tribal entity. ICAS membership is based on an individual's
ancestral lineage to a village tribe; it includes the peoples of eight
Native Villages: Kaktovik, Atqasuk, Nuiqsut, Anaktuvuk Pass, Barrow,
Wainwright, Point Lay, and Point Hope. Each village tribe acts
independently but will interact with ICAS and its membership as it
relates to Federal and State energy issues.
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\28\ Although the Alaska Native tribe is based in Utquiavik, at
any given time, the whaling may involve members of the Apugauti and
Nalukatq tribes, whose native lands do not border the coast. For
this reason, the AEWC prefers to refer to this group of whaling
captains collectively by the broader term ``Barrow.''
---------------------------------------------------------------------------
Conflict avoidance tools are often incorporated into leasing
stipulations addressing consultation with subsistence communities, and
will continue to be essential to help satisfy the need to provide a
secure source of energy for the Nation while at the same time
protecting the subsistence resources and uses of the local communities
where these energy resources are located.
5. Industry Interest in the Arctic OCS
In 1979, a year after the first Arctic offshore discovery (i.e.,
the Endicott oil field) was made in State waters, the Department,
acting through the Bureau of Land Management (BLM), held the first oil
and gas lease sale in the Arctic OCS, offering tracts adjacent to
Prudhoe Bay in the Beaufort Sea Planning Area. That sale resulted in 24
leases, covering 85,776 acres, being issued. Although it was the first
sale ever conducted for the Arctic OCS, the revenues generated from
that sale, over $491 million, make it the 4th largest sale in Arctic
OCS history. That dollar amount would represent almost $1.9 billion
dollars in 2019 after adjusting for inflation. Between 1979 and 2008,
the Department, acting through the BLM and Minerals Management Service
(MMS),\29\ held 13 oil and gas lease sales, and issued nearly 1,800
leases, covering over 9.7 million acres, on the Arctic OCS. These sales
generated over $6.8 billion in bonus bids. As many as 23 companies/
bidders have participated in an Alaska OCS lease sale and, while the
number of companies/bidders participating from one sale to the next
varied, an average of 10 companies/bidders participated in each sale.
---------------------------------------------------------------------------
\29\ MMS was the predecessor agency of BSEE and BOEM.
---------------------------------------------------------------------------
By 2008, U.S. oil production had been steadily declining for 5
years to an average of 5 million barrels per day, while U.S.
consumption of crude oil and petroleum products reached an all-time
high of 20.68 million barrels per day.\30\ The price of oil increased
steadily through 2007 from approximately $50 to $90 per barrel by the
time the most recent Arctic sale, Lease Sale 193, was held in February
of 2008.\31\ These market factors may have contributed to the outcome
of Lease Sale 193, one of the most successful in Arctic OCS history,
based on multiple metrics--the number of bids received, the number of
tracts receiving bids, and the total amount of bonus bids received from
the sale. The MMS received a total of 667 bids on 488 blocks; both
record-setting numbers for the Arctic OCS. A total of 487 leases,
covering over 2.7 million acres, were issued, and the sale generated
over $2.6 billion in bonus bids, which went to the U.S. Treasury. Since
2008, however, the Department has not conducted any new lease sales for
the Arctic OCS. A description of the status of active leases in the
Artic OCS is discussed in further detail below within this subsection,
prior to the subheading entitled, Global Arctic Exploration Activities.
---------------------------------------------------------------------------
\30\ https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=MTTUPUS2&f=A, table entitled, ``U.S.
Product Supplied of Crude Oil and Petroleum Products (Thousand
Barrels per Day)''.
\31\ https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=F000000__3&f=M.
---------------------------------------------------------------------------
Sale 193 was significant, not only in number of tracts sold and the
amount received from the sale, but in that the industry's interest
spurred a flurry of activities on the Arctic OCS prior to and after the
sale. The following table lists those activities:
2006
------------------------------------------------------------------------
June 20........................ MMS authorizes ConocoPhillips, Shell,
and GX Technology Corporation to
conduct geophysical operations for a
portion of Chukchi Sea Planning Area,
which covered the Sale 193 area.
------------------------------------------------------------------------
2007
------------------------------------------------------------------------
July 13........................ MMS authorizes Shell to conduct
additional geophysical operations in
Chukchi Sea Planning Area covering the
same area as their 2006 geophysical
permit.
------------------------------------------------------------------------
2008
------------------------------------------------------------------------
February 6..................... MMS holds Chukchi Sea Lease Sale 193.
Seven companies were issued leases
from this sale--NACRA; Repsol; Shell;
ConocoPhillips; Eni Petroleum;
StatoilHydro; and Iona Energy Company.
February 15.................... MMS authorizes Shell to conduct even
further geophysical operations, also
covering the same area as their 2006
geophysical permit.
------------------------------------------------------------------------
2009
------------------------------------------------------------------------
May 9.......................... Shell submits its initial EP for the
Chukchi Sea.
------------------------------------------------------------------------
2010
------------------------------------------------------------------------
April 10....................... BP Deepwater Horizon Incident--Blowout
of the Macondo well (Gulf of Mexico).
May 19......................... Secretary's Order 3299 reorganizing the
Minerals Management Service and
dividing its functions between three
separate bureaus.
June 18........................ Secretary's Order 3302 creating the
Bureau of Ocean Energy Management,
Regulation, and Enforcement (BOEMRE).
August 8....................... BOEMRE authorizes Statoil to conduct
geophysical operations within and
around the area where their leases
were located in the Chukchi Sea
Planning Area.
[[Page 79274]]
December 7..................... BOEMRE conditionally approves Shell's
initial EP for the Chukchi Sea.
------------------------------------------------------------------------
2011
------------------------------------------------------------------------
May 11......................... Shell submits a revised EP for the
Chukchi Sea.
August 29...................... Secretary's Order 3299 was amended to
divide BOEMRE into the Bureau of Ocean
Energy Management (BOEM), the Bureau
of Safety and Environmental
Enforcement (BSEE), and the Office of
Natural Resources Revenue (ONRR).
December 16.................... BOEM conditionally approves Shell's
revised EP for the Chukchi Sea.
------------------------------------------------------------------------
2012
------------------------------------------------------------------------
August 30...................... BSEE authorizes Shell to initiate
certain limited preparatory
exploration drilling activities;
drilling of the top hole for Burger A
exploration well in the Chukchi Sea.
September 9.................... Shell begins drilling operations for
its Burger A exploration well in the
Chukchi Sea, but was not able to
complete its well operations. Shell
returned in 2016 to complete its well
operations, ultimately plugging and
abandoning the well.
September 20................... While not applicable to the Chukchi
Sea, BSEE also authorizes Shell to
initiate drilling of the top hole for
the Sivuliq N exploration well in the
Beaufort Sea.
October 3...................... Shell begins drilling operations for
its Sivuliq N exploration well in the
Beaufort Sea, but was not able to
complete its well operations. Shell
returned in 2016 to complete its well
operations, ultimately plugging and
abandoning the well.
------------------------------------------------------------------------
2013
------------------------------------------------------------------------
August 5....................... BOEM authorizes TGS to conduct
geophysical operations for a portion
of Chukchi Sea Planning Area covering
a portion of the Sale 193 area.
November 6..................... Shell submits a revised EP for the
Chukchi Sea in response to lessons
learned from its 2012 drilling
operations of the Sivuliq N and Burger
A exploration wells.
------------------------------------------------------------------------
2014
------------------------------------------------------------------------
August 28...................... Shell submits a revised EP for the
Chukchi Sea, replacing its November
2013 submission.
------------------------------------------------------------------------
2015
------------------------------------------------------------------------
January 21..................... President Obama signed E.O. 13689,
which calls for multiple agencies that
may have jurisdictional
responsibilities in the Arctic to
enhance their coordination efforts to
protect the nation's various interests
in the region.
January 27..................... President Obama issues Presidential
Memorandum withdrawing certain areas
of the OCS within the Beaufort and
Chukchi Seas from leasing. These areas
included the Hannah Shoal in the
Chukchi Sea and lease deferral areas
identified in BOEM's 2012-2017
National OCS Oil and Gas Leasing
Program.
February 24.................... BSEE and BOEM published the 2015
Proposed Arctic Exploratory Drilling
Rule, providing a 90-day period for
the public to review and comment on
the proposed rule.
May 11......................... BOEM conditionally approves Shell's
revised EP for the Chukchi Sea.
July 22........................ BSEE authorizes Shell to initiate
certain limited preparatory
exploration drilling activities;
drilling of the top hole for Burger J
exploration well in the Chukchi Sea.
July 31........................ Shell begins drilling operations for
its Burger J exploration well in the
Chukchi Sea.
September 21................... Shell completes its Burger J
exploration operations, and ultimately
plugs and abandons the well.
October 16..................... The Department cancels all Beaufort and
Chukchi lease sales that were
scheduled to take place as part of
BOEM's 2012-2017 National OCS Oil and
Gas Leasing Program.
------------------------------------------------------------------------
2016
------------------------------------------------------------------------
December 30.................... President Obama issues a Presidential
Memorandum that expands the withdrawal
to all areas of the Chukchi Sea
planning area and much of the Beaufort
Sea planning area that were not
currently withdrawn at that time. The
withdrawal excludes Beaufort tracts
located nearshore in an area that
included existing leases at the time.
A key factor that contributed to the length of time taken to
authorize Shell's exploration drilling activities was a lawsuit filed
by the Native Village of Point Hope challenging the Department's
decision to hold Sale 193. See Native Village of Point Hope v. Salazar,
730 F. Supp.2d 1009 (D. Ak., 2010); see also Native Village of Point
Hope v. Jewell, 740 F.3d 489 (9th Cir., 2014). The original
Environmental Impact Statement (EIS) for Sale 193 was published in
2007, and the lease sale was held, but subsequent legal challenges and
Federal court decisions remanded the lease sale to BOEM for further
analysis. In response to the court remand, BOEM conducted additional
analysis and incorporated that information into a Supplemental EIS that
was published in February 2015 and affirmed the sale as held. Only
thereafter were BOEM and BSEE able to complete their formal review of
Shell's exploration plan for the Chukchi Sea and approve the drilling
activities that took place in the summer of 2015.
Between 2008 and 2019, oil prices remained unstable, increasing to
an all-time high of almost $96 per barrel in 2013 to $44 per barrel in
2015, which increased to $56 per barrel in 2019.\32\ Domestic oil
production had grown since 2008, in part due to developments in tight
oil onshore and Gulf of Mexico production, to about 9.4 million barrels
per day in 2015 and 12.2 million barrels in 2019.\33\ Demand for oil
remained relatively stable between 2008 and 2019, with only a minor
increase in 2019 over 2008--approximately a 4% increase.\34\
---------------------------------------------------------------------------
\32\ https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=F000000__3&f=M.
\33\ https://www.eia.gov/todayinenergy/detail.php?id=4910.
\34\ https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=MTTUPUS2&f=A, table titled ``U.S. Product
Supplied of Crude Oil and Petroleum Products (Thousand Barrels per
Day).
---------------------------------------------------------------------------
On September 28, 2015, Shell announced that it would cease further
exploration activity in offshore Alaska for the foreseeable future.
Shell stated that its decision was based on the results of their Burger
J well, which found indications of oil and gas, but were insufficient
to warrant further
[[Page 79275]]
exploration in the Burger prospect. The company also stated that its
decision was motivated by the high costs associated with the project,
and the challenging and unpredictable Federal regulatory environment
offshore Alaska.\35\ On November 17, 2015, Statoil announced its
decision to exit Alaska and relinquish its leases acquired from Sale
193. All leaseholders that acquired leases in Sale 193 eventually
relinquished their leases.
---------------------------------------------------------------------------
\35\ https://www.shell.com/media/news-and-media-releases/2015/shell-updates-on-alaska-exploration.html.
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Despite these setbacks, industry interest in the Arctic OCS and
other areas of the Arctic, globally, has shown to be consistent amidst
fluctuating commodity prices and concerns about regulatory challenges.
Since 1998, nineteen geological and geophysical seismic surveys were
permitted and completed for the Beaufort Sea and Chukchi Sea Planning
Areas. The data from these surveys provide information to both industry
and the government for use in lease sales and for design and evaluation
of activities described in EPs and DPPs. Several different companies
participated in each of the four Beaufort Sea Planning Area lease sales
and the one Chukchi Sea Planning Area lease sale indicating on-going
industry interest in the area. Companies submitted EPs, three in the
Beaufort and one in the Chukchi Sea. These plans, and their revisions,
received evaluation and conditional approval. BOEM approved two DPPs,
both for the Beaufort Sea. Currently, there are 19 oil and gas leases
in the Arctic OCS, all of which are located in the Beaufort Sea
Planning Area. Exploratory drilling and development on these leases
have taken place from gravel islands in State waters.
Global Arctic Exploration Activities
In addition to the Arctic OCS activities just described, global
interest and development has taken place in other parts of the Arctic.
Countries, such as Russia, Norway, Canada, and Greenland have been
diligently exploring their oil and gas resources in or near the Arctic.
Greenland--Since the 1970s, exploration activities have taken place
on the offshore waters of western Greenland. While these exploration
activities have taken place in sub-Arctic regions, operators do
experience some of the key challenges present in the Arctic. It is not
uncommon for icebergs to pose dangers to drilling operations. Operators
use ice management plans to identify, monitor, and tow away any
icebergs that may impact their exploration operations. Operators also
have contingency plans that may require disconnecting their drilling
rig from the well and moving off location to avoid contact with
icebergs.
Canada--In the Jeanne d'Arc, Orphan, and Flemish Pass oil and gas
basins on the Grand Banks of Newfoundland, operators have conducted
exploration drilling from MODUs in shallow and deep waters. Like
Greenland, the areas with oil and gas potential are located in sub-
Arctic regions that experience some seasonal sea ice and significant
iceberg incursions. In these areas, operators also employ strong ice
management and contingency plans.
Norway--In Norway's portion of the Barents Sea, which is located
entirely within the Arctic, exploration activities have taken place
since 1980. Most of the area is free of sea ice year-round, but
drilling has taken place in areas that do experience challenging Arctic
OCS conditions. As late as 2014, exploration drilling took place in
Norway's northern portion of the Barents Seas in what is known as the
Hoop area. Those exploration operations entailed the use of winterized
semisubmersible rigs and the availability of a capping stack.
Russia--Russia's latest drilling operations also took place in 2014
when ExxonMobil drilled a well in the South Kara Sea. The operation
took place in an area of the Arctic where drilling could not take place
during the winter months, similar to the Chukchi and Beaufort Seas.
Exploration activities took place during the summer, when little to no
sea ice was present at the drilling location and were completed in mid-
fall. The operation was similar to the operations from the other
countries just described--a winterized MODU and robust ice management
and contingency plans. However, unique to this project was the use of a
subsea isolation device (SSID). (NPC Report 2015 at 6-17 and 6-18, and
NPC Report 2019 at C-10). The Kara Sea project is discussed in more
detail below in Section II. Section-by-Section Discussion of Proposed
Changes, Subsection A. Key Revisions Proposed by BSEE, under the
subheading entitled, Supplemental Assessment to the 2015 Report on
Arctic Potential: Realizing the Promise of U.S. Arctic Oil and Gas
Resources (NPC 2019 Report).
Global Arctic Exploration Requirements
Norway, Canada, and Greenland have similar regulatory requirements
to the United States for Arctic offshore drilling operations performed
from a MODU. The Bratslavsky and SolstenXP study also included a review
of the regulatory requirements from these countries that pertain to
relief wells, SCCE, and approval of alternative technologies. The study
did not include Russia in its review because the country's regulations
could not be accessed. Here is a summary of that review:
Relief Wells--All the Arctic countries that were reviewed
specifically require relief wells, but regulations among them differ.
For example, Canada simply requires a ``same[hyphen]season'' relief
well capacity, whereby the operator demonstrates its capability to
drill a relief well and kill an out[hyphen]of[hyphen]control well in
the same drilling season. Whereas the U.S. requires the ability to
bring in a relief[hyphen]drilling rig and complete the plug and
abandonment within 45 days, Norway and Greenland require a
relief[hyphen]drilling rig to be on site within 12 days.
SCCE--Canada is the only country besides the U.S. that has
specific SCCE requirements. Canada's requirements, however, are less
prescriptive in that they include a more general requirement for ``cap
and containment methods and same[hyphen]well intervention methods,'' as
compared to the U.S. requirement for access to specific SCCE equipment
within a specified time period.
Alternative Technologies--With respect to approval of
alternative technologies in lieu of a relief rig or SCCE, the U.S. has
specific regulations that allow for potential substitutions and
accommodations for innovative technologies. Canada also provides for
the approval of alternative technologies through specific approval
processes. Norway's regulations, in general, are largely performance-
based. As such, their regulations allow for the consideration of
different technologies at the onset when planning a project.
B. BSEE and BOEM Statutory and Regulatory Authority and
Responsibilities
The Outer Continental Shelf Lands Act, 43 U.S.C. 1331 et seq., was
first enacted in 1953 and substantially amended in 1978. In amending
OCSLA, Congress established a national policy of making the OCS
``available for expeditious and orderly development, subject to
environmental safeguards, in a manner which is consistent with the
maintenance of competition and other national needs.'' (43 U.S.C.
1332(3)). OCSLA authorizes the Secretary of the Interior (Secretary) to
lease the OCS for mineral development and to regulate oil and gas
exploration, development, and production operations on the OCS.
On May 19, 2010, Secretary Ken Salazar issued S.O. 3299, which
[[Page 79276]]
restructured and divided the former MMS's responsibilities under OCSLA
among three new bureaus: (i) BOEM; (ii) BSEE; and the (iii) Office of
Natural Resources Revenue (ONRR). S.O. 3299 delegated those
responsibilities for oil and gas operations to BSEE and BOEM, both of
which are charged with administering and regulating aspects of the
Nation's OCS oil and gas program (see 30 CFR parts 250 and 550).
On June 18, 2010, Secretary Salazar issued S.O. No. 3302, which
announced the name change of part of the former MMS to the Bureau of
Ocean Energy Management, Regulation and Enforcement (BOEMRE). This
name, BOEMRE, would remain in effect until BOEM and BSEE were
officially created under S.O. 3299, effective October 1, 2011.
On October 1, 2010, the revenue-collection functions of the former
MMS were transferred to ONRR, reporting to the Assistant Secretary for
Policy, Management and Budget.
S.O. 3299 assigned BOEM the responsibility for managing the
development of the Nation's offshore conventional and renewable energy
resources. BOEM's mission is to manage the development of the OCS
energy and mineral resources in an environmentally and economically
responsible way. BOEM's functions include: Leasing; EP administration;
DPP administration; permitting of geological and geophysical
activities; environmental analyses in compliance with NEPA;
environmental studies; compliance with relevant laws (e.g., the
Endangered Species Act (ESA), the Marine Mammal Protection Act, the
Magnuson-Stevens Fishery Conservation and Management Act, and the
Coastal Zone Management Act \36\ (CZMA)); resource evaluation; oil
spill worst case discharge (WCD) determination; economic analysis and
fair market value bid/lease evaluations; management of the OCS
renewable energy and marine mineral programs; and consultation with
other entities at the local (e.g., North Slope Borough, Native
Villages), tribal (e.g., Federally recognized tribes and Alaska Native
Claims Settlement Act Corporations), State, and Federal levels (e.g.,
National Oceanic and Atmospheric Administration (NOAA) Fisheries, U.S.
Coast Guard (USCG)) related to activities within BOEM's activities and
areas of responsibility.
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\36\ BOEM is not subject to the requirements of the CZMA in
Alaska as it is on the rest of the OCS, where it is required to
provide opportunities to the coastal State to review the proposed
Federal actions for consistency with the state's federally approved
coastal management program. More specifically, on July 1, 2011,
Alaska repealed its CZMA program.
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Secretary's Order 3299 made BSEE responsible for safety and
environmental enforcement functions, including, but not limited to, the
authority to permit activities, inspect, investigate, summon witnesses
and produce evidence: Levy penalties; cancel or suspend activities; and
oversee safety, and oil spill response and removal preparedness. BSEE's
mission is to promote safety, protect the environment, and conserve
resources through vigorous regulatory oversight and enforcement. BSEE's
functions include evaluating permit applications for post-lease oil and
natural gas exploration and development activities on the OCS and
conducting inspections to ensure compliance with laws, regulations,
lease terms, and approved plans and permits.
BOEM evaluates EPs, and BSEE, thereafter, evaluates Applications
for Permits to Drill (APDs) and other permits and applications, to
determine whether the operator's proposed activities meet OCSLA's
standards and each Bureau's regulations governing OCS exploration.
Based on their respective evaluations, BSEE and BOEM will either
approve the operator's EP and APD, require the operator to modify its
submissions, or disapprove the EP or APD (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 was intended to facilitate the prompt sharing of information
among the relevant Federal agencies that may be involved in overseeing
exploratory drilling operations conducted from MODUs. The operator may
then submit an EP to BOEM for approval. An EP must include information
such as a schedule of anticipated exploration activities, equipment to
be used, the general location of each well to be drilled, and any other
information deemed pertinent by BOEM (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 to BSEE an APD, which BSEE must approve before an
operator 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 blowout
preventer (BOP) systems, MODU (if one is to be used), and any
additional information requested by the BSEE District Manager.
C. Executive and Secretary's Orders
On March 28, 2017, the President issued E.O. 13783--Promoting
Energy Independence and Economic Growth (82 FR 16093). The E.O.
directed Federal agencies to review all existing regulations and other
similar agency actions, which potentially burden the development or use
of domestically produced energy resources with the goal of ``avoiding
regulatory burdens that unnecessarily encumber energy production,
constrain economic growth, and prevent job creation.'' It made it U.S.
policy for agencies to ``review existing regulations that potentially
burden the development or use of domestically produced energy resources
and appropriately suspend, revise, or rescind those that unduly burden
the development of domestic energy resources beyond the degree
necessary to protect the public interest or otherwise comply with the
law.''
On April 28, 2017, the President issued E.O. 13795--Implementing an
America-First Offshore Energy Strategy (82 FR 20815), which directed
the Secretary to ``take all steps necessary to review'' the 2016 Arctic
Exploratory Drilling Rule and, ``if appropriate, [to,] as soon as
practicable and consistent with law, publish for notice and comment a
proposed rule suspending, revising, or rescinding this rule.'' The
policy underlying E.O. 13795 is ``to encourage energy exploration and
production, including on the Outer Continental Shelf, in order to
maintain the Nation's position as a global energy leader and foster
energy security and resilience for the benefit of the American people,
while ensuring that any such activity is safe and environmentally
responsible.'' These E.O.s did not dictate outcomes; rather, they
provided direction for review in accordance with all relevant laws.
To further implement E.O. 13795, on May 1, 2017, the Secretary
issued S.O. 3350, America-First Offshore Energy Strategy, directing
BSEE and BOEM to review the 2016 Arctic Exploratory
[[Page 79277]]
Drilling Rule ``for consistency with the policy set forth in section 2
of E.O. 13795'' and to prepare a report ``summarizing the review and
providing recommendations on whether to suspend, revise, or rescind the
rule.''
Consistent with E.O.s 13783 and 13795, and S.O. 3350, BSEE and BOEM
reviewed the regulations promulgated through the 2016 Arctic
Exploratory Drilling Rule and are proposing revisions to those
regulations to reduce unnecessary burdens on industry while maintaining
safety and environmental protection.
D. Purpose and Summary of the Rulemaking
BSEE and BOEM promulgated the 2016 Arctic Exploratory Drilling Rule
based on experiences gained from Shell's 2012 and 2015 Arctic
operations, internal reviews conducted on potential oil and gas
operations on the Arctic OCS, and concerns expressed by environmental
organizations and Alaska Natives.
Since publication of the 2016 Arctic Exploratory Drilling Rule,
however, BSEE and BOEM have become aware of additional information
informing and warranting the bureaus' reconsideration of certain
regulatory provisions promulgated through that rule. BSEE commissioned
a Technology Assessment Program study (Bratslavsky and SolstenXP, 2018)
that entailed a historical statistical analysis of recent Alaska Arctic
OCS drilling seasons (5-year period between 2012 and 2016), in which
meteorology and physical oceanographic (``metocean'') and operational
conditions would support the safe deployment of SCCE, the drilling of a
relief well, or both. The study included a comprehensive review and gap
analysis of U.S. and international regulations, standards, recommended
practices, specifications, technical reports, and common industry
methods regarding the safe deployment of SCCE, as compared to the
effectiveness of drilling a relief well in Arctic conditions.
The Bratslavsky and SolstenXP study determined that metocean
conditions prevalent in the Chukchi Sea and Beaufort Sea (i.e., rough
sea states and sea ice conditions, primarily) are key factors that
limit the ability to safely deploy SCCE throughout the Arctic OCS. The
study determined that, when operating in the presence of sea ice in the
Chukchi Sea and the Beaufort Sea, there is a greater probability for
safe relief well deployment versus SCCE deployment. When operating in
open water conditions (i.e., those prone to 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 wells and SCCE is the same. This is because the
Beaufort Sea has fewer ice-free days than the Chukchi and ice helps
maintain calm sea state conditions.
The study also determined that water depth in the Arctic OCS is
also a factor limiting the safe deployment of SCCE. According to the
Bratslavsky and SolstenXP study, safe deployment of SCCE is likely to
be impaired in water depths shallower than 984 feet because the
equipment would potentially encounter a gas boil at the surface caused
by a subsea blowing well (Bratslavsky and SolstenXP at 143). Water
depths in the majority of the Chukchi Sea and Beaufort Sea where
exploration has historically occurred are relatively shallow--167 feet
or less (id. at 7 to 9). This water depth range limits the fleet of
support vessels that could be used for the safe deployment of SCCE.
The NPC also published its NPC 2019 Report as a supplemental
assessment to the NPC 2015 Report. The NPC prepared the NPC 2019 Report
in response to an April 2018 request from the Secretary of Energy. The
Secretary of Energy requested that the NPC provide recommendations for
enhancing the Nation's regulatory environment by improving reliability,
safety, efficiency, and environmental stewardship of oil and gas
activities on the OCS. That report specifically addressed the
regulatory burdens associated with U.S. Arctic OCS development.
Key findings from the NPC's supplemental assessment that helped
inform the preparation of this proposed rule include the NPC's
determination that the requirement to drill an SSRW to mitigate the
risk of a late season well control event continuing over the winter
season is ``outdated.'' The report concluded that SSIDs and capping
stacks are superior solutions that could stop the flow of oil and allow
intervention through the original borehole before a relief well could
be completed (NPC 2109 Report at 19). Details in the report regarding
Russia's 2014 drilling operation that included the use of an SSID in
the South Kara Sea also informs this proposed rule.
In this proposed rule, the Bureaus also address other issues in
addition to those addressed in the 2016 Arctic Exploratory Drilling
Rule, including seasonal weather-related constraints in the Arctic that
severely impact an operator's ability to safely perform leaseholding
operations for a significant portion of the term on a lease. While
these issues are in addition to the issues addressed by the 2016 Arctic
Exploratory Drilling Rule, they are unique to the Arctic OCS and,
therefore, are appropriate to address as part of this proposed
rulemaking.
BSEE and BOEM recognize that the 2016 Arctic Exploratory Drilling
Rule addressed specific operational and environmental conditions that
are unique to the Arctic OCS. While this proposed rule would leave most
of the regulations promulgated by the 2016 rule unaltered, certain of
these regulations are worth reconsidering to accommodate technological
innovation and encourage energy exploration on the Arctic OCS. Based on
the new scientific information gathered from the Bratslavsky and
SolstenXP study, and global practical experience gained in recent
years, as described in the NPC Reports, the bureaus believe that these
proposed revisions reduce unnecessary regulatory burdens on
stakeholders and increase the ability to review and apply advancing
technological innovations, while ensuring safety and environmental
protection.
The following paragraphs briefly summarize the key elements of this
proposed rule, which are more fully explained in Section II. Section-
by-Section Discussion of Proposed Changes of this preamble:
1. Seasonal Conditions SOO--The unique seasonal conditions in the
Arctic make it difficult or physically impossible for operators to
explore their leases for a significant portion of each year. To
facilitate the proper development of Arctic leases in accordance with
OCSLA sec. 5,\37\ BSEE proposes to add a new provision to its
regulations that would provide those operators that are conducting
drilling operations, but are prevented from completing those
leaseholding operations due to seasonal constraints unique to the
Arctic, with the opportunity to obtain an SOO. If granted, this type of
SOO would suspend the running of the lease term and effectively extend
the term of the affected lease by a period equivalent to the period of
such suspension. This would provide operators that are otherwise ready
and able to conduct drilling operations with additional time to
diligently explore their leases, without facing lease expiration due to
[[Page 79278]]
interference by seasonal constraints unique to the Arctic.
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\37\ OCSLA sec. 5 (as amended) provides in pertinent part: ``The
regulations prescribed by the Secretary . . . shall include . . .
provisions . . . for the suspension . . . of any operation or
activity . . . at the request of a lessee, in the national interest,
[or] to facilitate proper development of a lease . . . and for the
extension of any permit or lease affected by [such] suspension . . .
by a period equivalent to the period of such suspension . . . .'' 43
U.S.C. 1334(a)(1).
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2. Water-Based Mud and Cuttings--BSEE proposes to eliminate
references to the Regional Supervisor's discretionary authority to
require the capture of water-based muds and cuttings in those cases
where subsistence values might be impacted by such discharges. While
not intended, BSEE understands that this reference created some
uncertainty for the regulated industry, because it appeared to overlap
with regulation by the Environmental Protection Agency (EPA) and, if
implemented, might result in BSEE issuing requirements that contradict
EPA's requirements.
3. SCCE--BSEE would preserve the requirement for the operator to
have access to its SCCE when drilling below or working below the
surface casing. However, with respect to the capping stack, the Bureau
proposes to provide an opportunity to the operator to adjust the point
in time during operations when it must position its capping stack so
that it is available to arrive at the well location within 24 hours
after a loss of well control. The existing regulations also impose a
positioning requirement on the cap and flow system, and containment
dome--slightly different from the capping stack--``positioned to ensure
that it will arrive at the well location within 7 days after a loss of
well control.'' BSEE's proposed changes to the positioning requirement
for the cap and flow system and containment dome are discussed in more
detail later in this paragraph. If the operator is able to demonstrate
to BSEE, based on documentation it submits as part of its APD, that the
operations it plans to conduct below the surface casing would not
encounter any abnormally 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 other available data and
information. As previously mentioned, BSEE also proposes to eliminate
the requirement for the operator to ensure that the containment dome
and cap and flow system are positioned so as to arrive at the well
location within seven days after a loss of well control. The
Bratslavsky and SolstenXP study evaluated current industry methods and
standards for deploying SCCE in Arctic OCS conditions, and determined
that 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 BSEE's
regulations to prescribe that certain SCCE (containment dome and cap
and flow system, in particular) be positioned within proximity to a
well location when the conditions for safely deploying this equipment
in the Arctic OCS are limiting. However, BSEE would retain other
existing containment dome and cap and flow system requirements in Sec.
250.471, which provide that the operator must:
(i) Demonstrate that it has access to a containment dome and cap
and flow system;
(ii) Provide a containment dome and cap and flow system that meets
BSEE's operating standards;
(iii) Conduct tests or exercises for all SCCE; and
(iv) Maintain records pertaining to the testing, inspection,
maintenance, and use of the SCCE and make these available to BSEE upon
request. The changes BSEE proposes to the SCCE requirements in Sec.
250.471 would preserve the regulations' requirement that operators have
redundant protective measures that are appropriate for Arctic OCS
conditions because there is no guarantee that a single measure could
control or contain a WCD.
4. Same Season Relief Well (SSRW) Requirement and Subsea Isolation
Devices (SSID)--BSEE proposes to revise the relief rig and SSRW
requirements by providing the operator with the option of using an SSID
or having access to a relief rig as an additional means to secure the
well in the event of a loss of well control, if the operator will be
conducting exploratory drilling operations from a MODU. In addition,
BSEE proposes to provide an opportunity to the operator to adjust the
point in time during operations when it must stage its relief rig (if
the operator elects to have access to a relief rig) when conducting
Arctic OCS exploratory drilling operations--from when drilling below or
working below the ``surface casing'' to when drilling below or working
below the ``last casing point prior to penetrating a zone capable of
flowing hydrocarbons in measurable quantities.'' If the operator is
able to demonstrate to BSEE, based on 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.
5. Mudline Cellars--BSEE proposes to clarify the requirement for
the operator, in areas of ice scour, to use a mudline cellar when
drilling that is designed to minimize the risk of damage to the well
head and wellbore. The existing regulation could be read to require the
operator to use a mudline cellar in all cases, except when the operator
can prove that the mudline cellar would present an operational risk,
and that was not BSEE's intent. This proposed change would make it
clear that the operator has more flexibility to propose to employ
alternate procedures or equipment instead of the mudline cellar under
appropriate circumstances, as provided by the longstanding provisions
of 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.
6. IOP--BOEM proposes to eliminate the requirement that the
operator submit an IOP because it requires submission of information
that overlaps with that required in the EP and the IOP's early
information sharing is unnecessary in light of BOEM's practice for
reviewing and coordinating review of the EP. Consequently, the operator
is already aware that it must plan for how it will reduce operational
risks and address the challenges associated with operations on the
Arctic OCS through its EP.
[[Page 79279]]
E. Partner Engagement in Preparation for This Proposed Rule
1. Summary of Partner Interaction
In advance of publishing this proposed rule, BSEE and BOEM reached
out to Alaska Native tribal leaders, ANCSA corporations, and native
village leaders in Northern Alaska for Government-to-Government
consultations and municipal meetings. These Bureaus arranged
consultations and meetings to receive input from these groups on
potential regulatory changes that could encourage energy exploration
and production and reduce unnecessary regulatory burdens, while
maintaining safety and environmental protection. Between November 29,
2018 and January 30, 2019, BSEE and BOEM officials met with 23 tribal,
ANCSA corporation, and municipal leaders at villages throughout
Northern Alaska (Kotzebue, Point Hope, Utqiagvik [i.e., Barrow],
Nuiqsut, and Kaktovik), in Fairbanks, and in Anchorage. In addition,
BSEE and BOEM held a consultation meeting via a conference call with
tribal representatives from the Native Village of Point Lay. The
following list identifies the entities with which BSEE and BOEM met:
Tribal Governments--Native Village of Utqiagvik, Native
Village of Wainwright, Native Village of Kotzebue, Native Village of
Point Hope, Native Village of Nuiqsut, Native Village of Kaktovik,
Tanana Chiefs Conference, and Native Village of Point Lay;
Native Corporations--Olgoonik Native Corporation, Doyon
Limited, Arctic Slope Regional Corporation, Tikigaq Native Corporation,
Cully Corporation, Kuukpik Corporation, and Kaktovik Inupiat
Corporation;
Municipal Governments--Northwest Arctic Borough, Point
Hope, North Slope Borough, City of Utqiagvik, Nuiqsut, and Kaktovik;
and,
Other Tribal Organizations--ICAS and the AEWC.
BSEE and BOEM shared information with the tribal representatives
describing potential options for regulatory change that the Bureaus
were considering at the time the meetings took place. BSEE and BOEM
made multiple attempts to contact two corporations--Kikiktagruk
Corporation and NANA Regional Corporation but did not receive a
response from them.
2. Summary of Comments Received
BSEE and BOEM heard a variety of perspectives during these meetings
with Alaska Natives. The most common comment received was a concern
over food security. Subsistence resources, including bowhead and beluga
whales, other marine mammals, fish, and birds, are a key food source
for many peoples' diets in the native villages. The Alaska Natives'
primary concerns pertained to protecting their food sources. BSEE and
BOEM are fully aware that subsistence resources play a key role in
offsetting the high costs of conventional food supplies and that
subsistence hunting and fishing play a key role in the cultural
identity of Alaska Natives. BOEM's leases all contain provisions
related to the protection of these subsistence uses and BOEM's
regulations at Sec. Sec. 550.227(b)(7) and 550.261(b)(7) require
lessees to explain how they propose to protect these subsistence uses.
In addition, BSEE and BOEM are not proposing any regulatory changes
that would adversely affect protection of subsistence uses.
Certain tribal representatives, and most ANCSA corporations, were
supportive of this rulemaking, and explained that it could help attract
more economic opportunities to their villages. In some cases, tribes or
corporations advocated for the use of their villages to support safer
oil and gas operations, because the villages have deeper ports that
could support larger vessels, or because they may be located closer to
potential drilling operations than those ports or facilities that have
been used in the past. This could allow for quicker response to
emergency incidents.
BSEE did not include any regulatory changes in this proposed rule
specifically designed to respond to this comment. While requiring the
staging of equipment at strategically located coastal depots could have
a positive impact on oil spill responses in the Arctic, the
identification and placement of depots for such resources falls to the
discretion of the operator (within the parameters established by
existing regulation). To provide each plan holder with the flexibility
needed to respond to their WCD scenarios, BSEE's Oil Spill Response
Plan (OSRP) regulations do not mandate the use of any particular
staging location(s) for equipment and personnel. BSEE will review the
operator's staging arrangements submitted as part of the proposed OSRP
to ensure that the OSRP would fully comply with the planning
requirements in the governing regulations.
Other comments provided during the consultation meetings included a
recommendation for BSEE and BOEM to provide broader outreach by
presenting this proposed rule to their tribal assembly and to citizens
within the communities.
DOI strives to strengthen its government-to-government relationship
with federally recognized tribes through a commitment to consultation
with tribes and recognition of their right to self-governance and
tribal sovereignty. E.O. 13175, Consultation and Coordination with
Indian Tribal Governments and DOI's tribal consultation policy, which
implements the E.O., provide for procedures for consultation with
tribes when taking an action with tribal implications. DOI has extended
its consultation policy to ANCSA corporations. Furthermore, BSEE and
BOEM recently issued their own expanded tribal consultation guidance on
August 20, 2019 and June 29, 2018, respectively. BSEE's guidance
(Bureau of Safety and Environmental Enforcement (BSEE) Tribal
Consultation Guidance, August 20, 2019, available at https://www.bsee.gov/bsee-tribal-guidance-2019) and BOEM's guidance (BOEM
Tribal Consultation Guidance, June 29, 2018, available at https://www.boem.gov/Tribal-Engagement/), identify various consultation
authorities that BSEE and BOEM will follow in consulting with tribes
and ANCSA corporations.
DOI recognizes and respects the distinct, unique, and individual
cultural traditions and values of Alaska Native people and the
statutory relationship between ANCSA Corporations and the Federal
Government. BSEE and BOEM will endeavor to go above and beyond their
consultation responsibilities where and when appropriate throughout the
rulemaking process to maintain a strong working relationship with their
tribal and ANCSA corporation partners.
BSEE and BOEM also received a comment from one of the ANCSA
corporations recommending that this rulemaking take into account the
NPC 2019 Report. BSEE and BOEM considered the NPC reports when
preparing this proposed rule and based some of the proposed regulatory
revisions on that report's recommendations, as discussed more fully
below.
Another common comment that BSEE and BOEM received was a
recommendation to include a requirement for a CAA between the oil and
gas operator and those whaling communities potentially affected by an
operator's proposed drilling project. A CAA is typically established
through a collaborative process whereby both parties work to create
mitigation strategies that would avoid adverse impacts to bowhead
whales and other marine mammals, their habitat, and hunting
opportunities. Historically, operators have voluntarily used the CAA
process and, currently, existing lessees are required to do so through
[[Page 79280]]
lease stipulations.\38\ See discussion in Section I.E.3, History and
Background on the Conflict Avoidance Agreement, of this preamble
describing the history and background of the CAA. In addition, under
the MMPA, the taking of marine mammals without a permit or exception is
prohibited in order to prevent the decline of species and populations.
To avoid liability for take, operators must obtain an Incidental Take
Authorization or Incidental Harassment Authorization for activities
related to offshore exploration, development and production.
Implementation of the MMPA is shared between NMFS and USFWS.
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\38\ Every BOEM Arctic lease contains a variant of the following
stipulation: ``Prior to submitting an exploration plan or
development and production plan (including associated oil-spill
contingency plans) to MMS for activities proposed during the bowhead
whale migration period, the lessee shall consult with the directly
affected subsistence communities, Barrow, Kaktovik, or Nuiqsut, the
North Slope Borough (NSB), and the AEWC to discuss potential
conflicts with the siting, timing, and methods of proposed
operations and safeguards or mitigating measures which could be
implemented by the operator to prevent unreasonable conflicts.
Through this consultation, the lessee shall make every reasonable
effort, including such mechanisms as a conflict avoidance agreement,
to assure that exploration, development, and production activities
are compatible with whaling and other subsistence hunting activities
and will not result in unreasonable interference with subsistence
harvests.
A discussion of resolutions reached during this consultation
process and plans for continued consultation shall be included in
the exploration plan or the development and production plan. In
particular, the lessee shall show in the plan how its activities, in
combination with other activities in the area, will be scheduled and
located to prevent unreasonable conflicts with subsistence
activities.''
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Section 7(a)(2) of the ESA requires every Federal agency to ensure
that any action they authorize, fund, or carry out is not likely to
jeopardize the continued existence of a listed species or result in the
adverse modification of designated critical habitat. When any
exploration or development plan, or G&G permit application, is
submitted to BOEM, BOEM evaluates the proposal, and consults with NMFS
and USFWS on species listed under the ESA. During this process,
mitigation measures (e.g., vessel speed restrictions, rig lighting
specifications, and protected species observer requirements) are
developed to reduce impacts to protected species. These measures are
then included in BOEM's conditions of approval for the EP, DPP, or G&G
permit.
BOEM did not include any regulatory changes in this proposed rule
specifically designed to respond to this comment. BOEM cannot require
whaling communities to establish agreements with operators, since BOEM
has no jurisdiction over such communities. Such a requirement for
lessees and operators to execute an agreement could give a third-party
power to set conditions for, or veto, OCS activities over which they
otherwise have no authority.
For those reasons, BOEM has concluded that a regulation would not
result in any additional protections of subsistence whaling beyond
those provided by its longstanding practice of addressing the issue in
a lease stipulation. BOEM has included as a lease stipulation for all
Arctic OCS lease sales since 1991 that the lessee must make every
reasonable effort, including such mechanisms as a CAA, to assure that
exploration, development, and production activities are compatible with
whaling and other subsistence hunting activities and will not result in
unreasonable interference with subsistence harvests. Implementation of
the stipulation must be described in an EP under Sec. 550.222. In
addition, either BOEM or BSEE may require additional mitigation
measures at the EP or the APD stages, as necessary, to appropriately
address potential interference with subsistence activities. For
example, because subsistence hunters are concerned that the effects of
offshore oil and gas exploration might displace migrating bowhead
whales and other marine mammals (like beluga whales), the Bureaus will
meet with the AEWC and its whaling captains to help document
traditional knowledge pertaining to bowhead whales, including movement
and behavior.
Given the importance of subsistence activities and related socio-
cultural activities to the Alaska Native communities, BOEM has long
encouraged operators to work directly with interested parties to help
mitigate potential impacts to subsistence activities. In addition, BOEM
funds and supports studies to better understand the potential impacts
from OCS operations on marine mammals and subsistence activities. Over
the last 46 years, the environmental studies program has provided more
than $1.2 billion nationally for scientific research on the OCS. Nearly
$500 million of that amount has funded studies in Alaska to produce
more than 1,000 technical reports and innumerable peer reviewed
publications. BOEM uses information from the studies program to
evaluate the potential environmental effects of leasing OCS lands for
exploration and development. Since July 2016, BOEM has completed 35
environmental studies and has 23 ongoing studies that cover the Arctic,
totaling nearly $72 million. While environmental conditions change and
continue to change (e.g., walrus habitat, bowhead whale migration, and
ice coverage), BOEM's environmental studies program both adds to our
understanding and tracks these changes to have the best science
available for the public, industry, and federal permitting decisions.
While BOEM has observed changes through these studies, these changes
follow the trajectory that BOEM has been studying and documenting for
several decades. While this proposed rule would change how operators
could explore for OCS resources in the Arctic, there are ample
opportunities to permit these activities consistent with ESA, MMPA,
NEPA, and consultation with Alaska Native communities.
3. History and Background on the Conflict Avoidance Agreement
In 1977, the IWC expressed concern over the low bowhead whale
population. Its report specifically mentioned that the future expansion
of offshore oil and gas extraction in the Arctic posed a potential risk
to the bowhead whale population. At that time, Inuit subsistence
hunters knew that bowhead whales were sensitive to anthropogenic noise,
movements, and even smells. There were concerns that increased activity
would affect their hunt. Traditional hunters had noticed that boat
traffic, seismic exploration, and drilling were causing migrating
whales to deflect away from the shore and beyond the hunters' reach.
Beginning in 1986, offshore stakeholders, such as representatives
from whaling villages, the AEWC, and oil and gas companies, have all
met to identify sources of potential conflict, and have relied on local
traditional knowledge as well as other information. CAAs were developed
first in the 1980s to address these sources of potential conflict and
have been referenced in lease stipulations since 1991.
Since 1991, all leases in the Arctic issued by BOEM or its
predecessors have included a stipulation requiring the operator to
coordinate their activities with potentially affected Alaska native
communities. While the text of these stipulations has varied from time
to time, all of them have included certain important components. The
following is an extract from such a stipulation, incorporated into the
leases issued from the Oil and Gas Lease Sale Number 202, issued on
April 18, 2007:
Prior to submitting an exploration plan or development and
production plan (including associated oil-spill contingency plans)
to MMS for activities proposed during the bowhead whale migration
period, the lessee shall consult with the directly affected
subsistence communities, Barrow, Kaktovik, or Nuiqsut, the North
Slope Borough (NSB),
[[Page 79281]]
and the Alaska Eskimo Whaling Commission (AEWC) to discuss potential
conflicts with the siting, timing, and methods of proposed
operations and safeguards or mitigating measures which could be
implemented by the operator to prevent unreasonable conflicts.
Through this consultation, the lessee shall make every reasonable
effort, including such mechanisms as a conflict avoidance agreement,
to assure that exploration, development, and production activities
are compatible with whaling and other subsistence hunting activities
and will not result in unreasonable interference with subsistence
harvests.
Because this stipulation was provided for in the lease sale notice
and included in the lease agreements resulting from the lease sale, its
requirements became binding for all leases issued as a result of that
particular lease sale.
The intent of this stipulation is for the operator to make a
reasonable effort to establish a CAA with potentially affected whaling
or subsistence hunting communities. It is the operator's responsibility
to attempt to reach agreement on a CAA with those communities.
II. Section-by-Section Discussion of Proposed Changes
This section provides explanations of and justifications for each
of the specific regulatory changes proposed in this document. Since
this is a joint BSEE and BOEM proposed rulemaking, this Section-by-
Section discussion is organized according to the order in which the
relevant provisions would appear in the CFR. BSEE's and BOEM's
regulations are found in the CFR at Title 30--Mineral Resources, Volume
2; BSEE's regulations are in Chapter II, and BOEM's regulations are in
Chapter V.
A. Key Revisions Proposed by BSEE
Title 30, Chapter II, Subchapter B, Part 250
Subpart A--General
Definitions. (Sec. 250.105)
BSEE proposes to revise the definition of Capping Stack by deleting
the phrase ``including one that is pre-positioned'' from the
definition. BSEE included this phrase as part of the 2016 Arctic
Exploratory Drilling Rule in response to a suggestion that the
definition in the 2015 Arctic Proposed Rule should be expanded to allow
pre-positioned capping stacks to be used below subsea BOPs when deemed
technically and operationally appropriate. Recognizing that the comment
was helpful, BSEE agreed with the suggestion and added the phrase
``including one that is pre-positioned'' to the capping stack
definition (see 81 FR 46492). As a practical matter, pre-positioned
capping stacks are similar to SSIDs. Accordingly, this modification in
the 2016 final rule effectively allows the operator to install an SSID
below a subsea BOP and would be in compliance with the capping stack
requirement in the existing Sec. 250.471, What are the requirements
for Arctic OCS source control and containment? Existing Sec.
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, as
previously mentioned, aligns closely with an SSID. The Bureau 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? This proposed revision would provide
clarity concerning the capping stack requirements under Sec. 250.471,
specifically that 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. The new SSID option that BSEE is proposing under Sec.
250.472 does not, and is not intended to, replace any of the SCCE
requirements in proposed Sec. 250.471(a), where BSEE's capping stack
requirement is addressed.
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 the Arctic OCS. This proposed
revision is consistent with OCSLA's requirement that the Secretary
promulgate suspensions regulations that ``facilitate proper development
of a lease . . . .'' \39\ The proposed regulation would list the
factors upon which BSEE may rely when determining whether to grant an
SOO and include when an operator:
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\39\ OCSLA sec. 5, as amended, codified at 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: A MODU, an artificial gravel island or a
gravity-based structure, or an artificial ice island; and
(3) is not able to safely continue its operations due to the
presence of seasonal ice, temporary seasonal drilling restrictions in
its approved oil spill response plan, or seasonal temperature changes
(respectively, for each facility type).
Currently, BOEM issues Alaska OCS leases with the maximum 10-year
primary lease term allowed under OCSLA.\40\ However, operators may be
precluded from properly developing leases because it is not possible to
conduct leaseholding operations for significant portions of those 10-
year terms. Offshore drilling locations on the Arctic OCS are
inaccessible for a significant portion of each year, due to seasonal
changes that make operating conditions unsafe or otherwise preclude
operations. Moreover, it is difficult to predict precisely when sea ice
will persist or break-up.
---------------------------------------------------------------------------
\40\ OCSLA sec. 8, as amended, states in part: ``An oil and gas
lease issued pursuant [OCSLA] shall be for an initial period of (A)
five years; or (B) not to exceed ten years where the Secretary finds
that such longer period is necessary to encourage exploration and
development in areas because of unusually deep water or other
unusually adverse conditions . . . .'' 43 U.S.C. 1337(b).
---------------------------------------------------------------------------
MODUs--For example, drilling operations performed from a MODU may
occur only during the open-water drilling season (generally late June
to early November), when sea ice is non-existent or minimal. This
practical limitation, without considering other logistical problems
unique to the Arctic OCS, could mean that during a consecutive 10-year
period, a lease may be unavailable for operations for approximately 70
percent of the time.
Artificial Gravel Islands or 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, because of the potential impact of weather
and ice conditions on potential oil spill response and cleanup efforts.
In particular, response and cleanup techniques for a large spill are
not as effective when sea ice is broken and unconsolidated around the
drilling location. By contrast, response and
[[Page 79282]]
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 a steel drilling caisson(s).
Artificial Ice Islands--A similar issue would be encountered if
drilling were to take place from a man-made ice island. In those cases,
the drilling location would be accessible only during the winter season
when temperatures are very low, and the area is completely covered by
ice stable enough to safely support a drilling rig and associated
equipment. As temperatures rise during the spring and summer seasons,
the ice breaks or melts away, making the drilling location inaccessible
until the next winter season.
The new paragraph (d) of Sec. 250.175 would facilitate the proper
development of a lease by addressing those seasonal conditions that
limit leaseholding operations by providing an operator ready and able
to complete its operations with the opportunity to obtain an SOO. If
granted, this SOO would suspend the running of the lease term and
effectively extend the term of the affected lease by a period
equivalent to the period of such suspension. The SOO would allow a
diligent operator to use the full 10 years in a 10-year lease term to
explore for hydrocarbons, without the concern for a lease expiring
because Arctic seasonal constraints prevented operations.
BSEE would continue to require the operator to comply with the
existing requirements for requesting a suspension under existing Sec.
250.171, How do I request a suspension? For example, Sec. 250.171
requires the operator to submit a reasonable schedule of work for
resuming the suspended operations on the subject lease for which the
operator requests the suspension. A schedule of work typically includes
milestones describing what activities the operator will perform to
resume operations and when those operations will be performed. If the
operator submits a schedule of work that demonstrates a reasonable plan
and schedule for resuming operations, BSEE will typically grant the SOO
(assuming the other requirements are satisfied). BSEE will use the
reasonable schedule of work as an established measuring stick by which
the Bureau would assess the operator's diligence and progress toward
prudent development. If the operator does not adhere to its approved
work schedule, BSEE may terminate the SOO under existing regulations.
Paragraph (e) of existing Sec. 250.170, How long does a suspension
last? authorizes BSEE to terminate any suspension when the Regional
Supervisor determines the circumstances that justified the suspension
no longer exist. Because a reasonable schedule of work serves as a
required foundation for BSEE's SOO approval, the operator's adherence
to that schedule is necessary to maintain the SOO. This allows BSEE to
ensure that the operator complies with the OCSLA Congressional
declaration of purpose. Other regulations under Subpart A that would
also apply to BSEE's implementation of proposed paragraph (d) of Sec.
250.175 includes Sec. 250.170, How long does a suspension last? which
allows BSEE to issue a suspension for up to five years and provides
that the suspension automatically ends when the suspended operation
commences.
BSEE understands the requirement in OCSLA to supervise operations
in a manner that assures due diligence in the exploration and
development of each lease. Therefore, BSEE is contemplating the option
of limiting the period for when the suspension would remain in effect;
only during the period between one drilling season and the next when
the operator is prevented from continuing its drilling or other
leaseholding activities due to seasonal conditions. This option would
still provide operators more time to effectively explore their leases
without fear of an expiring lease. It could also provide BSEE with a
better means of tracking an operator's diligence efforts. This option,
however, could result in additional unnecessary burdens, since an
operator would have to ``reapply'' for a new suspension if the operator
is unable to return to the location during the next open-water season.
BSEE is seeking comment on this regulatory option for the SOO or any
other option that could avoid or minimize additional burden, but still
assure diligent lease exploration and development.
BSEE's proposed regulatory change would address concerns raised in
the NPC reports, which suggested that the current approach toward
administration of the 10-year primary lease term allowed under OCSLA
``comes from other offshore areas in the U.S., where operators have
access to the leases all year-round.'' (NPC 2015 Report at 31 and NPC
2019 Report at 25). The NPC 2019 Report pointed out that a ``10-year
lease in the U.S. Arctic equates to about 3 to 4 years of working time,
compared with the equivalent 10 years working time in the Gulf of
Mexico.'' (NPC 2019 Report at 25). While it is not possible for BOEM to
award leases with more than the maximum ten-year primary lease term
allowed under OCSLA, this proposed regulatory change would rely on the
Secretary's statutorily delegated authority, which has, in turn, been
delegated to BSEE, to administer suspensions to address, as
appropriate, the effects of Arctic working conditions when they may
limit the operator's ability to perform leaseholding activities.
Documents Incorporated by Reference. (Sec. 250.198)
BSEE proposes to revise the existing relief rig and SSRW
requirements in Sec. 250.472 by providing the operator with an option
to either use an SSID or have access to a relief rig if the operator
will conduct exploratory drilling operations from a MODU. As part of
that proposed regulatory change, which is discussed in detail later
below in the What are the relief rig or additional well control
equipment or relief rig requirements for the Arctic OCS? (Sec.
250.472) section-by-section discussion, BSEE proposes to require the
SSID to include Remotely Operated Vehicle (ROV) intervention equipment
that has the capabilities to function the SSID. Under proposed Sec.
250.472(a)(3)(ii), BSEE would require the ROV to have panels that are
compliant with API RP 17H, Remotely Operated Tools and Interfaces on
Subsea Production Systems, Second Edition, June 2013; Errata, January
2014, to ensure that the operator's ROV capabilities for the SSID
follow BSEE's existing ROV panel requirements for BOP systems. In
conjunction with proposed paragraph (a)(3)(ii) that would require the
operator's ROV panels to be compliant with API RP 17H, BSEE proposes to
add the citation for proposed Sec. 250.472(a)(3) to Sec.
250.198(e)(73). Paragraph (e)(73) of Sec. 250.198 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)(73) would clarify that API RP 17H is
a regulatory requirement when complying with Sec. 250.472 and is
subject to BSEE
[[Page 79283]]
oversight and enforcement in the same manner as other regulatory
requirements.
API Recommended Practice 17H--Remotely Operated Tools and Interfaces on
Subsea Production Systems
This recommended practice provides general recommendations and
overall guidance for the design and operation of remotely operated
tools (ROT) and remotely operated vehicle (ROV) tooling used on
offshore subsea systems. ROT and ROV performance is critical to
ensuring safe and reliable subsea operations and this document provides
general performance guidelines for this and associated equipment. This
second edition also includes provisions on high flow Type D hot stabs.
The American Petroleum Institute (API) provides free online public
access to view read only copies of its key industry standards,
including a broad range of technical standards. All API standards that
are safety-related and that are incorporated into Federal regulations
are available to the public for free viewing online in the
Incorporation by Reference Reading Room on API's website at: http://publications.api.org \[1]\. In addition to the free online availability
of these standards for viewing on API's website, hardcopies and
printable versions are available for purchase from API. The API website
address to purchase standards is: https://www.api.org/products-and-services/standards/purchase.
\[1]\ To view these standards online, go to the API publications
website at: http://publications.api.org. You must then log-in or create
a new account, accept API's ``Terms and Conditions,'' click on the
``Browse Documents'' button, and then select the applicable category
(e.g., ``Exploration and Production'') for the standard(s) you wish to
review.
For the convenience of the viewing public who may not wish to
purchase or view the incorporated documents online, the documents may
be inspected at BSEE's offices at: 3801 Centerpoint Dr, Anchorage,
Alaska, 99503 (phone: 907-334-5300); 1919 Smith Street, Suite 14042,
Houston, Texas 77002 (phone: 1-844-259-4779); or 45600 Woodland Road,
Sterling, Virginia 20166 (email: [email protected]), by appointment only.
BSEE will make documents incorporated in the rule available for viewing
at the time and date agreed upon for the appointment. Additional
information on where these documents can be inspected or purchased can
be found at 30 CFR 250.198, Documents incorporated by reference, or by
sending a request by email to [email protected].
Subpart C--Pollution Prevention and Control
Pollution prevention. (Sec. 250.300)
BSEE proposes to revise paragraphs (b)(1) and (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 (2) that operators
capture all petroleum-based mud and associated cuttings while operating
on the Arctic OCS.
Existing Sec. 250.300(b)(1) and (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 (2) of this
section in light of EPA's authority to address water-based muds and
cuttings discharges. The Clean Water Act (CWA) (Section 301(a), 33
U.S.C. 1311(a)) provides EPA with the authority to issue National
Pollutant Discharge Elimination System (NPDES) general permits, which
authorize certain discharges, including certain restricted discharges
of water-based muds and cuttings, from oil and gas exploratory
facilities on the OCS in the Beaufort Sea and the Chukchi Sea. Those
general permits additionally prohibit the discharge of oil-based and
non-aqueous based muds and cuttings. The EPA must issue an NPDES
general permit before an operator may seek coverage under that general
permit. Compliance with the CWA, including gaining coverage under an
applicable NPDES general permit, is necessary before an operator may
discharge pollutants from its exploratory drilling operations.
Before issuing an NPDES permit, EPA must make specific
determinations to ensure that issuance of a permit will not lead to
unreasonable degradation of the marine environment. EPA's determination
is guided by an Ocean Discharge Criteria Evaluation (ODCE). The ODCE
requires the agency to consider multiple environmental factors, such as
potential impacts on human health through direct and indirect pathways,
and the importance of the receiving water area to the surrounding
biological community. These factors take into consideration how
discharges could impact subsistence activities, marine resources, and
coastal areas. The most relevant NPDES permits issued for offshore oil
and gas exploration activities conducted from a MODU on the Arctic OCS
are two 2012 general permits that covered oil and gas exploration
facilities conducting operations in Federal waters of the Beaufort Sea
and the Chukchi Sea. The Beaufort Sea permit \41\ does not allow the
discharge of water-based muds and cuttings during the fall bowhead
whale hunt. However, the Chukchi Sea permit \42\ did not include a
similar restriction. According to the ODCE for the Chukchi Sea permit,
the restriction was not necessary because the migration of bowhead
whales would be over before discharge-related activities would
begin.\43\
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\41\ https://www.epa.gov/sites/production/files/2017-12/documents/r10-npdes-beaufort-oil-gas-gp-akg282100-final-permit-2012.pdf.
\42\ https://www.epa.gov/sites/production/files/2017-12/documents/r10-npdes-chukchi-oil-gas-gp-akg288100-final-permit-2012.pdf.
\43\ https://www.epa.gov/sites/production/files/2017-12/documents/r10-npdes-chukchi-oil-gas-gp-akg288100-odce-2012.pdf, pp.
6-14 to 6-17.
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Under this proposed rule, BSEE would preserve the requirements in
Sec. 250.300(b)(1) and (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
[[Page 79284]]
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 (2)
are not necessary. In particular, the EPA already addresses the goals
of protecting water quality through the NPDES program, protecting
marine species and their habitats, as well as the effectiveness of
subsistence hunting activities, through the exercise of that agency's
authorities. Thus, BSEE does not expect the Regional Supervisor to need
to exercise the discretionary authority under existing Sec.
250.300(b)(1) and (2) in the foreseeable future.
Furthermore, BSEE understands, and did so even while it was
preparing the 2016 Arctic Exploratory Drilling rule, that the
references to the BSEE Regional Supervisor's authority in existing
paragraphs (b)(1) and (2) created some uncertainty for the regulated
industry because it appeared to overlap with EPA's jurisdiction and, if
implemented, might result in BSEE issuing duplicative or conflicting
requirements. BSEE addressed this concern by explaining that the
amendments were meant to clarify the Regional Supervisor's authority to
impose operational measures that complement EPA's discharge limitations
by considering potential impacts to specific components of the Arctic
environment, such as subsistence activities, marine resources, and
coastal areas (81 FR 46505). Given the policy in E.O. 13783 to review
existing regulations that potentially burden the development or use of
domestically produced energy resources and the general principles in
Section 1 of E.O. 13563--Improving Regulation and Regulatory Review (76
FR 3821)--to promote predictability and reduce uncertainty, BSEE
believes it is appropriate to propose eliminating the water-based mud,
and associated cuttings, provisions in Sec. 250.300(b)(1) and (2).
This proposed regulatory change does not suggest any change in
BSEE's recognition that it is responsible for ensuring that oil and gas
exploration and production activities on the OCS are conducted in a
safe and 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 capture of water-based
muds and cuttings on a case-by-case basis, if the EPA has not done so.
In particular, the District Manager would consider and determine
whether such a requirement would be appropriate for any facility. The
District Manager would make this determination on a case-by-case basis,
in conjunction with the EP and APD approval process. This process
includes coordinating with BOEM, particularly at the EP stage, when
BOEM conducts an environmental review to identify the direct, indirect,
and cumulative environmental effects that may be expected as a result
of implementing the EP. That environmental review also incorporates
input about potential environmental effects that may be obtained
through consultations and review by interested parties, Federal
agencies (e.g., EPA), State or local agencies, Tribes, or the public.
Nothing would change BSEE's position from the 2016 rule to communicate
with other agencies responsible for oversight of discharges related to
oil and gas exploration drilling in the Arctic. This communication will
help ensure that conflicts do not arise (81 FR 46504). BSEE expects
that such input from EPA would address whether that agency has issued
or plans to issue a permit for the same exploratory drilling
facilities, and whether that agency believes that capture of water-
based muds in a specific case is warranted. Through BSEE's longstanding
authority under 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 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 (b)(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 operators 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.
In cases where an operator obtains SCCE capabilities through
contracting, paragraph (f)(3) currently requires the operator to
provide proof of contracts or membership agreements with cooperatives,
service providers, or other contractors. This includes information
demonstrating the availability of the personnel and/or equipment on a
24-hour per day basis during operations below the surface casing. BSEE
proposes to revise paragraph (f)(3) by replacing the ``below the
surface casing'' language in this paragraph with the phrase ``below the
surface casing, or before the last casing point prior to penetrating a
zone capable of flowing hydrocarbons in measurable quantities, as
approved by the Regional Supervisor.'' This change would make the
requirement in paragraph (f)(3) consistent with the changes BSEE is
proposing to Sec. 250.471, which houses the substance of the Arctic
OCS SCCE requirements. This proposed change is discussed in further
detail in connection with that provision.
Finally, BSEE proposes to add a new paragraph (h) to complement the
proposed revisions to 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
[[Page 79285]]
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 paragraphs (a)(1) through (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. Paragraph (a)(1) specifically requires the capping
stack to be positioned to ensure that it will be able to arrive at the
well location within 24 hours after a loss of well control. Paragraphs
(a)(2) and (3) require the cap and flow system and the containment dome
to be positioned to ensure that they will be able to arrive at the well
location within 7 days after a loss of well control.
BSEE proposes to revise Sec. 250.471 by:
(i) Adding a new provision at the end of paragraph (a) stating that
``However, the Regional Supervisor will approve delaying access to your
SCCE until your operations have reached the last casing point prior to
penetrating a zone capable of flowing hydrocarbons in measurable
quantities provided that you submit adequate documentation (such as,
but not limited to, risk modeling data, off-set well data, analog data,
seismic data), with your APD, demonstrating that you will not encounter
any abnormally high-pressured zones or other geologic hazards. The
Regional Supervisor will base the determination on any documentation
you provide as well as any other available data and information.''
(ii) modifying the language in paragraph (a) describing the
performance standard that the SCCE must meet by replacing ``capable of
stopping or capturing the flow of an 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 (3), which apply to the cap and
flow system and containment dome, respectively.
The changes described in item (i) from the previous paragraph could
allow the operator to adjust the point in time during operations when
it must position its capping stack--from ``when drilling or working
below the surface casing'' to ``when drilling or working below the last
casing point prior to the zone capable of flowing hydrocarbons in
measurable quantities''--if the operator is able to demonstrate that it
will not encounter any abnormally 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 paragraph (a)(1) and proposed paragraphs (a)(2) and (3),
when drilling or working below the surface casing. While BSEE does not
propose changes to the capping stack provision in paragraph (a)(1),
changes to paragraph (a) would have a practical effect on the existing
capping stack requirements. Changes to the capping stack requirements
are discussed in the next subsection, entitled, Revisions to the
Capping Stack Requirements.
BSEE's proposed modifications to the language in paragraph (a),
describing the performance standard that the operator's SCCE must meet,
is administrative in nature. BSEE proposes this change so that the
language is consistent with the source ``control'' and ``containment''
description of this equipment, as well as the title of this section of
the regulations (i.e., 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 to remove the phrase ``positioned to ensure
that it will arrive at the well location within 7 days after a loss of
well control'' from paragraphs (a)(2) and (3) would still require the
operator to ensure it has access to a cap and flow system or a
containment dome. However, the operator would no longer be required to
ensure the equipment is positioned to be able to arrive at the well
location within 7 days after the loss of well control. The distinction
between the positioning requirement and the requirement to have access
to the equipment is that ``having access'' refers to ensuring the
operator has identified the equipment that would meet the performance
requirements in this section and in other existing BSEE regulations--
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. Details regarding BSEE's proposed
revisions to Sec. 250.471(a)(2) and (3) are discussed in the
subsection below, entitled, Revisions to the Cap and Flow System, and
Containment Dome Requirements.
Revisions to the Capping Stack Requirements
BSEE's proposed revisions to paragraph (a) would provide an
opportunity to the operator to adjust the point in time during
operations when it must position its capping stack, so that it will be
available to arrive at the well location within 24 hours after a loss
of well control. If the operator is able to demonstrate to BSEE that
the operations it plans to conduct below the surface casing would not
encounter any abnormally high-pressured zones or other geologic hazards
before reaching the last casing point prior to penetrating a zone
capable of flowing hydrocarbons in measurable quantities, then BSEE
would allow the operator delay its positioning of the capping stack
until that point. A capping stack, as defined under the existing
regulations at Sec. 250.105, is a mechanical device that can be
installed on top of a subsea or surface well head or BOP to stop the
uncontrolled flow of fluids into the environment. BSEE also proposes
certain non-substantive language changes for clarity.
The existing capping stack requirements in paragraphs (a) and
(a)(1) are intended to ensure that a capping stack is readily available
to stop or capture the flow of hydrocarbons in case of a loss of well
control when drilling below or working below the surface casing. While
BSEE does not propose to eliminate the requirement in paragraph (a)(1)
to ensure that the capping stack will be able to arrive at the well
location within 24 hours after a loss of well control, the existing
requirement in paragraph (a) to ensure the equipment is accessible when
drilling below the surface casing does not fully take into
consideration the known geology of an area. The formations below the
surface casing, based on the known geology of the area, may have
minimal or no potential to flow hydrocarbons in measurable quantities
during drilling operations. This obviates the need for ensuring capping
stack availability during operations in those zones. Prior to
submitting an APD, operators assess the formations they will
potentially encounter during drilling operations,
[[Page 79286]]
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 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--that the operator can
demonstrate to BSEE that it will not encounter ``abnormally high-
pressured zones or other geologic hazards''--to determine whether to
grant an exception accounts for those downhole risks that could lead to
a blowout and may require the use of a capping stack. With respect to
abnormally high-pressured zones, BSEE is concerned that there could be
a case where a kick (an influx, or flow, of formation fluid from the
high-pressured zone entering into the wellbore) is not controlled and
could lead to a blowout. While there are means of mitigating the risk
of a kick, (i.e., overbalanced drilling), the capping stack needs to be
readily available if heavier weight drilling muds, the BOP, and SSID,
if applicable, fail to control the well.
There could be other geologic hazards, such as fractured or high
permeability zones, that may also pose a risk, particularly if those
zones contain hydrocarbons. It is possible that normally pressured
zones may be highly permeable or contain fractures, in which lost
circulation may occur. This could cause a dynamic effect where drilling
mud flows into the permeable formation causing the circulating pressure
to decrease below the zone's pore pressure resulting in formation
fluids flowing into the well bore. This may lead to a loss of well
control. The capping stack needs to be readily available if heavier
weight drilling muds, the BOP, and SSID, if applicable, fail to control
the well.
However, if the operator is able to demonstrate that a highly
permeable or fractured zone is predicted to only contain water, BSEE
would consider allowing the operator to delay positioning of the
capping stack. Under this scenario, the operator would be able to use
the diverter system in conjunction with the BOP system to maintain
safety and environmental protection because it would be unlikely for
hydrocarbons to be released into the environment. The diverter system
consists of a mechanical device similar to a BOP annular preventer. The
diverter system is used to divert gases, fluids, and other materials
flowing from the well, away from facilities and personnel. Also, an
operator would pump fluid loss materials into the well to bridge the
formation to reduce its permeability and allow drilling muds to isolate
the formation from the well. To permanently address the incident, the
operator could also install a liner or set a new casing point at the
interval where that highly permeable or fractured zone is located. BSEE
would like to know whether there are more appropriate 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 OCS in the Arctic. BSEE is
requesting comment on what other types of information could be used to
demonstrate the absence of abnormally pressured zones or other geologic
hazards, and how burden on the operator could change--increase or
decrease--if BSEE were to require its submission.
At the APD stage, BSEE would evaluate the operator's documentation
along with other accompanying geologic and engineering information/
analyses that must be submitted as part of its APD. BSEE would also
consider any other available G&G information, such as information
gathered from prior drilling operations in the area (e.g., well log and
pressure testing information), and any other applicable geophysical
(e.g., seismic data) information. BSEE makes clear in its proposed
regulatory language that the Regional Supervisor will base the
determination on whether to allow the operator to delay positioning of
the capping stack on the documentation that the operator submits, as
well as any other available data and information.
BSEE is also considering an alternative regulatory approach whereby
the Bureau would instead revise existing paragraph (a) by replacing
``surface casing'' with ``last casing point prior to penetrating a zone
capable of flowing hydrocarbons in measurable quantities.'' This
regulatory option would uniformly adjust the point in time during
operations when the operator must have access to its capping stack, by
requiring the operator to have
[[Page 79287]]
its capping stack positioned before drilling below or working below the
last casing point prior to penetrating a zone capable of flowing
hydrocarbons in measurable quantities.
Under this regulatory option, BSEE would evaluate the geologic and
engineering information/analysis that the operator must submit as part
of its APD, while also taking into consideration any other available
G&G information the Bureau may have (e.g., off-set well data, such as
well logs and pressure testing information, or geophysical information,
such as seismic data). Based on these different sources of information,
BSEE would determine whether there may be a need for the operator to
position the capping stack at a point in time during operations earlier
than last casing point prior to penetrating a zone capable of flowing
hydrocarbons in measurable quantities.
There may be cases where the operator or BSEE may not have
sufficient G&G or analogous well data during the permit review process
on a proposed project to provide an adequate level of certainty
regarding anticipated formations that may be encountered prior to
reaching the targeted productive formation. Therefore, BSEE is also
considering, as part of this regulatory option, a clarification that
the Regional Supervisor may require the operator to have access to a
capping stack in advance of drilling below or working below the last
casing point prior to penetrating a zone capable of flowing
hydrocarbons in measurable quantities if BSEE determines there is
insufficient G&G or analogous well data.
For example, there may be insufficient G&G or analogous well data
in cases where there have been a limited number of wells drilled within
proximity to the planned well. In most cases, G&G and analogous well
data are gathered from multiple sources. However, the same sets and
amounts of data and information may not be available for each area,
well, or project. There is no single set of criteria for determining
the sufficiency of G&G or analogous well data. The more data that are
available from sources near to the proposed drilling location, the
greater confidence BSEE will have in the G&G interpretations. BSEE
wants to ensure the operator has the most accurate data to make
determinations about where the zones capable of flowing hydrocarbons in
measurable quantities are located.
This alternative regulatory option would maintain the same level of
safety and environmental protection in comparison to BSEE's proposed
regulatory change. The decision on whether it is appropriate to delay
positioning of the capping stack at a point in time when operations are
taking place below the surface casing resides with BSEE. BSEE,
ultimately, may decide not to allow the operator to delay positioning
of the capping stack if the Bureau reasonably assesses that potential
risks below the surface casing exist that may require immediate
deployment of this device. However, the distinction under this
regulatory option is that the operator would not need to specifically
demonstrate that abnormally high-pressured zones or other geologic
hazards would be encountered above last casing point prior to
penetrating a zone capable of flowing hydrocarbons in measurable
quantities. The presumption would be that all zones above the last
casing point prior to penetrating a zone capable of flowing
hydrocarbons are safe unless BSEE determines otherwise. In addition,
under BSEE's proposed regulatory change, it would be clear that the
Bureau may request additional information from the operator and would
provide that BSEE may consider other available data and information.
BSEE is specifically soliciting comments about the benefits or
disadvantages of this regulatory option. BSEE is also soliciting
comments about the need for the operator to verify on a case-by-case
basis those zones incapable of flowing hydrocarbons in measurable
quantities. Operators verify these zones by analyzing G&G data to
evaluate the formations that are expected to be encountered during
drilling operations and confirm that there are no hydrocarbons present.
Operators must use available offset well data in conjunction with the
G&G data. BSEE requests comment on other methods operators use to
verify the hydrocarbon zones, or abnormally high-pressured zones or
other geologic hazards (such as fractured or high permeability zones),
they anticipate encountering for a proposed drilling project and how
frequently the data would be lacking at the point of preparing
information to submit as part of an APD.
Revisions to the Cap and Flow System, and Containment Dome
Requirements
As described at the beginning of this section-by-section
discussion, Sec. 250.471, BSEE is also proposing to revise paragraphs
(a)(2) and (3) of existing Sec. 250.471, which refers to the timing of
the arrival of a cap and flow system and containment dome,
respectively, by removing the phrase ``positioned to ensure that it
will arrive at the well location within 7 days after a loss of well
control'' from each paragraph. This proposed change would remove the
requirement to have a cap and flow system or a containment dome
positioned to ensure the equipment will be available to arrive at the
well location within 7 days after the loss of well control, while
preserving the existing requirement to deploy those pieces of equipment
as directed by BSEE.
BSEE proposes to allow the operator to adjust the point in time
during operations when it must position its capping stack under
paragraph (a), from ``when drilling or working below the surface
casing'' to ``when drilling below or working below last casing point
prior to penetrating a zone capable of flowing hydrocarbons in
measurable quantities'' if the operator is able to demonstrate that it
will not encounter any abnormally high-pressured zones or other
geologic hazards before that casing point. Only the 7-day arrival
timing related to the ``flow'' part of the cap and flow system would be
altered as a result of BSEE's proposed modification to paragraph (a)(2)
of Sec. 250.471.\44\
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\44\ Existing Sec. 250.105 defines Cap and flow system and
Capping stack.
---------------------------------------------------------------------------
The changes proposed in paragraphs (a)(2) and (3) to remove the
requirement for the cap and flow system and the containment dome to
arrive at the well location within 7 days after a loss of well control
would not change other existing requirements throughout 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.
BSEE proposes to remove the cap and flow system and containment
dome 7-day arrival timing requirements based on the Bratslavsky and
SolstenXP study. The Bratslavsky and SolstenXP study determined that
the time periods when SCCE may be safely deployed throughout the Arctic
OCS is limited based on typical Arctic conditions. In
[[Page 79288]]
the Chukchi Sea, this means that safe SCCE deployment could only occur
between August and October in the historically active exploration area.
Moving north from the historically active exploration area of the
Chukchi Sea, the ability to safely deploy SCCE diminishes significantly
(id. at 100). The study mentions there are more opportunities for safe
deployment of SCCE in other portions of the Chukchi Sea (June through
December). However, it is only in the southwestern extent of the
Chukchi Sea Planning Area; outside of the historically active
exploration area.
In the Beaufort Sea, the study noted that sea ice concentrations
tend to be greater year-round as compared to the Chukchi Sea (id. at
75). Accordingly, safe SCCE deployment could occur from ice capable
vessels between early August and October in the historically active
exploration area of the Beaufort Sea (i.e., the southern portion of the
Beaufort Sea Planning Area). However, moving north beyond the
historically active exploration area, time windows for safe SCCE
deployment decrease significantly (id. at 104).
In the case of open water operations in both the Chukchi and
Beaufort Seas, the study points out that sea state is an important
limiting factor for safe SCCE deployment. Rough sea states--high waves
and longer wave periods--can affect the safety and operating limits of
SCCE deployment. The vessel carrying the SCCE can become very unstable
in rough sea states and the heave action on the deck can therefore
increase significantly beyond the vessel's tolerance levels for
conducting operations, which may negatively affect the ability to
safely deploy the SCCE. Rough sea states are most likely to occur when
there is less sea ice coverage and larger open water areas to generate
large waves, which is more of an issue in the Chukchi Sea, where there
are larger open water areas throughout the open water season (id. at
11).
When operating in open water conditions, sea states generally
dictate that safe SCCE deployment could occur only between late
September and October in the historically active exploration area of
the Chukchi Sea, and that window diminishes significantly moving north
of the historically active exploration area. In the Beaufort Sea, where
there is less open water throughout the operating season, sea states
would generally permit safe deployment of SCCE between 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). As recently as April of 2020,\45\
there were active leases in the Arctic OCS where SCCE may be deployed.
These leases were located in the Beaufort Sea in water depths less than
approximately 170 feet deep. This water depth range limits the fleet of
support vessels that can be used for the safe deployment of SCCE. A
possible solution that could enable SCCE deployment in the presence of
a gas boil is the use of offset[hyphen]deployment technology to
remotely position SCCE over the blowing well in shallow water (id. at
A-35).
---------------------------------------------------------------------------
\45\ In April of 2020, the only leases with potential projects
that would be subject to the Arctic OCS's SCCE requirements were
relinquished. However, there are other active leases in the Beaufort
Sea located nearer to the shore in shallow waters where exploration
and development projects are being pursued (primarily through man-
made gravel islands).
---------------------------------------------------------------------------
When BSEE proposed its original Arctic OCS SCCE requirements in
2015, the Bureau explained that there is limited ability in the Arctic
region to summon additional source control and containment resources.
Accordingly, the Bureau required operators to plan for response
redundancies and planning complexities not required elsewhere (80 FR
9938). BSEE determined that the provisions finalized in 2016 provided
for the necessary redundancy and sequencing of the responses, based on
the time necessary to deploy, and therefore provided sufficient safety
and environmental protection to allow for exploratory drilling on the
Arctic OCS. At that time, BSEE believed that the technologies
identified in its SCCE requirements represented the optimal approach to
well control capabilities available for the Arctic OCS (81 FR 46520).
Since publication of the 2016 rule, however, BSEE has sought to
better understand the ability to safely deploy SCCE (and relief rigs)
in Arctic OCS conditions, through a study it commissioned to
Bratslavsky Consulting Engineers, Inc., and SolstenXP, Inc. According
to the Bratslavsky and SolstenXP study, the time periods when SCCE may
be safely deployed throughout the Arctic OCS is limited in comparison
to relief-well drilling operations, based on typical Arctic conditions.
BSEE did not have the benefit of having the Bratslavsky and SolstenXP
study when finalizing the 2016 Arctic Exploratory Drilling Rule. BSEE's
proposed changes to Sec. 250.471(a)(2) and (3) for the containment
dome and cap and flow system responds to the information it has
gathered from the study.
In light of these findings, BSEE proposes the revisions under Sec.
250.471 to the containment dome and cap and flow system deployment
requirements in paragraphs (a)(2) and (3) because it is not reasonable
to impose such universal, prescriptive requirements for equipment that
may not be safely deployed (moved to the location, equipment put into
place, and activated) and effectively used under certain Arctic OCS
conditions. The deployment and arrival schedules of the cap and flow
system and the containment dome will be directed by the BSEE Regional
Supervisor on a case-by-case basis.
However, as previously described, BSEE proposes only to adjust,
rather than eliminate, the reference to the point in time during
operations when the operator must have access to a capping stack that
is positioned to be able to arrive at the well location within 24 hours
after a loss of well control. The Bratslavsky and SolstenXP study shows
that the time periods when SCCE (capping stack, containment dome, and
cap and flow system) may safely be deployed and effectively used are
limited. Metocean conditions (i.e., rough sea states and sea ice
concentrations) prevalent in the Arctic OCS can exceed the operating
limits of the vessels that transport and deploy the SCCE. In addition,
SCCE deployment is likely impaired in water depths shallower that 984
feet, where gas boils could form above a blowing well. Water depths in
the majority of the Chukchi Sea and Beaufort Sea where exploration has
historically occurred are relatively shallow--167 feet or less.
However, BSEE's independent observation outside of the study is that
the chances for successfully deploying a capping stack under Arctic OCS
conditions is greater in comparison to the containment dome
[[Page 79289]]
and cap and flow system. More specifically, in comparison to the
containment dome, the capping stack has proven to be a more effective
technology when successfully deployed and has a different function
compared to a containment dome. The capping stack latches on to a
connector or pipe stub located on or in the well to achieve a pressure
tight seal to capture or stop all fluids flowing out of the well. A
containment dome, which removes oil and gas from the water column, will
likely capture only a portion of the hydrocarbon flow due to the non-
sealing design. In addition, the use of a containment dome may be
constrained by the drilling unit itself. Certain drilling rigs, such as
jackups and submersible drilling vessels, are unlikely to provide
adequate structural clearance for deployment of a containment dome
without moving the rig off the drill site. (id. at 33). Furthermore,
containment domes have limited field application to prove their
capabilities while, in contrast, capping stacks have been field tested
and successfully deployed in multiple practice drills (id. at 32 and
34).\46\
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\46\ For example, the capping stack technology was used to shut-
in the Macondo well during the Deepwater Horizon incident.
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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 (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 regulations' requirement for redundant protective
measures, while acknowledging the capability of each SCCE component, as
there is no guarantee that a single measure could control or contain a
WCD.
Finally, BSEE proposes to revise existing paragraph (b) by
eliminating the requirement for the operator to conduct a stump test of
a pre-positioned capping stack, if the operator elects to use one,
prior to installation on each well. This proposed change would provide
consistency with BSEE's proposed revision to the definition of a
capping stack in 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, which states, ``However, the Regional
Supervisor will approve delaying access to your relief rig until your
operations have reached the last casing point prior to penetrating a
zone capable of flowing hydrocarbons in measurable quantities provided
that you submit adequate documentation (such as, but not limited to,
risk modeling data, off-set well data, analog data, seismic data), with
your APD, demonstrating that you will not encounter any abnormally
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.''; and
(v) Eliminating the reference to expected seasonal ice encroachment
at the drill site, which applies to relief rig operations.
With respect to the structure of Sec. 250.472, proposed paragraph
(a) would establish the requirements the operator must follow if the
operator elects to use an SSID, and proposed paragraph (b) would
establish the requirements the operator must follow if the operator
elects to maintain access to a relief rig. BSEE would combine the
[[Page 79290]]
requirements in existing paragraphs (a) and (b) into a single
paragraph--proposed paragraph (b)--for organizational purposes, since
existing paragraphs (a) and (b) cover relief rigs. Proposed paragraph
(b) would also include the relief rig-related revision described in
item (iv) of the previous paragraph, which could allow the operator to
adjust the point in time during operations when it must stage its
relief rig--from ``when drilling or working below the surface casing''
to ``when drilling or working below the last casing point prior to the
zone capable of flowing hydrocarbons in measurable quantities''--if the
operator is able to demonstrate that it will not encounter any
abnormally high-pressured zones or other geological hazards before that
casing point. However, unless otherwise approved by BSEE, the operator
must stage its relief rig in a location, such that the relief rig would
be available to arrive on site, drill a relief well, kill and abandon
the original well, and abandon the relief well no later than 45 days
after the loss of well control, when drilling or working below the
surface casing. Finally, proposed paragraph (b) would include the
proposed relief rig-related revision to eliminate the reference to
expected seasonal ice encroachment at the drill site, which could
potentially extend the open-water drilling season for MODUs. The
changes included in proposed paragraphs (a) and (b) are discussed in
further detail below, respectively, under the two subheadings entitled,
Proposed Paragraph (a)--Complying with 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 it promulgated the 2016 Arctic Exploratory Drilling Rule, BSEE
understood that, based on past loss of well control events (including
the Deepwater Horizon incident), it was important for the operator to
be prepared to drill a relief well to permanently plug a well, in the
event of a loss of well control. Arctic OCS 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 proposed rule: Oil
and Gas and Sulphur Operations on the OCS--Requirements for Exploratory
Drilling on the Arctic OCS (February 24, 2015, 80 FR 9916) that, for
Arctic OCS Conditions, it was necessary to establish a relief rig and
SSRW requirements, whereby the rig would be positioned at a location
that would enable it to transit to the well site, drill a relief well,
kill and permanently plug the out-of-control well, plug the relief
well, and demobilize from the site, prior to expected seasonal ice
encroachment. (see 80 FR 9940).
Prior to finalizing the 2016 Arctic Exploratory Drilling Rule, BSEE
did not identify any alternative technologies that provided a
comparable level of results to drilling a relief well and permanently
killing an out-of-control well. Drilling a relief well prior to
seasonal ice encroachment eliminates the risk of a prolonged
uncontrolled flow of hydrocarbons under the ice, throughout the winter
season. The SCCE intervention options in BSEE's existing regulations
(capping stack, cap and flow system, and containment dome) are intended
only to temporarily control a well and not to be left in place over an
entire ice season. However, BSEE did provide an option through the 2016
rule for the operator to request that BSEE approve ``alternative
compliance measures to the relief rig requirement,'' as provided in the
longstanding regulation at 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 new 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:
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 recent experiences with Arctic
exploration and advancements in technology, and it provided findings
and recommendations directed toward enhancing the Nation's regulatory
environment to improve reliability, safety, efficiency, and
environmental stewardship for Arctic oil and gas development. One of
the key areas the Secretary of Energy requested that the NPC address
was regulatory burdens related to development on the Arctic OCS. (NPC
2019 Report at A-1)
The NPC 2015 Report described various technologies employed by
industry as preventative measures, to reduce the risk of a well control
incident or to mitigate the impacts of an incident through response and
recovery measures. It recommended further examination of source control
and containment technologies, including capping stacks and SSIDs,
noting that such alternatives ``. . . could prevent or significantly
reduce the amount of spilled oil compared to a relief well, which could
take a month or more to be effective.'' (NPC 2015 Report at 4-16).
In July/August of 2007, BSEE's predecessor, MMS, published a paper
entitled, ``Absence of fatalities in blowouts encouraging in MMS study
of OCS incidents 1992-2006.'' You may download and view the paper at
http://drillingcontractor.org/dcpi/dc-julyaug07/DC_July07_MMSBlowouts.pdf. The paper summarizes BSEE's assessment of
statistical information about loss of well control events that occurred
during drilling operations on the OCS from 1992 through 2006. The paper
noted that although relief wells were initiated in 2 of the 39 blowouts
that occurred during the study period, both wells were controlled by
other means prior to completion of the relief well. According to the
NPC 2015 report, ``[a] relief well under good weather conditions may
take 30 to 90 days plus rig mobilization, whereas a capping stack could
be installed significantly sooner, and a subsea shut-in device could be
activated in minutes.'' (NPC 2015 Report at 8-17)
The NPC 2019 Report noted that, when ExxonMobil drilled an
exploratory well in the Russian waters of the Kara Sea, it used an SSID
that was built and tested in Norway. According to the NPC 2019 Report,
the SSID used in the Kara Sea used existing capping stack technology,
including dual blind shear rams; an upgraded, redundant control system;
and side inlets for intervention below the shear rams. (id. at C-10).
At the same time, the NPC 2019 Report described the SSID as
[[Page 79291]]
similar to a second BOP that was designed to be left on the wellhead,
instead of being removed with the drilling rig, if the rig moves off
the well near the end of the drilling season. The SSID, which could be
actuated remotely, and the casing design together were capable of safe
full well shut-in, diminishing the risk related to a loss of well
control event occurring in late season and continuing over the winter
season. The NPC 2019 Report observed that this design approach could
eliminate the need for an SSRW. (id. at C-28). Ultimately, the NPC
recommended that the use of an SSID, in conjunction with capping
stacks, be accepted in place of the existing requirement for SSRW
capability. (id. at 2).
The NPC 2019 Report also included additional data regarding the
geologic characteristics of the formations targeted during exploratory
drilling operations in the Chukchi Sea and Beaufort Sea. The NPC 2019
Report provides an illustrative comparison of the geologic depths
encountered in the Arctic OCS and the Gulf of Mexico OCS. (NPC 2019
Report at 11). The shallower targeted geologic formations in the Arctic
OCS make drilling less complex and lower risk. This is different from
current water depths encountered by operators in the Gulf of Mexico. In
the Arctic OCS, exploratory drilling operations conducted from MODUs
have taken place in waters less than 200 feet. In the Gulf Mexico,
drilling activities are continually taking place in waters deeper than
9,000 feet.
The Arctic OCS's distinct challenges are driven by the region's
extreme environmental conditions, geographic remoteness, and a relative
lack of fixed infrastructure and existing operations. In comparison to
the Gulf of Mexico, the Arctic OCS lacks extensive operations and
infrastructure from which resources could be drawn to respond to a well
control incident. In addition, the open water season for drilling from
a MODU is limited, allowing operators to perform drilling operations
only during the summer and early fall. A late-season well-control event
could challenge an operator's ability to perform well intervention
operations prior to freeze up.
Suitability of Source Control and Containment Equipment
versus SSRW in the Alaska Outer Continental Shelf Region (Bratslavsky
and SolstenXP, 2018)
In addition to the NPC 2019 Report, BSEE received information about
SSIDs through the Bratslavsky and SolstenXP study, discussed in the
previous section in connection with the proposed changes to the current
Arctic OCS source control and containment requirements in Sec.
250.471. As previously mentioned, the Bratslavsky and SolstenXP study
entailed a comprehensive review and gap analysis of U.S. and
international regulations, standards, recommended practices (RP),
specifications, technical reports, and common industry methods
regarding the safe deployment of SCCE as compared to the effectiveness
of drilling an SSRW in Arctic conditions. BSEE notes that the
Bratslavsky and SolstenXP study refers to the SSID as a ``subsea
intervention device'' and considers the device to be SCCE, which is
used to mitigate the consequences of a well control event. However,
consistent with the findings in the NPC 2019 Report that categorizes
SSIDs as preventative measures (instead of a response and recovery
measure), BSEE considers SSIDs to be a barrier intended to prevent or
minimize the impacts of a well control event. (id. at 16).
The Bratslavsky and SolstenXP study noted that an SSID was
installed and field tested on a submersible drilling vessel (i.e., a
steel drilling caisson) for a 2005/2006 drilling project in the
Canadian Beaufort Sea. However, the system was not completed in time to
meet the approval process timelines and shipping deadlines required for
timely implementation of the unit. (Bratslavsky & SolstenXP at A-36).
According to the study, the use of a preinstalled SSID could provide a
faster and safer additional line of defense for a response to a blowout
than an SSRW or deployment of a capping stack or containment dome,
resulting in smaller discharges to the environment. The report also
mentions that the ability to remotely function the SSID ensures that it
can be used in instances where other types of SCCE cannot be deployed
due to site hazards that make it unsafe or inaccessible. These
instances may include: A blowout with pressurized fluids coming up
solely through the wellbore (forming a gas boil on the surface), a rig
catching fire or collapsing on top of the well, or an incident in an
area where response operations are limited, such as in shallow waters
(id. at 35). The report also stated that if the well is designed to
accommodate a full shut-in of the last casing string interval, the SSID
can temporarily cap and control a well and facilitate its plugging and
abandonment. This finding is consistent with the information from the
NPC 2019 Report discussed previously. In 2008, Chevron initiated a
technology venture with its partners on an R&D project to develop an
SSID that would advance the best BOP technologies available at the time
and would meet or exceed Canada's SSRW Arctic offshore regulations. The
SSID was known as the Alternative Well Kill System (AWKS), which had
two shear rams that were capable of simultaneously shearing and sealing
heavier wall, larger diameter tubulars, and casings than was possible
at that time. According to the NPC 2015 Report, Chevron successfully
completed its testing of the AWKS in 2014 and is ready for deployment.
(NPC 2015 Report at 4-18).
Although the Bratslavsky and SolstenXP study points out that SSIDs
could provide a faster and safer response to a blowout than capping
stacks or containment domes, BSEE does not conclude from this
observation that SSIDs should also replace the SCCE requirements in
existing and proposed Sec. 250.471. In the Arctic, it is critical for
the operator to have redundant protective measures in place, as there
is no guarantee that a single measure could control or contain a WCD.
(see 81 FR 46487). In addition to these redundant protective measures,
the SSID, well design, and BOPs serve as controls and barriers that
prevent or minimize the likelihood of loss of well control.
Other pertinent information from the Bratslavsky and SolstenXP
study includes the statistical analysis of recent OCS drilling seasons
in the Beaufort and Chukchi Seas. The analysis identified the metocean
and operational conditions that would support the safe drilling of a
relief well. The study noted that the hazards of sea ice to drilling
vessels and associated support vessels are primarily determined by the
concentration and thickness of the sea ice. A vessel's ice
classification, which are determined by various marine classification
societies, such as the American Bureau of Shipping (ABS) and Det Norske
Veritas and Germanischer Lloyd (DNV GL), indicates the vessel's
capabilities. As ice concentrations increase, a vessel's efficiency
decreases. (Bratslavsky & SolstenXP at 23).
The study notes that the currently available open water operating
season in the Chukchi Sea ranges from approximately 60 to 90 days in
the historically active exploration area. (id. at 143). However, the
results of the study showed that there is a high probability (90
percent) that drilling can be conducted safely in sea ice conditions in
a majority of the historically active exploration area of the Chukchi
Sea for 70 to 160 days if an ice class MODU and associated support
vessels are used as part of the drilling
[[Page 79292]]
operation. (id. at 108 and 145). Moreover, the NPC 2019 Report notes
that ``vessels and equipment that are positioned in the theater `just
in case' they are needed to minimize environmental impact, can actually
impede personnel safety and source control objectives, because they
distract operations personnel, add congestion, and can impede surface
access to the well location.'' (NPC 2019 Report at 19).
In the Beaufort Sea, the available open water operating season is
limited to approximately 50 to 60 days across the historically active
exploration area. (id. at 143). The study's analysis showed there is a
high probability (90 percent) that drilling can be conducted safely for
70 days, from mid[hyphen]August through October, in a majority of the
historically active exploration area of the Beaufort Sea. (id. at 146).
In light of the information from the NPC reports and the
Bratslavsky and SolstenXP study, and BSEE's consideration of that
information, BSEE proposes to revise Sec. 250.472 in the following
manner:
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.\47\ Through the 2016 rulemaking
comment process, stakeholders informed the Bureau that use of an SSID
could help significantly reduce the risk of a release of hydrocarbons
if the BOP system fails. At that time, BSEE focused more on permanent
remediation to resolve a WCD event in the Arctic. Nonetheless, the
Bureau agreed that an operator could request to use an SSID as an
alternate procedure or equipment to the relief rig (80 FR 9940).
Stopping short of requiring the use of an SSID, BSEE, instead, stated
in the 2016 rule that it would consider the use of an SSID as an
alternate procedure or equipment, under appropriate circumstances, if
proposed for use with a jack-up (when surface BOPs are used). At that
time, BSEE determined that, in the case where subsea BOPs are used in
conjunction with floating drilling units, SSIDs would only be
marginally effective or redundant (81 FR 46531). Since the 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.
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\47\ See, e.g., 80 FR 9940 (``[BSEE] requests comments on
alternative compliance approaches and specifically requests data on
the performance of SIDs, including operational issues (such as
timeframes needed to activate such alternatives). In particular,
BSEE requests comments on appropriate staging requirements for a
relief rig assuming that an SID has been installed at the
exploration well. Comments are also requested on the need for an
operator to have an in- season relief well drilling capability if an
SID is used at a location that is not subject to ice scouring.'')
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Consistent with the policy in E.O. 13783 to review existing
regulations that potentially burden the development or use of
domestically produced energy resources, BSEE re-considered the SSID
more closely, in light of the SSID information from the NPC reports and
the Bratzlavsky and SolstenXP study, to determine whether the device
could address the issues the Bureau identified when promulgating the
2016 rule.
Drilling a relief well is a complex, time-consuming process. After
setting up the drill rig and drilling begins, the process to intercept
the original wellbore may take several weeks or more because the
operator needs to drill deep enough at great precision to ensure
interception of the original well. This delay increases the length of
the time oil and other fluids within the original well could be flowing
uncontrollably into the marine environment. There is no delay for
operational use of an SSID compared to the process of using the relief
rig or capping stack.
In this proposed rule, BSEE developed its proposed SSID
requirements based on existing BOP equipment/technology whose
performance and reliability has been tested, proven in a manner that is
repeatable and reproducible, and has improved since promulgation of the
2016 rule. BSEE also proposes to require an SSID used in the Arctic OCS
to operate independently from the BOP. This would be accomplished by
requiring the SSID to have a redundant control system, independent from
the BOP control system, and independent, dedicated subsea accumulators
to operate the SSID. By having two independent, redundant components
(i.e., the BOP and the SSID) as part of the well control system, the
overall reliability and effectiveness of the entire system increases.
The following paragraphs describe BSEE's proposed requirements
associated with the SSID, 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 regulations
should provide options and flexibility to the operator (i.e., an SSID
or a relief rig) to fit its needs and plans to develop its Arctic OCS
leases. There could be cases where the operator's drilling schedule may
not align with the availability of an SSID. In such a case, the
operator should have the option to elect to proceed by complying with
the relief rig and SSRW requirements. If an operator does not complete
its exploratory drilling operations during that open water operating
season, the operator could come back during a subsequent open water
operating season and use an SSID, if one has become available in time.
There could also be cases where two or more operators may plan to
perform exploratory drilling operations during the same open water
season. In such a case, each operator's drilling rig could serve as the
other's relief rig. Under the existing regulations, BSEE would consider
this type of a scenario to be in compliance with the relief rig and
SSRW requirements. BSEE would not change that interpretation as part of
this rulemaking. In a scenario like this, none of the operators would
need to install an SSID, so long as there is an agreement among the
operators that their drilling rigs will serve as a relief rig, if
necessary. While it is not possible to identify every conceivable
scenario, BSEE recognizes there could be other scenarios that are
reasonably possible. Thus, it is appropriate to provide regulatory
flexibility in order to accommodate an operator's drilling program.
BSEE also retains its regulatory authority to approve alternate
procedures or equipment if the proposed procedures or equipment either
meet or exceed the level of safety and environmental protection
required.
The term SSID is a broadly used industry term, and there is not a
single, all-encompassing definition that establishes the scope and
function of an SSID. In some cases, different terms are used to
describe the device. For example, as stated earlier, the
[[Page 79293]]
Bratslavsky and SolstenXP study refers to the device as a ``subsea
intervention device,'' while some in the industry also refer to the
SSID as a ``mudline closure device.'' Irrespective of these synonymous
titles, BSEE uses the term SSID to refer to a fit-for-purpose device
that may be used for different types of situations, including for well
intervention applications, and can be used in different locations,
including outside of the Arctic. However, for the purposes of Arctic
OCS exploratory drilling from a MODU, BSEE is proposing to define the
minimum acceptable capabilities and functions of an SSID. BSEE notes
that, outside of the Arctic OCS, operators are contemplating using
SSIDs for future projects, and SSIDs have already been approved for use
in other parts of the OCS. The NPC 2019 Report notes that the
requirement to drill an SSRW to mitigate the risk of a late season well
control event continuing over the winter season is ``outdated.'' The
2019 report concludes that SSIDs and capping stacks are superior
solutions that could stop the flow of oil and allow intervention
through the original borehole before a relief well could be completed.
(NPC 2109 Report at 19). The SSID requirements BSEE is proposing to
establish in this proposed rule would not apply to projects outside of
the Arctic OCS. The design requirements for those SSIDs would be based
on the needs of a particular project and may or may not be similar to
what BSEE is proposing in this proposed rule. BSEE requests comments on
these SSID requirements as outlined in the proposed rule.
Under proposed paragraph (a) of 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,\48\ and determined that, on average, five loss of
well control events occurred each year on the OCS between 2007 and
2017.
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\48\ See, BSEE's website at https://www.bsee.gov/stats-facts/offshore-incident-statistics.
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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, 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:
(1) Close and seal the wellbore, independent of the BOP;
(2) Perform under the maximum environmental and operational
conditions anticipated to occur at the well;
(3) Be left on the wellhead in the event the drilling rig is moved
off location (e.g., due to storms, ice incursions, or emergency
situations);
(4) Preserve isolation through the winter season without relying on
the elastomer elements of the rams (e.g., by using a well cap) and
allow re-entry during the following open-water season; and
(5) In the event of a loss of well control, preserve isolation
until other methods of well intervention may be completed, including
the need to drill a relief well.
BSEE's analysis of loss of well control events data indicates that
the most common methods employed to regain control of a well include
pumping mud or cement into the uncontrolled well or activating
mechanical well control equipment (e.g., blowout preventer).
These SSID design requirements would help ensure the device is
capable of shutting in and containing all fluids within the wellbore
for an entire ice season (in the case of a loss of well control event
too late in the open-water season to provide enough time for the
operator to perform well kill or plug and abandonment operations). BSEE
is basing the proposed design requirement for the SSID to be capable of
preserving isolation through the winter season without relying on the
elastomer elements of the rams (e.g., by using a well cap) on
information it gained from the Kara Sea project. BSEE understands that
the SSID used in the Kara Sea project was capable of preserving
isolation over an entire ice season because it was designed to have a
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
[[Page 79294]]
not be achieved over the ice season if the shut-in relied solely on the
elastomer elements of the rams. The design requirements would also
ensure the SSID will allow for re-entry to perform well recovery
operations during the following open water season.
In a new paragraph (a)(2), BSEE proposes to require that the
operator's SSID include the following equipment:
(1) Dual shear rams, including ram locks; one ram must be a blind
shear ram;
(2) A redundant control system, independent from the BOP control
system, that includes ROV (remotely operated vehicle) capabilities and
a control station on the rig;
(3) Independent, dedicated subsea accumulators with the capacity to
function all components of the SSID; and,
(4) Two side inlets for intervention, one of which must be located
below the lowest ram on the SSID.
The dual shear ram requirement in proposed paragraph (a)(2)(i)
would ensure that the SSID is capable of shearing through drill pipe,
sealing the wellbore, and containing the fluids before they can escape
during a loss of well control event. BSEE notes that the NPC 2019
Report describes the SSID as having shearing/sealing rams. In fact,
when describing the SSID used in the Kara Sea Project, the report
explains that the device utilized dual blind shear rams. While proposed
paragraph (a)(2)(i) would require only one of the rams to be a blind
shear ram, BSEE is seeking comment on the advisability of requiring
dual blind shear rams on the SSID. As described in the bow-tie diagram
of the NPC 2019 Report, the SSID is the last line of prevention to
minimize the impacts of an event. (NPC 2019 Report at 14).
The redundant control system requirements in proposed paragraph
(a)(2)(ii) would ensure there is reliability in the system and that the
SSID will function when needed in an emergency situation. This proposed
requirement is intended to align with the existing requirement in
existing 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 American
Petroleum Institute (API) Specification (Spec.) 16D (e.g., yellow pod
and blue pod). More specifically, BSEE is further considering whether
there should be an additional manual method (separate from the
redundant control system) to close the SSID's rams with the ROV and
whether it may be appropriate to require a standby or tending vessel
with an ROV. These measures could address cases where the SSID's
control system on the drilling rig is not available (e.g., due to
failure or an evacuation of the rig).
The requirement in proposed paragraph (a)(2)(iii) for SSIDs to have
independent, dedicated subsea accumulators with capacity to function
all components of the SSID would help ensure that, if the BOP system
fails, the SSID will have the capabilities to function as needed,
independent of the BOP's accumulator system. The requirement in
proposed paragraph (a)(2)(iv) for SSIDs to have two side inlets, with
one of the inlets located below the lowest ram on the SSID, would allow
for re-entry through the SSID to perform well intervention operations.
Side inlets allow the operator to pump fluids into the well to kill the
well, before opening the blind shear ram to perform additional well
intervention operations.
In proposed paragraph (a)(3), BSEE would require the SSID to
include ROV intervention equipment and capabilities to function the
SSID. BSEE regulations currently include requirements for ROV
intervention capabilities in relation to a BOP's functionality. BSEE is
proposing similar requirements for the SSID because the SSID functions
similarly to a BOP. Under proposed paragraph (a)(3), the ROV equipment
and capabilities must:
(1) Be able to close each shear ram under the Maximum Anticipated
Surface Pressures (MASP), as defined for the operation;
(2) Include an ROV panel that is compliant with API RP 17H (as
incorporated by reference in Sec. 250.198);
(3) Meet the ROV requirements in existing Sec. 250.734(a)(5); and,
(4) Have the ability to function the SSID in any environment (e.g.,
when in a mudline cellar).
The requirement in proposed paragraph (a)(3)(i) for the ROV to be
able to close each shear ram under the operation's defined MASP would
ensure that the operator is able to remotely close (through the ROV)
each shear ram on the SSID and seal the well, which are the most
critical functions during a well control event. The requirement in
proposed paragraph 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)(73). Section 250.198(e)(73) documents the locations in the
regulations where API RP 17H is incorporated by reference as a
regulatory requirement, which would include Sec. 250.472(a)(3) under
this proposed rule. Adding the citation for Sec. 250.472(a)(3) to
Sec. 250.198(e)(73) 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
[[Page 79295]]
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 understands that ROVs are more reliable for this type of
application. However, BSEE requests that commenters provide any
information that demonstrates the reliability of acoustic (or other)
technologies to actuate an SSID from a remote location.
Furthermore, although BSEE is not proposing to require the SSID to
have a self-actuating function, the Bureau is contemplating whether one
may be necessary for certain emergency situations. BSEE is aware that
in the Arctic OCS, it is possible for a drilling vessel to sink and
allide with (i.e., strike against) the top of a wellhead during a loss
of well control event (Bratslavsky and SolstenXP at 17). As discussed
in the previous section, all exploratory drilling in the Beaufort Sea
and the Chukchi Sea has taken place in waters less than 167 feet deep,
and as recent as April 2020,\49\ there were active leases in the
Beaufort Sea where an SSID could have been deployed. These leases were
located in water depths less than approximately 170 feet deep. In these
water depths, during an emergency, a vessel could sink before the BOP
or SSID can be activated. A self-actuating system incorporated into the
SSID could potentially address this problem.
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\49\ In April 2020, the only leases with potential projects that
would be subject to the Arctic OCS's SSID or SSRW requirements were
relinquished. However, there are other active leases in the Beaufort
Sea located nearer to the shore in shallower waters where
exploration and development projects are actively being pursued
(primarily through man-made gravel islands).
---------------------------------------------------------------------------
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
lower marine riser package (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 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:
(1) Below the BOP;
[[Page 79296]]
(2) At or before the time they install their BOP; and
(3) In a way that will provide protection from deep ice keels in
the event it must remain in place over the winter season (e.g.,
installed in a mudline cellar).
Installing the SSID below the BOP would allow for quick detachment
of the BOP and other equipment above the SSID, which would be critical
when moving off of a location for emergency purposes. With respect to
timing of the SSID's installation, the operator would be required to
install the SSID at or before the time they install the BOP. The
proposed requirement for the SSID to be installed in a way that will
provide protection from deep ice keels would help ensure that the
device is not damaged by ice in areas of ice scour. As previously
discussed, this could be accomplished by placing the SSID in a mudline
cellar. In complying with this proposed requirement, the operator must
also consider situations where the drill site is not located in an ice
scour area, but could experience ice floes with keels deep enough to
clip and compromise the SSID if left on the seafloor over the winter
season.
In a new paragraph (a)(5), BSEE proposes to require the operator to
test the SSID according to the BOP testing requirements in 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 recent
incident data from 2013 to 2017, which may be accessed on BSEE's
website at https://www.bsee.gov/stats-facts/offshore-incident-statistics, to try to identify any past incidents involving the use of
a BSEE directed relief well to remedy the loss of well control. Aside
from the Macondo well incident in 2010, one incident in 2013 required
the drilling of a relief well (see https://www.bsee.gov/newsroom/latest-news/statements-and-releases/press-releases/drilling-of-relief-well-begins-at-south). Other loss of well control events during that
timeframe were successfully remedied with conventional well control
methods. These incidents occurred in the Gulf of Mexico and were
controlled by either circulating heavier weighted muds into the well or
closing the BOP (or both), to control pressures within the well. BSEE
would evaluate the individual circumstances associated with each case
to make this determination. For these reasons, BSEE's proposed changes
to 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)?
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
[[Page 79297]]
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 (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
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 GOM, 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. It is possible that normally pressured
zones may be highly permeable or contain fractures, in which lost
circulation can occur. This could cause a dynamic effect where drilling
mud flows into the permeable formation
[[Page 79298]]
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
high-pressured zones or other geologic hazards would not be encountered
before reaching the last casing point prior to penetrating a zone
capable of flowing hydrocarbons in measurable quantities-- ``such as,
but not limited to, risk modeling data, 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 in order to develop and design an offshore
exploration drilling project in the Arctic OCS. BSEE is requesting
comment on what other types of information could be used to demonstrate
the absence of abnormally pressured zones or other geologic hazards,
and how burden on the operator could change--increase or decrease--if
BSEE were to require its submission.
At the APD stage, BSEE would evaluate the operator's documentation
along with other accompanying geologic and engineering information/
analyses that must be submitted as part of their APD. BSEE would also
take into consideration any other available G&G information, such as
information gathered from prior drilling operations in the area (e.g.,
well log and pressure testing information), and any other applicable
geophysical information (e.g., seismic data). BSEE makes clear in its
proposed regulatory language that the Regional Supervisor will base the
determination for whether to allow the operator to delay staging of its
relief rig on the documentation the operator submits as well as any
other available data and information.
BSEE is also considering an alternative regulatory approach whereby
the Bureau would instead revise existing paragraph (b) by replacing
``surface casing'' with ``last casing point prior to penetrating a zone
capable of flowing hydrocarbons in measurable quantities.'' This option
would adjust the point in time during operations when the operator must
stage its relief rig. This alternative regulatory change would,
instead, require the operator to stage its relief rig before drilling
below or working below the last casing point prior to penetrating a
zone capable of flowing hydrocarbons in measurable quantities.
Under this regulatory option, BSEE would evaluate the geologic and
engineering information/analysis the operator must submit as part of
its APD, while also taking into consideration any other available G&G
information the Bureau may have (e.g., off-set well data, such as well
logs and pressure testing information, or geophysical information, such
as seismic data). Based on these different sources of information, BSEE
would determine whether there may be a need for the operator to
position the capping stack at an interval earlier than last casing
point prior to penetrating a zone capable of flowing hydrocarbons in
measurable quantities.
There may be cases where the operator or BSEE may not have
sufficient G&G or analogous well data during the permit review process
on a proposed project to provide an adequate level of certainty
regarding anticipated formations that may be encountered prior to
reaching the targeted productive formation. Therefore, BSEE is also
contemplating, as part of this regulatory option, a clarification that
the Regional Supervisor may require the operator to stage its relief
rig prior to drilling below or working below the last casing point
prior to penetrating a zone capable of flowing hydrocarbons in
measurable quantities if BSEE determines there is insufficient G&G or
analogous well data.
For example, there may be insufficient G&G or analogous well data
in cases where there have been a limited number of wells drilled within
proximity to the planned well. In most cases, G&G and analogous well
data are gathered from multiple sources. However, the same sets and
amounts of data and information may not be available for each area,
well, or project. There is no single set of criteria for determining
the sufficiency of G&G or analogous well data. The more data that are
available from sources near to the proposed drilling location, the
greater confidence BSEE will have in the G&G interpretations. BSEE
wants to ensure the operator has the most accurate data to make
determinations about where the zones capable of flowing hydrocarbons in
measurable quantities are located.
This alternative regulatory option would maintain the same level of
safety and environmental protection in comparison to BSEE's proposed
regulatory change. The decision on whether it is appropriate to delay
positioning of the capping stack below the surface casing resides with
BSEE. BSEE, ultimately, may not allow the operator to delay staging of
the relief rig if there are potential risks below the surface casing
that may require immediate relief rig deployment. However, the
distinction under this regulatory option is that the operator would not
need to specifically demonstrate that abnormally high-pressured zones
or other geologic hazards would be encountered above last casing point
prior to penetrating a zone capable of flowing hydrocarbons in
measurable quantities. BSEE would be responsible for making that
determination.
BSEE is specifically soliciting comments about its views of the
benefits or disadvantages of this regulatory option and the need for
the operator to verify on a case-by-case basis which zones are
incapable of flowing hydrocarbons in measurable quantities.
[cir] Expected Seasonal Ice Encroachment at the Drill Site
In the 2015 proposed Arctic Exploratory Drilling Rule, BSEE
determined that, because Arctic OCS exploratory drilling operations
from a MODU take place only during the open water season (i.e., that
period of time in
[[Page 79299]]
the summer and early fall when ice hazards can be physically managed
and there is no continuous ice layer over the water), it was critical
to ensure that drilling (including relief well drilling) and other
operations affected by sea ice are concluded before ice encroachment.
Ice encroachment may complicate or prevent drilling, transit, and oil
spill response operations. However, the analysis from the Bratslavsky
and SolstenXP study shows that the sea ice capabilities of an ice class
MODU and its support vessels can extend the currently available open-
water operating seasons in the Chukchi and Beaufort Seas, depending on
the drilling location within each planning area (id. at 143).
Therefore, BSEE proposes to eliminate the reference to ``expected
seasonal ice encroachment'' at the drill site in existing paragraph
(b). BSEE, however, would retain the requirement clarifying that the
relief rig must be different than the operator's primary drilling rig
and that the relief rig must be staged in a location such that it can
arrive on site, drill a relief well, kill and abandon the original
well, and abandon the relief well no later than 45 days after the loss
of well control. This proposed regulatory change would effectively
extend the drilling season in those cases where the operator's MODU and
associated support vessels are capable of safely operating beyond the
period when seasonal sea ice begins to encroach at a drill site. The
operator would no longer need to plan for their well operations to end
in time to complete a relief well prior to the date when sea ice is
expected to encroach on the drill site. The operator would, instead,
have to plan to end its operations with sufficient time to complete its
relief well prior to the anticipated date when sea ice conditions at
the drill site are approaching the ice classification capability and
rating limits of the operator's vessels.
BSEE and BOEM would evaluate the ice classification capabilities
and limitations of the operator's MODU and associated support vessels
using existing permitting and review processes. For example, through
BOEM's EP review process, the operator is required under existing Sec.
550.220(c)(6) to specify when it anticipates completing onsite
operations and when it anticipates terminating drilling operations. In
addition, Sec. 550.220(c)(1) requires the operator to describe how it
will design and conduct its exploratory drilling activities in a manner
that accounts for Arctic OCS conditions. Furthermore, in the EP
regulations at proposed Sec. 550.220(c)(1), BOEM would require the
operator to submit a description of how all vessels and equipment will
be designed, built, and/or modified to account for Arctic OCS
conditions and how such activities will be managed and overseen as an
integrated endeavor. This preamble discusses this proposed regulatory
change in more detail later. Collectively, this information provided in
an EP would allow BOEM (in conjunction with BSEE) to evaluate the
capability of the operator's equipment, including its vessels and
procedures to manage and mitigate risks associated with Arctic OCS
conditions.
At the APD stage, BSEE would also review the capabilities of the
operator's MODU and associated supporting vessels. Existing paragraph
(a)(2) of Sec. 250.470, What additional information must I submit with
my APD for Arctic OCS exploratory drilling operations? requires the
operator to describe how it plans to prepare its equipment, materials,
and drilling unit for service in the environmental, meteorological, and
oceanic conditions it expects to encounter at the well site and how its
drilling unit will be in compliance with the requirements of existing
Sec. 250.713, What must I provide if I plan to use a Mobile Offshore
Drilling Unit (MODU) for well operations. Paragraph (d) of Sec.
250.713 requires the operator, when using a MODU for well operations,
to provide the current Certificate of Inspection (for U.S.-flag
vessels) or Certificate of Compliance (for foreign-flag vessels) from
the USCG, as well as a Certificate of Classification. The operator must
also provide current documentation of any operational limitations
imposed by an appropriate classification society. As discussed earlier
in this section, the Bratslavsky and SolstenXP study notes that a
vessel's capabilities are identified by the ice classification for the
vessel, which is provided by marine classification societies such as
ABS and DNV GL. BSEE would evaluate the information required under
existing Sec. Sec. 250.470(a)(2) and 250.713(d), together with BOEM's
approval of the operator's end-of-season date(s) in the EP, to verify
whether the vessels' capabilities and limitations can support extending
operations beyond when seasonal ice is expected to arrive at the drill
site. However, in no case will BSEE approve a permit that proposes to
use a vessel that does not meet the existing requirements of Sec.
250.713, including providing a current certificate of inspection or
compliance from the USCG.
Finally, while BSEE is proposing these revisions to Sec. 250.472,
BSEE is seeking comment on whether there are other appropriate
approaches to well control operations in the Arctic, including
alternative equipment/technology or performance standards. For example,
although the NPC 2019 Report recommends accepting the use of an SSID in
place of the requirement for SSRW capability, it also recommends
replacing the relief rig and SSRW requirements with requirements that
specify the desired outcome (i.e., to stop the flow of a well and allow
the operator to propose equivalent technology and demonstrate its
capabilities). (NPC 2019 Report at 30). BSEE assumes that the NPC
recommends specifying a desired performance-based outcome in the
regulations that would allow the operator to propose and demonstrate
technologies capable of meeting that standard at the permitting stage,
rather than prescribing a particular technology, such as a relief rig.
Subpart G--Well Operations and Equipment
When and how must I secure a well? (Sec. 250.720)
BSEE proposes to delete the last sentence in existing paragraph
(c)(2) that states ``BSEE may approve an equivalent means that will
meet or exceed the level of safety and environmental protection
provided by a mudline cellar if the operator can show that utilizing a
mudline cellar would compromise the stability of the rig, impede access
to the well head during a well control event, or otherwise create
operational risks.'' In its place, BSEE proposes to insert a new
sentence that states ``You may request, and the Regional Supervisor may
approve, an alternate procedure or equipment in accordance with
Sec. Sec. 250.141 and 250.408.'' BSEE, however, would preserve the
basic requirement in in paragraph (c)(2) for the operator to use a
mudline cellar or an equivalent means if there is indication of ice
scour. The regulatory change BSEE is proposing in this section would
make clear that BSEE could approve the equivalent means of doing so in
accordance with Sec. Sec. 250.141, May I ever use alternate procedures
or equipment? and 250.408, May I use alternate procedures or equipment
during drilling operations?
The new language that BSEE proposes to insert reiterates
longstanding regulatory provisions contained in Sec. Sec. 250.141 and
250.408 that describe what procedures the operator must follow and
standards it must meet to receive BSEE's approval of a request to use
alternate procedures or equipment to those required by regulation.
Section
[[Page 79300]]
250.141 allows the BSEE District Manager or Regional Supervisor to
approve the use of any alternate procedures or equipment that the
operator may propose if the proposal provides a level of safety and
environmental protection that equals or surpasses BSEE's current
requirements. It also describes the types of information the operator
must submit or present to BSEE when requesting to use alternate
procedures or equipment. Section 250.408 requires the operator to
identify and discuss their proposed alternate procedures or equipment
in their APD.
Since the issuance of the 2016 Arctic Exploratory Drilling Rule,
BSEE learned that there is an industry misconception that the last
sentence in existing paragraph (c)(2) means that the operator would be
required to use a mudline cellar in all cases, except when the operator
can prove that the mudline cellar would present an operational risk--
effectively narrowing the scope of Sec. Sec. 250.141 and 250.408 in
this context. However, BSEE did not intend that language to constrain
the contexts in which operators could seek approval of alternatives to
the mudline cellar requirement. Rather, in response to commenters
expressing concern that use of a mudline cellar may create operational
risks in certain contexts, BSEE introduced that language to make clear
that alternate approaches were available in those contexts, while at
the same time highlighting the general flexibility available under
Sec. 250.141, May I ever use alternate procedures or equipment? (see
81 FR 46507 and 46510). The last sentence in existing paragraph (c)(2)
was not intended to, and did not, restrict or preclude use of the
longstanding options for seeking approval of alternate procedures or
equipment under Sec. Sec. 250.141 and 250.408, which do not
necessarily require a demonstration of operational risk. Thus, this
proposed change would clarify that the operator has more flexibility to
propose alternate solutions to the mudline cellar requirement under a
broader range of circumstances than those described in the last
sentence of existing Sec. 250.720(c)(2). An operator could still base
such a request on the same grounds that BSEE described in the language
that we propose to delete (i.e., that installation of a mudline cellar
in a specific case would cause operational risks).
B. Key Revisions Proposed by BOEM
Title 30, Chapter V, Subchapter B, Part 550, Subpart B--Plans and
Information Definitions. (Sec. 550.200)
BOEM is proposing to eliminate the definition of the term
``Integrated Operations Plan,'' consistent with the proposal to
eliminate the requirement for the operator to submit an IOP for the
reasons listed immediately below.
Removal of the IOP Requirement (Sec. 550.204)
The 2016 Arctic Exploratory Drilling Rule discussed how commenters
generally criticized the IOP provision as being duplicative or
redundant of existing requirements (see 81 FR at 46492-46493). In 2016,
when the rule was adopted, BOEM disagreed with these commenters and
published responses to the commenters in the preamble. In its
responses, BOEM discussed how the IOP was distinct from existing
regulations, the importance of contractor management as it related to
the IOP provisions, and the BOEM Regional Director's ability to waive
submission of required information in the EP that was already provided
in the IOP. Circumstances have changed since the IOP requirement was
originally adopted. The various Federal agencies have improved their
coordination to such an extent that BOEM believes there is no need for
operators to create and submit a separate IOP for that purpose. Much of
the required content of the two documents overlaps, and in the 2016
rulemaking itself BOEM added requirements that the EP include
additional information that made this overlap even greater. BOEM is now
proposing to keep two important provisions from the IOP and incorporate
them into the requirements for EPs. The first provision would reinforce
BOEM's commitment to operational safety, while the second provision
would require the operator to provide details of how its operations
would conform to the unique circumstances of the Arctic OCS. Taken
together, the enhancements to BOEM's regulations made in connection
with the 2016 Arctic Exploratory Drilling Rule and the retention of
these key provisions from the IOP make the IOP unnecessary and
redundant.
For these reasons, BOEM proposes to eliminate the requirement for
preparing and submitting the IOP. In doing so, BOEM would delete all of
Sec. 550.204, and remove corresponding references to the IOP from
Sec. Sec. 550.200 and 550.206. Currently, BOEM requires the operator
to submit an IOP at least 90 days before filing an EP with BOEM. The
IOP is not subject to agency approval. BOEM developed the IOP
requirement based on the Report to the Secretary of the Interior,
Review of Shell's 2012 Alaska Offshore Oil and Gas Exploration Program,
prepared by DOI (60-Day Report), March 2013,\50\ which included \51\
the following recommendation:
---------------------------------------------------------------------------
\50\ Available at: https://www.doi.gov/sites/doi.gov/files/migrated/news/pressreleases/upload/Shell-report-3-8-13-Final.pdf.
\51\ Report to the Secretary of the Interior, Review of Shell's
2012 Alaska Offshore Oil and Gas Exploration Program, prepared by
DOI (60-Day Report), March 2013, available at: https://www.doi.gov/sites/doi.gov/files/migrated/news/pressreleases/upload/Shell-report-3-8-13-Final.pdf.
All phases of an offshore Arctic program--including
preparations, drilling, maritime and emergency response operations--
must be integrated and subject to strong operator management and
---------------------------------------------------------------------------
government oversight. (60-day report, p. 3).
The information provided in the IOP was intended to facilitate the
prompt sharing of information among the relevant Federal agencies
(e.g., BOEM, BSEE, USFWS, USCG, NMFS, U.S. Army Corps of Engineers, and
EPA). Standing BOEM practice (LP-SOP-06 Standard Operating Procedure
for Exploration Plans) in the Anchorage, Alaska OCS Office is to inform
other agencies about an operator's EP, well in advance of the
completeness review (i.e., the deemed submitted determination) for the
EP. BOEM successfully did so prior to the 2016 implementation of the
IOP requirement.
The IOP requirement does not supersede or supplant the operator's
obligation to comply with all other applicable Federal agency
requirements. As described in the 2016 Arctic Exploratory Drilling
Rule, the IOP process does not provide a mechanism for agencies to
approve or disapprove the operator's proposed activities. BOEM has no
authority under the IOP provision other than to make unenforceable
suggestions to the operator. If BOEM or another agency determined that
an operator was failing to engage in the needed integrated planning in
advance of EP submission, BOEM could only compel an operator to do so
through the EP review process.
The 2016 Arctic Exploratory Drilling Rule added informational
requirements for EPs to address key concerns that motivated the IOP, as
shown in Table 1, ``Crosswalk between the IOP provisions proposed for
removal and existing EP regulations and review practices.'' Because
this information is required in the EP, operators should be aware that
they must plan for how they will manage contractors to reduce
[[Page 79301]]
operational risks and address the challenges associated with operations
on the Arctic OCS. The EP regulations are clear that the operator must
plan to coordinate the work of a number of contractors to ensure that
time pressure, or other contractor complications, do not undermine safe
and environmentally responsible operations. In particular, proposed
Sec. 550.220(c)(1) would require the operator to describe in the EP
how it will design and conduct its exploratory drilling activities, and
how it will manage and oversee these activities as an integrated
endeavor. BOEM does not need, and nothing in OCSLA requires, an
operator to inform Federal agencies about its planning on these issues
in advance of an EP. The EP, however, will make evident whether the
operator has done so, and if the EP does not address the operators'
planning on all the required elements, BOEM will return the EP to the
operator to include the requisite information in accordance with
existing Sec. 550.231(b).
As part of the 2016 Arctic Exploratory Drilling Rule, BOEM expanded
the regulatory criteria for EPs to include information important for
planning Arctic exploratory drilling. Specifically, BOEM expanded
requirements for: Emergency plans at existing Sec. 550.220(a), the
EP's suitability for Arctic OCS conditions at proposed Sec.
550.220(c)(1), ice and weather management at existing Sec.
550.220(c)(2), SCCE capabilities at existing Sec. 550.220(c)(3),
deployment for a relief rig at proposed Sec. 550.220(c)(4), resource-
sharing at existing Sec. 550.220(c)(5), and anticipated end of
seasonal operation dates at existing Sec. 550.220(c)(6).
BOEM's EP and environmental impact analysis (EIA) requirements at
existing Sec. 550.202, What criteria must the Exploration Plan (EP),
Development and Production Plan (DPP), or Development Operations
Coordination Document (DOCD) meet?, existing paragraphs (a) and (c) of
Sec. 550.211, What must the EP include?, existing paragraph (c) of
Sec. 550.216, What biological, physical, and socioeconomic information
must accompany the EP?, existing paragraphs (a) and (b) of Sec.
550.219, What oil and hazardous substance spills information must
accompany the EP?, existing paragraphs (b), (c)(2) and (5) of Sec.
550.220, If I propose activities in the Alaska OCS Region, what
planning information must accompany the EP?, proposed paragraph (c)(1)
of Sec. 550.220, existing paragraph (a) of Sec. 550.224, What
information on support vessels, offshore vehicles, and aircraft you
will use must accompany the EP?, and existing paragraph (b)(7) of Sec.
550.227, What environmental impact analysis (EIA) information must
accompany the EP? require the operator to address issues that the
operator also needs to consider in preparing the IOP. The following
table provides a detailed analysis of how the key operational
provisions of the IOP are addressed in BOEM's existing regulations, and
why the key safety provisions of the IOP will continue to be fully
addressed by other provisions within BOEM's regulations:
Table 1--Crosswalk Between the IOP Provisions Proposed for Removal and
Existing EP Regulations and Review Practices
------------------------------------------------------------------------
Coverage in BOEM's continuing
IOP provision regulations, operator EPs, and
review practices
------------------------------------------------------------------------
Sec. 550.204(a)--The operator Sec. 550.220 (c)(1)--The
describes how vessels and equipment operator describes how drilling
were designed for Arctic OCS activities account for Arctic
conditions; OCS conditions.
Sec. 550.204(b)--The operator Sec. 550.211(a)--The operator
includes a schedule of the includes a schedule and
exploratory program; discussion of objectives for
its exploration program.
Sec. 550.204(c)--The operator Sec. 550.220 (c)(1)--The
describes how its plans account for operator describes how drilling
Arctic OCS conditions; activities account for Arctic
OCS conditions.
Sec. 550.220(c)(2)--The
operator describes weather and
ice forecasting and management
plans.
Sec. 550.224(a)--The operator
describes vessels and aircraft
it would use during
exploration, including storage
capacity of fuels.
Sec. 550.202--BOEM must review
plans to ensure they are safe
and do not cause undue or
serious harm or damage to the
human, marine, or coastal
environment.
Sec. 550.204(d)--The operator Sec. 550.211(a)--The operator
describes general abandonment plans includes a schedule and
for wells; discussion of objectives for
its exploration program.
Sec. 550.220 (c)(1)--The
operator describes how drilling
activities account for Arctic
OCS conditions.
Sec. 550.220(c)(2)--The
operator describes weather and
ice forecasting and management
plans.
Sec. 550.220(c)(6)(ii)
(proposed)--The operator would
describe the termination of
drilling operations consistent
with the well control planning
requirements under Sec.
250.472 of this title.
Sec. 550.204(e)--The operator Sec. 550.220(c)(2)--The
describes its plans for responding operator describes weather and
and managing ice hazards and weather ice forecasting and management
events; plans.
Sec. 550.220(b)--The operator
would describe critical
operations and curtailment
procedures.
Sec. 550.204(f)--The operator Sec. 550.220 (c)(1)--The
describes work to be performed by operator describes how drilling
contractors; activities account for Arctic
OCS conditions.
Sec. 550.220(c)(2)--The
operator describes weather and
ice forecasting and management
plans.
Sec. 550.202--BOEM must review
plans to ensure they are safe
and do not cause undue or
serious harm or damage to the
human, marine, or coastal
environment.
Sec. 550.204(g)--The operator Sec. 550.211(c)--The operator
describes how it will ensure would describe the drilling
operational safety; unit, associated equipment,
safety features, and storage of
fuels and oils.
Sec. 550.220 (c)(1)--The
operator describes how drilling
activities account for Arctic
OCS conditions.
[[Page 79302]]
Sec. 550.204(h)--The operator Sec. 550.219 (a) and Sec.
describes oil spill response plans; 550.219 (b)--The operator would
describe its oil spill response
plan and associated spill
modeling report.
Sec. 550.204(i)--The operator Sec. 550.216 (c)--the operator
describes efforts to minimize impacts must analyze socioeconomic
to local community infrastructure; resources associated with its
exploratory program.
Sec. 550.227 (b)(7)--The
operator must describe
socioeconomic resources
including employment and
subsistence resources and
harvest practices.
Sec. 550.204(j)--The operator Sec. 550.220 (c)(5)--The
describes how it could rely on local operator describes agreements
communities for parts of its it has with third parties in
exploratory drilling program. the event of an oil spill or
emergency.
Sec. 550.219 (a) and Sec.
550.219 (b)--The operator would
describe its oil spill response
plan and associated spill
modeling report.
Sec. 550.227 (b)(7)--The
operator must describe
socioeconomic resources
including employment and
subsistence resources and
harvest practices.
------------------------------------------------------------------------
The following information that was previously required as part of
the IOP submission, but not included in the EP requirements, is
proposed to be added to the relevant sections of the EP:
------------------------------------------------------------------------
Existing regulation text New provision
------------------------------------------------------------------------
Sec. 550.204(a)--The operator Sec. 550.220(c)(1)--The
describes how vessels and equipment operator describes how the
were designed for Arctic OCS exploratory drilling (including
conditions; vessels and equipment) would
account for Arctic OCS
conditions, including any
allowances or limitations its
vessels have from a
classification society and/or
the USCG.
Sec. 550.204(g)--The operator Sec. 550.211(b)--the operator
describes how it will ensure describes how it will ensure
operational safety; operational safety.
------------------------------------------------------------------------
To the extent that there is not an exact correlation between the
information required in the IOP and that required in the EP, BOEM and
BSEE believe that the additional information required in the IOP that
is not in the EP is not necessary and certainly not necessary in
advance of the EP.
Furthermore, the BOEM Anchorage, Alaska OCS Office meets with
members of the Interagency Working Group on Alaska Energy Permitting
and other relevant agencies, before an EP is submitted or deemed
submitted. Although BOEM previously argued that the IOP would not
delay, but in fact, speed development by encouraging earlier review and
coordination between regulatory agencies, BOEM no longer believes that
is the case. While it is true that the IOP might speed up BOEM's review
and approval of an EP, by encouraging earlier review and coordination
among agencies, such acceleration would not shorten the overall
planning process undertaken by the operator to prepare and submit an
EP. The operator should conduct the same degree of planning with or
without an IOP, because such planning is necessitated by the EP
requirements. The IOP merely shifts some of the agency review to
earlier in the process. With or without a prescriptive requirement for
an IOP, the operator's thorough advance planning and coordination
between BOEM, the operator, and other agencies prior to submission,
will result in fewer unexpected issues overall. In practice, the entire
planning process from initial concept to actual drilling should be the
same, with or without an IOP. What is more important in terms of
timeline, is the detailed work the operator would conduct in preparing
and submitting a well-crafted EP.
How do I submit the EP, DPP, or DOCD? (Sec. 550.206)
BOEM proposes to delete all references to the IOP in this section.
The substantive provisions of this section that relate to EPs, DPPs,
and DOCDs would remain unchanged.
What must the EP include? (Sec. 550.211)
BOEM proposes to move existing Sec. 550.204(g) to Sec. 550.211 as
a new paragraph (b). All other provisions of Sec. 550.211 would remain
unchanged. The addition of the provision from Sec. 550.204 into Sec.
550.211 is designed to describe operational safety procedures that the
operator has developed specific to conditions relevant on the Arctic
OCS. These requirements were previously included in the IOP and not
specifically enumerated as part of the requirements for an EP, although
similar, more general requirements are already part of paragraphs (a),
Description, objectives, and schedule, and (c), Drilling unit of this
section. Paragraph (c) requires the operator to describe the drilling
unit, associated equipment, safety features, and storage of fuels and
oils.
Without the current IOP provisions, the applicant would already
need to have the information required by this paragraph in order to
comply with BSEE's regulations that currently require operators to
develop, implement, and maintain a safety and environmental management
system (SEMS) program (Subpart S, Sec. Sec. 250.1900 to 250.1933), and
as a result, moving this requirement from Sec. Sec. 550.204 to 550.211
does not add any burden.
Retaining this important provision as part of the requirements for
exploratory drilling on the Arctic OCS ensures consistency with the
goals of this rulemaking and to better align BOEM's rules with those of
BSEE. The following is a description of the provision that is being
retained. The section describes how an operator will ensure operational
safety while working in Arctic OCS conditions, including but not
limited to:
(1) The safety principles that it intends to apply to itself and
its contractors;
(2) The accountability structure within its organization for
implementing such principles;
[[Page 79303]]
(3) How it will communicate such principles to its employees and
contractors; and
(4) How it will determine successful implementation of such
principles.
The text of this transferred regulation provision is identical to
what it was in Sec. 550.204(g). As such, this addition to Sec.
550.211 will not impose any new burden on lessees or operators. BOEM
believes that retaining this important safety and environmental
protection is a necessary part of ensuring that energy exploration and
development activity is safe and environmentally responsible.
If I propose activities in the Arctic OCS Region, what planning
information must accompany the EP? (Sec. 550.220)
BOEM proposes to revise paragraphs (c)(1) and (4), and (c)(6)(ii)
of Sec. 550.220 to conform to BSEE's proposed changes to Sec.
250.472, What are the additional well control equipment or relief rig
requirements for the Arctic OCS?
Existing paragraph (c)(1) of Sec. 550.220 would be revised to add
text to account for the text in existing Sec. 550.204(a), which would
be removed. With the elimination of Sec. 550.204, BOEM proposes to
combine the requirements of these two sections into a revised Sec.
550.220(c)(1) that would require the operator to describe how its
exploratory drilling (including vessels and equipment) would account
for Arctic OCS conditions, including any allowances or limitations its
vessels have from a classification society and/or the USCG.
BOEM is proposing to add a new informational requirement for
modified vessels. BOEM is seeking to confirm that the operator meets
the requirements of other entities with authority over vessels, not to
impose requirements on those vessels. Although this revised paragraph
would appear to add new requirements, in fact this revision would
simply clarify and formalize the existing arrangements between BOEM and
these other entities. This provision is proposed in order to avoid any
potential confusion that might otherwise arise regarding the
incorporation of the existing IOP requirements into the EP and how they
may relate to the regulations and jurisdiction of the United States
Coast Guard, or the flag state of the vessel. According to this
proposed revision, for vessel modifications, the operator would
describe any approvals from the flag state and vessel classification
society and include in that description any allowances or limitations
placed upon the vessel by the classification society and/or USCG.
Vessel modifications may include the suitability of vessels for Arctic
conditions. These vessels may have or acquire classification from a
``recognized organization'' under the USCG's Alternative Compliance
Program (ACP).\52\ This specification provides the operator with
guidance on what information the EP should contain to show that its
vessels would be able to operate safely in the Arctic OCS. The
specification would also show that BOEM is not duplicating regulations
from USCG by acknowledging that the flag state, USCG, and/or the
classification society have authority for approvals, allowances, and
limitations placed upon modified vessels. For these reasons, this
change would impose no material additional burden on lessee or
operators beyond that which already exists and which has already been
accounted for in the information collection burden for this section.
---------------------------------------------------------------------------
\52\ 33 U.S.C. 3316 and 46 CFR part 8 implement the USCG's ACP.
---------------------------------------------------------------------------
To ensure consistency with BSEE's proposed regulatory changes, BOEM
is proposing to revise paragraphs (c)(4) and (c)(6)(ii) by requiring
the operator to provide a general description of how they will comply
with Sec. 250.472, including a description of the termination of their
operations. BSEE is proposing to revise Sec. 250.472 to provide the
operator with the option to either use an SSID or have access to a
relief rig, as an additional means to secure the well in the event of a
loss of well control, if the operator will be conducting exploratory
drilling operations from a MODU.
III. Additional Comments Solicited
To assist BSEE and BOEM in these revisions, we are requesting
public comments on specific issues discussed in the preamble. We will
consider these comments while developing final regulations. To provide
necessary context, we included the requests for public comments in
appropriate locations throughout the preamble. For ease of commenting,
we consolidated the requests for comments in this section of the
preamble. While BSEE and BOEM are soliciting comment on specific topics
associated with the proposed rule, the bureaus welcome the public to
submit information or comment on any other topics relevant to this
rulemaking that may not necessarily pertain to the bureaus' specific
solicitation. At this stage, the bureaus are open to considering any
option that would improve the regulatory changes proposed, including
maintaining the original requirement as part of the final rule. In all
cases, please provide supporting reasons and data for your responses.
(i) Well Design When Using an SSID (Sec. 250.472(a))--BSEE is
seeking comments on how well design could be better addressed in this
rulemaking to enhance the overall safety of operations on the Arctic
OCS. More specifically, BSEE would like to know whether the well design
requirement in proposed Sec. 250.472(a) is adequate to address
situations the operator may encounter if a well is shut-in with an SSID
over an entire winter season (e.g., six to nine months). These
situations could include cases where the wellbore pressure profile may
increase to reservoir pressures at the top of the well over the course
of the winter season. BSEE would also like to know whether there are
other scenarios that may occur in a shut-in well over the ice season.
(ii) SSID Efficacy Relative to the Relief Rig and SSRW--BSEE is
proposing to revise the relief rig and SSRW requirement with the intent
to minimize environmental damage due to a prolonged ongoing well
control event. When drilling a relief well, there is a delay in
stopping the uncontrolled flow of oil and other fluid into the marine
environment while relief well drilling operations are taking place.
When properly functioning as designed, there is usually no delay for
operational use of an SSID compared to the process of utilizing the
relief rig or capping stack. If the SSID does not initially function,
the SSID may still be activated through the ROV intervention equipment
and capabilities that BSEE is proposing as a SSID design requirement.
The SSID would operate independently from the BOP. By having two
independent, redundant components, as part of the well control system,
the overall reliability and effectiveness of the entire system
increases. BSEE would like to know of any cases or data, in addition to
what we have already discussed in the preamble, regarding the
performance and reliability of the SSID and its effectiveness compared
to drilling a relief well.
(iii) NPC Report and Bratslavsky and SolstenXP Study--The NPC 2019
Report and the Bratslavsky and SolstenXP study have been valuable tools
that were not available when promulgating the 2016 Arctic Exploratory
Drilling Rule. BSEE requests the public to provide additional
information or clarification related to those portions of these reports
that the Bureau relied upon in this rulemaking.
(iv) SSID Capability to Preserve Isolation Over the Winter Season
(Sec. 250.472(a)(1)(iv))--BSEE proposes to require that the SSID must
be capable of
[[Page 79304]]
preserving isolation through the winter season without solely relying
on the elastomer elements of the rams (e.g., by using a well cap) and
allow re-entry during the following open-water season. BSEE understands
that the operator is able to achieve long-term isolation by installing
a well cap (i.e., a metal-to-metal cap) on the SSID before leaving the
device on the seafloor over the winter season. BSEE would like to know
if there are means by which isolation would be preserved through the
winter season in cases where a late-season emergency situation may not
provide adequate time or ability to access the SSID to install a well
cap.
(v) SSID Dual Shear Requirement in Proposed Sec.
250.472(a)(2)(i)--The NPC 2019 Report describes the SSID used in the
Kara Sea Project as having dual blind shear rams. BSEE does not propose
requiring the SSID to be equipped with dual blind shear rams. However,
BSEE is seeking comment on the advantages or disadvantages between dual
blind shear rams and using dual shear rams, with ram locks, with one
ram being a blind shear ram.
(vi) SSID Redundant Control System Capabilities (Sec.
250.472(a)(2)(ii))--BSEE proposes to require the SSID to use a
redundant control system that includes ROV capabilities and a control
station on the rig that is independent from the BOP control system.
BSEE is contemplating whether it may be more appropriate to require the
SSID's redundant control system capabilities to be separate from its
ROV's capabilities, and to be consistent with the fully redundant
control system requirements described in API Spec. 16D, Specification
for Control Systems for Drilling Well Control Equipment and Control
Systems for Diverter Equipment, Second Edition, July 2004, reaffirmed
August 2013; incorporated by reference at Sec. 250.198(e)(90); (e.g.,
yellow pod and blue pod). In addition to meeting the ROV requirements
in existing Sec. 250.734(a)(5), BSEE is also considering whether there
should be an additional manual method (separate from the redundant
control system) to close the SSID's rams with the ROV and whether it
may be appropriate to require a standby or tending vessel with an ROV.
There could be cases where the SSID's control system on the drilling
rig is not available (e.g., due to failure or an evacuation of the
rig).
(vii) SSID Testing Requirements (Sec. 250.472(a)(5))--BSEE is
seeking comment on whether it is appropriate to align the SSID's
proposed testing requirements with BSEE's existing BOP testing
requirements in Sec. 250.737, What are the BOP system testing
requirements?, or whether there are more appropriate and reliable
testing methods for SSIDs. BSEE would like to receive information on
what testing procedures have been used in the past to test an SSID when
it was deployed, or what testing procedures are being developed for
future projects.
(viii) Relief Rig Staging and Capping Stack Positioning
Requirements--BSEE proposes to revise the staging and positioning
requirement for the relief rig and capping stack, respectively, by
providing an opportunity to the operator to adjust the point in time
during its operations when it must stage or position these pieces of
equipment, from ``when drilling below or working below the surface
casing'' to ``when drilling below or working below the last casing
point prior to penetrating a zone capable of flowing hydrocarbons in
measurable quantities.'' If the operator is able to demonstrate to BSEE
that the operations it plans to conduct below the surface casing would
not encounter any abnormally high-pressured or other geologic hazards
before reaching the last casing point prior to penetrating a zone
capable of flowing hydrocarbons in measurable quantities, then BSEE
would allow the operator to delay staging of its relief rig or
positioning of its SCCE until reaching that point. BSEE would like to
know whether there are more appropriate criteria, other than
``abnormally high-pressured zones or other geologic hazards,'' that
should be used to determine whether to allow the operator to delay
positioning of the capping stack and relief rig. BSEE is also
requesting comment on what types of information, other than what is
listed in proposed Sec. 250.471(a) and Sec. 250.472 (b)--risk
modeling data, off-set well data, analog data, and seismic data, could
be used to demonstrate the absence of abnormally pressured zones or
other geologic hazards, and how burden on the operator could change--
increase or decrease--if BSEE were to require submission of that
information in its APD.
(ix) Alternative Regulatory Approach to the Relief Rig and Capping
Stack Positioning Requirements--BSEE is considering an alternative
regulatory approach in which BSEE would revise the staging and
positioning requirement for the relief rig and capping stack,
respectively, by adjusting the point in time during its operations when
it must stage or position these pieces of equipment, from ``when
drilling below or working below the surface casing'' to ``when drilling
below or working below the last casing point prior to penetrating a
zone capable of flowing hydrocarbons in measurable quantities.''
However, there could be cases where the operator or BSEE may not have
sufficient G&G or analogous well data on a proposed project to
confidently identify the location of the first formation that the
operator may encounter that is capable of flowing hydrocarbons in
measurable quantities. BSEE is soliciting the public's comments about
this regulatory approach. BSEE is also soliciting comment about the
need for the operator to verify, on a case-by-case basis, zones not
capable of flowing hydrocarbons in measurable quantities.
(x) Installing and Operating an SSID in a Mudline Cellar--BSEE is
requesting more information about whether there are any operational or
installation challenges the operator may encounter in attempting to
operate the SSID when it is installed in a mudline cellar. In areas of
ice scour, BSEE's current regulations at Sec. Sec. 250.734(a)(13) and
250.738(h) require placement of subsea BOP systems in mudline cellars.
In addition, proposed Sec. 250.720(c)(2) requires placement of the
wellhead in a mudline cellar in areas of ice scour. Proposed Sec.
250.472(a)(4)(i) would require installation of the SSID below the BOP.
(xi) Operating an SSID with a Subsea BOP Installed on the
Seafloor--Historically, drilling in the Beaufort Sea and the Chukchi
Sea has occurred in waters less than 167 feet deep, and as recent as
April 2020,\53\ there were active leases in the Beaufort Sea where an
SSID could have been deployed. If the operator installs all well
control systems on the seafloor (subsea BOP systems and SSIDs), there
could be as much as 128 feet of water column taken up by these systems
and a ship's hull (if a drillship is used). BSEE would like to know
what challenges operators could face in cases where there is little
room to operate. BSEE would also like to know how operators addressed
those challenges in the past, or how such challenges could be addressed
in future operations.
---------------------------------------------------------------------------
\53\ In April of 2020, the only leases with potential projects
that would be subject to the Arctic OCS's SSID requirements were
relinquished. However, there are other active leases in the Beaufort
Sea located nearer to shore in shallower waters where exploration
and development projects are actively being pursued (primarily
through man-made gravel islands).
---------------------------------------------------------------------------
(xii) Fail-Safe Mechanisms Used on an SSID--BSEE is seeking comment
on what fail-safe mechanisms exist that could be applied to an SSID in
cases where a subsea BOP system is used. BSEE is contemplating whether
it may be necessary to require mechanisms, such as autoshear or deadman
for the SSID, to address emergency situations, such as a sunken MODU,
where the
[[Page 79305]]
subsea BOP system may have failed and the SSID could no longer be
functioned via the rig or ROV (due to lack of access). BSEE currently
has fail-safe requirements for subsea BOP systems (autoshear and
deadman systems), which could be applied to SSIDs. However, there could
be unintended consequences from applying these fail-safe systems on an
SSID when a subsea BOP system is used. BSEE is seeking comment on what
fail-safe mechanisms could be deployed to address cases where the BOP
fails and the SSID is inaccessible by an ROV or a MODU control station.
If an autoshear system or a deadman system are appropriate fail-safe
mechanisms, BSEE is seeking input on what criteria should be used to
function these systems, to ensure they do not function at the wrong
time or interfere with or impact the subsea BOP's autoshear and deadman
systems.
(xiii) Autoshear and Deadman System Requirements for Surface BOPs--
BSEE is contemplating establishing autoshear and deadman system
requirements in cases where operators use a surface BOP. BSEE does not
currently require the use of an autoshear or deadman system with
surface BOPs. BSEE is seeking comment on what criteria should be
established to function the autoshear or deadman systems in connection
with a surface BOP. BSEE welcomes any other comments, unrelated to
autoshear or deadman systems, which require additional consideration in
those cases where a surface BOP is used.
(xiv) Outcome-based Well Control System Requirements--BSEE is
seeking comment on other appropriate approaches to well-control
operations in the Arctic. The NPC 2019 Report recommends accepting the
use of an SSID in place of the requirement for SSRW capability.
However, it also recommends replacing the relief rig and SSRW
requirements with requirements that specify desired outcomes (i.e., to
stop the flow of a well and allow the operator to propose equivalent
technology and demonstrate its capabilities). BSEE assumes that the NPC
recommendation would entail a performance-based approach to the
regulations, in which the operator could propose and demonstrate new
technologies to meet a stated objective, rather than being required to
use certain technologies, such as a relief rig.
(xv) Suspension of Operations--BSEE is considering the option of
limiting the period during which a suspension would remain in effect to
the period between one drilling season and the next when the operator
is prevented from continuing its drilling or other leaseholding
activities due to seasonal conditions. BSEE is seeking comment on this
regulatory option for the new SOO provision it is proposing in a new
paragraph (d) of Sec. 250.175, or any other option that could avoid or
minimize the additional burdens associated with making requests on an
annual basis (if the duration of the suspension needs to be longer),
but still assure diligent lease exploration and development.
(xvi) Other Solicited Comments--BSEE is also requesting comments on
the specific costs and operational implications of each of the
regulatory changes included in this proposed rule.
IV. Procedural Matters
A. Regulatory Planning and Review (Executive Orders (E.O.) 12866,
13563, and 13771)
Executive Order 12866 provides that the Office of Information and
Regulatory Affairs (OIRA) within OMB will review all significant rules.
This proposed action is an economically significant regulatory action
that was submitted to OMB for review, as it would have an annual effect
on the economy of $100 million or more. BSEE and BOEM developed an
economic analysis to assess the anticipated costs and potential
benefits of the proposed rule. Due to uncertainty surrounding the
outcome of ongoing litigation regarding the availability of Arctic OCS
planning areas for future leasing and energy development, BSEE and BOEM
developed two baseline activity level forecasts: (1) Activity levels
expected if the full Beaufort and Chukchi Sea planning areas are
reopened (i.e., the Full Arctic baseline), and (2) reduced activity
levels if these areas remain withdrawn from leasing (i.e., the
Restricted Beaufort baseline). Under either scenario, the proposed
action would be economically significant as a result of the estimated
cost savings of this proposed rule. BSEE and BOEM estimate the
amendments proposed in this rulemaking would provide annualized net
benefits of $142 million under the Full Arctic baseline, or $121
million under the Restricted Beaufort baseline, discounted at 7
percent.
Details on the estimated cost savings of this proposed rule can be
found in the rule's Initial Regulatory Impact Analysis (IRIA). The net
quantified benefits for this proposed rule are based on cost savings
less forgone benefits. The cost savings to both government and industry
result from removing regulatory redundancies, reduction in paperwork
burdens, provision for alternative methods of compliance, and adoption
of improved industry technology. Forgone benefits result from slight
increases in the risks to subsistence hunters and fishermen and
wildlife stemming from an increased probability of small or
catastrophic oil spills. The cost savings exceed the forgone benefits,
leading to the net benefits summarized in the following paragraphs.
This proposed rule would revise regulatory provisions in 30 CFR
part 250, subparts A, C, D, and G, and 30 CFR part 550, subpart B. BSEE
and BOEM have reassessed a number of the provisions promulgated through
the 2016 Arctic Exploratory Drilling Rule and are proposing to revise
some provisions to reflect performance-based standards rather than
prescriptive requirements. Other revisions remove redundant regulatory
oversight provisions and provide regional flexibility in the
administration of suspensions and associated lease term extensions,
without significantly impacting the current levels of safety and
environmental protection. The bureaus sought the best available data
and information to analyze the economic impact of these changes. The
IRIA for this rulemaking can be found in the https://www.regulations.gov/ docket (Docket ID: BSEE-2019-0008).
BSEE and BOEM are proposing to revise certain regulations
promulgated through the 2016 Arctic Exploratory Drilling Rule based on
new information generated since the 2016 rule was finalized, and to
support the goals of the Administration's regulatory reform
initiatives, while ensuring safety and environmental protection. This
proposed rule would revise certain existing regulations--Sec. Sec.
250.105; 250.175; 250.198; 250.300(b); 250.470(b), (f), and (h);
250.471(a) and (b); 250.472(a), (b), and (c); 250.720(c); 550.200;
550.204; 550.206; 550.211; and 550.220(c). The bulk of the net benefits
are derived from cost savings driven by a proposed revision to existing
Sec. 250.472(b) and (c), which is discussed below. The analysis
suggests forgone benefits are small compared to the cost savings, and
the primary forgone benefits are from possible impacts on the
environment and subsistence hunting and whaling communities, that could
be caused by an oil spill of greater duration and higher discharge
volumes in the event the BOP, SSID, and capping stack were to fail in
sequence, and a containment dome and flow system would be needed to
capture oil flowing from the well while relief-well drilling operations
are underway. These, and the other provisions, are discussed in greater
detail within the IRIA.
[[Page 79306]]
The largest contributor to net benefits attributable to the
proposed rule is the proposed revision to existing Sec. 250.472
paragraphs (a), (b), and (c). As promulgated under the 2016 Arctic
Exploratory Drilling Rule, this provision currently requires the use of
a `relief rig' and adoption of a 45-day shoulder season. The relief rig
is a secondary drilling vessel that is available and capable of
drilling an SSRW in the event of a loss of well control. The 45-day
``shoulder season'' was the maximum time permitted by the regulations
to mobilize the relief rig to an incident, drill a relief well, kill
and abandon the original well, and abandon the relief well prior to
expected seasonal ice encroachment at the drill site. This shoulder
season necessarily compresses the already short Arctic drilling
timeframe and also limits the ability of operators to drill and
complete a well in one season. The proposed revisions to Sec. 250.472
would provide the operator with the option to either use an SSID or
have access to a relief rig, as an additional means to secure the well
in the event of a loss of well control, if the operator will be
conducting exploratory drilling operations from a MODU. The two
features of this flexibility driving the cost savings are the removal
of the shoulder season and removal of the requirement for the secondary
drilling vessel, if the operator elects to install an SSID to comply
with Sec. 250.472. Because of the relative cost effectiveness of
procuring, and potential well control advantages of installing an SSID
versus mobilizing a relief rig and the necessary support vessels and
personnel, BSEE assumes operators will prefer this option when using
MODUs. This proposed change would produce an annualized cost savings of
$142 million under the Full Arctic baseline, or $121 million under the
Restricted Beaufort baseline, discounted at 7%.
This proposed rule would reduce the burden imposed on industry,
while maintaining safety and environmental protection. The forgone
benefits of adopting the proposed rule include possible impacts on the
environment, subsistence hunting and whaling communities, and an oil
spill of greater duration with higher discharge volumes in the event a
BOP and SSID were to fail. As discussed earlier in the preamble, BSEE
proposes to require operators to operate an SSID independently from the
BOP. By having two independent, redundant components (i.e., the BOP and
the SSID) as part of the well control system, the overall reliability
and effectiveness of the entire system increases. In the event both
devices were to fail, the capping stack would still be used as required
in the permitted timeframe. When a capping stack is used to contain a
well, the relief well can be drilled without an ongoing active spill
event. If the capping stack were to fail, the containment dome and flow
system would be used to capture the oil flowing from the well while
relief-well drilling operations are underway.
Given that the proposed rule would remove the arrival timing
requirement for these pieces of equipment, there may be a delay in
their arrival, in comparison to the existing regulations. The amount of
oil flowing from the well during that delayed period, would be the
contributing factor to the proposed rule's forgone benefits. However,
as discussed in the IRIA, the probability of a catastrophic spill event
(as a result of the BOP and SSID systems experiencing total failures)
is low. Coupled with a scenario in which a BOP, SSID, and capping stack
were all to fail, the probability of realizing these forgone benefits
may be even lower. Nonetheless, the possibility exists and if the BOP
were to fail and the SSID were to function as designed, there would be
no forgone benefits in comparison to the existing regulations (and
there might be a gained benefit since the SSID would activate
immediately).
As part of the final rule, BSEE and BOEM are contemplating the
preparation of a sensitivity analysis for the Final RIA and are
soliciting comments on ways to make the analysis as accurate as
possible. The information we receive through public input on this
proposed rule regarding the SSID's performance, reliability, and
effectiveness may inform the preparation of a sensitivity analysis.
The timeframe of the present analysis is 24 years, composed of an
initial 4 years with no activity followed by 20 years of activities
beginning in 2024. The two tables below summarize BSEE's and BOEM's
estimates of the total and annual net benefits derived from all
proposed revisions and additions. Additional information on the time
horizon, compliance costs, savings, benefits, and forgone benefits may
be found in the IRIA published in the rule docket.
20-Year Estimated Annualized Net Benefits Associated With Proposed
Amendments to 30 CFR Part 250 Subparts A, C, D, and G, and 30 CFR Part
550, Subpart B Under Full-Arctic Baseline Assumptions
------------------------------------------------------------------------
Discounted to Discounted to
Year (2024-2043) 2019 at 3% 2019 at 7%
------------------------------------------------------------------------
Annualized (millions)................... $149.8 $142.2
------------------------------------------------------------------------
20-Year Estimated Annualized Net Benefits Associated With Proposed
Amendments to 30 CFR Part 250 Subparts A, C, D, and G, and 30 CFR Part
550, Subpart B Under Restricted Beaufort Baseline Assumptions
------------------------------------------------------------------------
Discounted to Discounted to
Year (2024-2043) 2019 at 3% 2019 at 7%
------------------------------------------------------------------------
Annualized (millions)................... $126.0 $120.9
------------------------------------------------------------------------
This proposed rule would revise multiple provisions in the current
regulations to implement performance-based provisions based upon
reasonably obtainable information on safety, technical, economic, and
other issues. Redundant or unnecessary reporting requirements are also
being eliminated. BSEE and BOEM are providing industry flexibility,
when practical, to meet the safety or equipment standards, rather than
specifying the compliance method. Based on a consideration of the
qualitative and quantitative safety and environmental factors related
to the rule, BSEE and BOEM determined that the proposed revisions would
be consistent with the policies of the applicable E.O.s and the OCSLA.
Executive Order 13563 reaffirms the principles of E.O. 12866 while
calling for improvements in the Nation's regulatory system to promote
predictability, to reduce uncertainty,
[[Page 79307]]
and to use the best, most innovative, and least burdensome tools for
achieving regulatory ends. The E.O. directs agencies to consider
regulatory approaches that reduce burdens and maintain flexibility and
freedom of choice for the public where these approaches are relevant,
feasible, and consistent with regulatory objectives. E.O. 13563
emphasizes that regulations must be based on the best available science
and that the rulemaking process must allow for public participation and
an open exchange of ideas. Furthermore, it promotes retrospective
review of existing regulations that may be outmoded, ineffective,
insufficient, or excessively burdensome. BSEE and BOEM have reviewed
the existing regulations as amended by the 2016 Rule and have developed
this proposed rule in a manner consistent with E.O. 13563.
Executive Order 13771 requires Federal agencies to take proactive
measures to reduce the costs associated with complying with Federal
regulations. This proposed rule is an E.O. 13771 deregulatory action.
B. Regulatory Flexibility Act and Small Business Regulatory Enforcement
Fairness Act
The Regulatory Flexibility Act (RFA), 5 U.S.C. 601-612, requires
agencies to analyze the economic impact of regulations when there is
likely to be a significant economic impact on a substantial number of
small entities and to consider regulatory alternatives that will
achieve the agency's goals while minimizing the burden on small
entities. The proposed rule would affect operators and Federal oil and
gas lessees that could conduct exploratory drilling on the Arctic OCS.
The RFA defines small entities as small businesses, small nonprofits,
and small governmental jurisdictions. No small nonprofits or small
governmental jurisdictions have been identified that would be impacted
by this rule.
Businesses subject to this proposed rule fall under North American
Industry Classification System (NAICS) codes 211111 (Crude Petroleum
and Natural Gas Extraction) and 213111 (Drilling Oil and Gas Wells).
For these classifications, a small business is defined as one with
fewer than 1,250 employees (NAICS code 211111) and fewer than 1,000
employees (NAICS code 213111), respectively. A small entity is one that
is ``independently owned and operated and which is not dominant in its
field of operation.''
According to BOEM's list of Arctic OCS leaseholders, four
businesses currently hold lease interests on the Arctic OCS. This
proposed rule would directly affect all four Arctic lessees. Based on
the small entity criterion, none of the four businesses are considered
a small entity. No small companies hold leases on the Arctic OCS.
Previously, a single small company with only one lease held acreage on
the Arctic OCS. This company relinquished its lease in March 2016.
BSEE and BOEM prepared an Initial Regulatory Flexibility Analysis
(IRFA), which can be found in Section VII of the IRIA. Given the
challenging environment and associated costs of drilling in the Arctic
OCS planning areas, no small entities are expected to operate in these
areas for the foreseeable future. Therefore, BSEE and BOEM
preliminarily conclude that no small entities would be affected by
these proposed amendments, however the agency has prepared an IRFA and
is seeking public comment on any small business impacts from the
proposed amendments.
This proposed rule would meet the E.O. 12866 criteria for an
economically significant rule because it would likely have an annual
effect on the economy of $100 million or more in at least one year of
the 20-year period analyzed, and BSEE/BOEM comply with the RFA and the
Small Business Regulatory Enforcement Fairness Act by providing a
regulatory flexibility analysis. The requirements would apply to all
entities operating on the Arctic OCS regardless of company designation
as a small business. For more information on the small business
impacts, see the IRFA section in the IRIA. Small businesses may send
comments on the actions of Federal employees who enforce, or otherwise
determine compliance with, Federal regulations to the Small Business
and Agriculture Regulatory Enforcement Ombudsman, and to the Regional
Small Business Regulatory Fairness Board. The Ombudsman evaluates these
actions annually and rates each agency's responsiveness to small
business. If you wish to comment on actions by employees of BSEE or
BOEM, call 1-888-REG-FAIR (1-888-734-3247).
C. Unfunded Mandates Reform Act of 1995 (UMRA)
This proposed rule would not impose an unfunded Federal mandate on
State, local, or tribal governments and would not have a significant or
unique effect on State, local, or tribal governments. The requirements
in this proposed rule would apply to Arctic OCS oil and gas lessees and
operators, not to State, local, and tribal governments. Thus, the
proposed rule would not have disproportionate budgetary effects on
these governments. BSEE and BOEM have determined the proposed changes
in this rulemaking would result in cost savings annually to regulated
entities. Therefore, a written statement under the Unfunded Mandates
Reform Act (2 U.S.C. 1531 et seq.) is not required.
D. Takings Implication Assessment
Under the criteria in E.O. 12630, this proposed rule would not have
significant takings implications. The proposed rule is not a
governmental action capable of interference with constitutionally
protected property rights. A Takings Implication Assessment is not
required.
E. Federalism (E.O. 13132)
Under the criteria in E.O. 13132, this proposed rule would not have
federalism implications. This proposed rule would not substantially and
directly affect the relationship between the Federal and State
Governments. To the extent that State and local governments have a role
in OCS activities, this proposed rule would not affect that role. A
Federalism Assessment is not required.
F. Civil Justice Reform (E.O. 12988)
This proposed rule complies with the requirements of E.O. 12988.
Specifically, this rule:
1. Meets the criteria of section 3(a) requiring that all
regulations be reviewed to eliminate errors and ambiguity and be
written to minimize litigation; and
2. Meets the criteria of section 3(b)(2) requiring that all
regulations be written in clear language and contain clear legal
standards.
G. Consultation With Indian Tribes (E.O. 13175)
Under the criteria in E.O. 13175, Consultation and Coordination
with Indian Tribal Governments (dated November 6, 2000), DOI's Policy
on Consultation with Indian Tribes and Alaska Native Corporations (512
Departmental Manual 4, dated November 9, 2015), and DOI's Procedures
for Consultation with Indian Tribes (512 Departmental Manual 5, dated
November 9, 2015), we evaluated the subject matter of this rulemaking
and determined that it would have tribal implications for Alaska
Natives. As described earlier, future Arctic OCS exploratory drilling
activities conducted pursuant to this proposed rule could affect Alaska
Natives, particularly their ability to engage in subsistence and
cultural activities. However, as discussed earlier in Section I.
[[Page 79308]]
Background, Subsection E. Partner Engagement in Preparation for This
Proposed Rule, Item 2. Summary of Comments Received, BOEM's
environmental studies program has provided nearly $500 million over the
last 46 years to scientific research on the Alaska OCS, which includes
the Arctic OCS. Since July 2016, BOEM has completed 35 environmental
studies and has 23 ongoing studies that cover the Arctic, totaling
nearly $72 million. While this proposed rule would change how operators
could explore for OCS resources in the Arctic, there are ample
opportunities to permit these activities consistent with ESA, MMPA,
NEPA, and consultation with Alaska Native communities. BOEM's
environmental studies program provides the information that is used to
evaluate the potential environmental effects of leasing OCS lands for
exploration and development and helps ensure BOEM and BSEE have the
best science available for the public, industry, and federal permitting
decisions.
In addition, Alaska Natives may also be beneficiaries of the
proposed rule, to the extent they are partners in any exploratory
activities. There are additional unquantified benefits in situations
where a SSID is available to immediately shut-in a flowing well rather
than waiting for a relief well to be drilled.
BSEE and BOEM are committed to regular and meaningful consultation
and collaboration with Alaska Native Tribes and ANCSA Corporations on
policy decisions that have tribal implications, including, as an
initial step, through complete and consistent implementation of E.O.
13175, together with related orders, directives, and guidance.
Therefore, BSEE and BOEM engaged in Government-to-Government tribal
consultations, Government-to-ANCSA Corporations consultations, and
meetings with municipal leaders (i.e., mayors or their respective
representatives), to discuss the subject matter of the proposed rule
and solicit input in the development of the proposed rule.
On September 20, 2018, BSEE and BOEM began reaching out to leaders
from Alaska Native Tribes, ANCSA Corporations, and municipalities to
determine which partners were interested in having conversations with
BSEE and BOEM about the rulemaking. Consultations entailed meetings in
Alaska, at locations and times convenient to the Alaska Native
communities and corporations, to ensure they can have proper
representation during the meetings. Accordingly, the timing of these
meetings was critical. BSEE and BOEM scheduled the meetings around
important traditional subsistence and cultural activities, such as
whaling, that take place during specific times of the year,
particularly in the early fall. Between November 29, 2018 and January
30, 2019, BSEE and BOEM met with a majority of the tribal entities (23
of 25) originally invited to consult. The following table lists all 25
invited tribal entities, and the dates and locations of the meetings
with the 23 entities.
----------------------------------------------------------------------------------------------------------------
Tribal entity name Type of entity Meeting date Location
----------------------------------------------------------------------------------------------------------------
Native Village of Utqiagvik........ Tribal Government.......... November 29, 2018..... Anchorage.
Native Village of Wainwright....... Tribal Government..........
Olgoonik Native Corporation........ Native Corporation.........
Doyon Limited...................... Native Corporation.........
Arctic Slope Regional Corporation.. Native Corporation......... December 7, 2018......
Native Village of Kotzebue......... Tribal Government.......... December 10, 2018..... Kotzebue.
Northwest Arctic Borough Mayor..... Municipal Government.......
Native Village of Point Hope....... Tribal Government.......... December 11, 2018..... Point Hope.
Tikigaq Native Corporation......... Native Corporation.........
Point Hope Mayor................... Municipal Government.......
Alaska Eskimo Whaling Commission... Non-tribe that consults on December 13, 2018..... Anchorage.
tribe's behalf.
Cully Corporation.................. Native Corporation......... December 14, 2018.....
North Slope Borough Mayor.......... Municipal Government....... December 17, 2018..... Utqiagvik.
City of Utqiagvik Mayor............ Municipal Government.......
Native Village of Nuiqsut.......... Tribal Government.......... December 18, 2018..... Nuiqsut.
Kuukpik Corporation................ Native Corporation.........
Nuiqsut Mayor...................... Municipal Government.......
Inupiat Community of the Arctic Non-tribe that consults on
Slope. tribe's behalf.
Native Village of Kaktovik......... Tribal Government.......... December 19, 2018..... Kaktovik.
Kaktovik Inupiat Corporation....... Native Corporation.........
Kaktovik Mayor..................... Municipal Government.......
Tanana Chiefs Conference........... Tribal Government.......... December 20, 2018..... Fairbanks.
Native Village of Point Lay........ Tribal Government.......... January 30, 2019...... Conference Call.
-----------------------------------------------
Kikiktagruk Corporation............ Native Corporation......... BSEE and BOEM made multiple attempts to
contact these corporations. However, the
bureaus did not receive a response from
either organization.
-----------------------------------------------
NANA Regional Corporation.......... Native Corporation.........
----------------------------------------------------------------------------------------------------------------
All Alaska Native input provided during the meetings was
subsequently provided to DOI in writing and has been included in the
administrative record for this proposed rule.
As previously discussed in part E of the background section in this
preamble, BSEE and BOEM heard a variety of perspectives during their
meetings with Alaska Natives. The most common comment received was a
concern over food security. Subsistence resources, including bowhead
and beluga whales, other marine mammals, fish, and birds, are a key
food source for many people's diets in the native villages. Another
common comment recommended inclusion of a requirement for an oil and
gas operator to establish an agreement with those whaling communities
potentially affected by a planned drilling project. Certain tribal
representatives and most ANCSA corporations were supportive of this
proposed rulemaking because it could help attract more economic
opportunities to their villages. Other comments provided during the
consultation meetings included a recommendation to provide broader
[[Page 79309]]
outreach by presenting this rulemaking to the tribal assemblies and to
citizens within the communities. One of the ANCSA corporations also
recommended that this rulemaking take into account the NPC 2019 Report.
Please refer to the discussions above in Part E (Partner Engagement in
Preparation for This Proposed Rule) of the background section of this
preamble for a description of how BSEE and BOEM are addressing this
input during the rulemaking process. BSEE and BOEM intend to continue
consultation with affected tribes and ANCSA Corporations following
publication of this proposed rule.
H. Effects on Environmental Justice for Minority and Low-Income
Populations (E.O. 12898)
E.O. 12898 requires Federal agencies to make achieving
environmental justice part of their mission by identifying and
addressing disproportionately high and adverse human health or
environmental effects of their programs, policies, and activities on
minority and low-income populations. DOI has determined that this
proposed rule would not have a disproportionately high or adverse human
health or environmental effect on native, minority, or low-income
communities because its provisions are designed to maintain
environmental protection and minimize any impact of exploration
drilling on subsistence activities and Alaska Native community
resources and infrastructure.
I. Paperwork Reduction Act (PRA)
This proposed rule contains existing and new information collection
(IC) requirements for both BSEE and BOEM regulations, and a submission
to OMB for review under the Paperwork Reduction Act of 1995 (44 U.S.C.
3501 et seq.) is required. Therefore, each bureau will submit an IC
request to OMB for review and approval. We may not conduct, or sponsor,
and you are not required to respond to a collection of information
unless it displays a currently valid OMB control number. OMB has
previously reviewed and approved the existing information collection
requirements associated with Outer Continental Shelf drilling permits,
plans, and related information collection, which would be altered by
this proposed rule. OMB has assigned the following OMB control numbers
to the current ICs:
1014-0025 (BSEE), 30 CFR part 250, Applications for Permit
to Drill (APD and revised APD) (expires 06/30/2023), and in accordance
with 5 CFR 1320.10, an agency may continue to conduct or sponsor this
collection of information while the renewal submission is pending at
OMB.
1010-0151 (BOEM), 30 CFR part 550, subpart B Plans and
Information (exp. 06/30/2021), and in accordance with 5 CFR 1320.10, an
agency may continue to conduct or sponsor this collection of
information while the renewal submission is pending at OMB.
The IC aspects affecting each bureau are discussed separately.
Additionally, BOEM is seeking to renew these information collections
for three years with this rulemaking. Instructions on how to comment
follow those discussions.
The following table details proposed changes to the annual
estimated hour burdens and non-hour costs; as well as associated wage
cost changes for both BSEE and BOEM information submission activities
described below:
BSEE
--------------------------------------------------------------------------------------------------------------------------------------------------------
Existing regulations Proposed rule Total changes
---------------------------------------------------------------------------------------------
Requirement Number of Number of Number of Number of Change of Change of Changes in
responses burden hours responses burden hours responses burden hours wage cost
--------------------------------------------------------------------------------------------------------------------------------------------------------
Submit signed SSID and Well Design certification Sec. 0 0 2 6 +2 +6 +$848
250.470(h)...............................................
Submit request to delay access to your SCCE--Sec. 0 0 2 2 +2 +2 +$286
250.471(a) and Sec. 250.472(b).........................
--------------------------------------------------------------------------------------------------------------------------------------------------------
There are no changes to non-hour costs for BSEE requirements.
BOEM
--------------------------------------------------------------------------------------------------------------------------------------------------------
Existing regulations Proposed rule Total changes
---------------------------------------------------------------------------------------------
Requirement Number of Number of Number of Number of Change of Change of Changes in
responses burden hours responses burden hours responses burden hours wage cost
--------------------------------------------------------------------------------------------------------------------------------------------------------
Submit IOP, including all required information Sec. 1 2,880 0 0 (1) (2,880) ($316,800)
550.204..................................................
Submit required Arctic-specific information with EP Sec. 1 350 1 400 ........... +50 +5,500
550.220..................................................
--------------------------------------------------------------------------------------------------------------------------------------------------------
There are no changes to non-hour costs for BOEM requirements.
BSEE Information Collection--30 CFR Part 250
The proposed regulations would establish new and/or revise current
requirements and the submission of information for safe and
environmentally responsible Arctic OCS oil and gas exploration in an
APD. BSEE would use the information in our efforts to protect life and
the environment, conserve natural resources, and prevent waste.
The following provides a breakdown of the paperwork and non-hour
cost burdens for this proposed rule. For the current requirements
retained in the proposed rule, we used OMB's approved estimated hour
and non-hour cost burdens.
As discussed in the Preamble Section-by-Section above, and in the
supporting statement available at RegInfo.gov, this proposed rule would
modify language in Sec. Sec. 250.175(d), 250.300(b),
[[Page 79310]]
250.470(f)(3), and 250.720(c)(2); however, there would be no change in
hour burden or non-hour costs associated with these revisions.
In Sec. 250.470(h), we would add a requirement to submit with an
APD a certification signed by a registered professional engineer that
your SSID and well design (including casing and cementing program) meet
the design requirements in Sec. 250.472 (+ 2 responses and 6 hours for
PE Certification).
In Sec. Sec. 250.471(a) and 250.472(b), we would add a requirement
for operators to submit, with an APD, documentation demonstrating that
having access to SCCE and the relief rig can be safely delayed until
the last casing point prior to penetrating a zone capable of flowing
hydrocarbons in measurable quantities. BSEE will grant this approval if
the operator adequately demonstrates to the Bureau that it will not
encounter any abnormally high-pressured zones or other geological
hazards before that casing point (+ 2 responses and 2 hours per
request).
Because not all APDs submitted to BSEE would involve Arctic OCS
exploration drilling, we are separating the Arctic-specific
requirements and burdens from the national APD requirements. The burden
table below outlines the revised requirements and burdens associated
with this proposed rulemaking.
Title of Collection: Revisions to the Requirements for Exploratory
Drilling on the Arctic Outer Continental Shelf--Application for Permit
to Drill (APD, Revised APD).
OMB Control Number: 1014-0025.
Form Number: BSEE-0123 (APD) and BSEE-0123S (Supplemental APD).
Type of Review: Revision of a currently approved collection.
Respondents/Affected Public: Potential respondents comprise Federal
OCS oil, gas, and sulfur lessees/operators and holders of pipeline
rights-of-way.
Total Estimated Number of Annual Respondents: Currently there are
approximately 60 Oil and Gas Drilling and Production Operators in the
OCS. Not all the potential respondents would submit information at any
given time, and some may submit multiple times.
Total Estimated Number of Annual Responses: 11,331.
Estimated Completion Time per Response: Varies from 1 hour to 2,800
hours depending on activity.
Total Estimated Number of Annual Burden Hours: 77,945.
Respondent's Obligation: Most responses are mandatory, while others
are required to obtain or retain benefits.
Frequency of Collection: Generally, on occasion and as required in
the regulations.
Total Estimated Annual Nonhour Burden Cost: $4,400,470.
Burden Table
[Changes due to the proposed rule shown in bold]
----------------------------------------------------------------------------------------------------------------
Reporting or Annual burden
Citation 30 CFR 250; application for recordkeeping Hour burden Average number hours
permit to drill (APD) requirement * of responses (rounded)
----------------------------------------------------------------------------------------------------------------
Non-hour cost burden
----------------------------------------------------------------------------------------------------------------
Subparts A, C, D, E, G, H, P........... Apply for permit to 1 190 applications 190
drill, sidetrack,
bypass, or deepen a
well submitted via
Forms BSEE-0123
(APD) and BSEE-0123S
(Supplemental APD).
(This burden
represents only the
filling out of the
forms, the
requirements are
listed separately
below.).
---------------------------------
$2,113 fee x 190 = $401,470
----------------------------------------------------------------------------------------------------------------
Subparts D, E, G....................... Obtain approval to 1 730 submittals.. 730
revise your drilling
plan or change major
drilling equipment
by submitting a
Revised APD and
Supplemental APD [no
cost recovery fee
for Revised APDs].
(This burden
represents only the
filling out of the
forms, the
requirements are
listed separately
below.).
----------------------------------------------------------------------------------------------------------------
Subtotal.................................................................. 920 responses... 920
----------------------------------------------------------------------------------------------------------------
$401,470 non-hour cost burdens
----------------------------------------------------------------------------------------------------------------
Subpart A
----------------------------------------------------------------------------------------------------------------
125.................................... Submit evidence of Exempt under 5 CFR 1320.3(h)(1) 0
your fee for
services receipt.
----------------------------------------------------------------------------------------------------------------
197.................................... Written Exempt under 5 CFR 1320.5(d)(2) 0
confidentiality
agreement.
----------------------------------------------------------------------------------------------------------------
Subpart C
----------------------------------------------------------------------------------------------------------------
300(b)(1), (2)......................... Obtain approval to 150 1 request....... 150
add petroleum-based
substance to
drilling mud system
or approval for
method of disposal
of drill cuttings,
sand, & other well
solids, including
those containing
Naturally Occurring
Radioactive Material
(NORM).
----------------------------------------------------------------------------------------------------------------
Subpart C subtotal........................................................ 1 response...... 150
----------------------------------------------------------------------------------------------------------------
[[Page 79311]]
Subpart D
----------------------------------------------------------------------------------------------------------------
408; 414(h)............................ Request approval of Burden covered under subpart A, 0
alternate procedures 1014-0022
or equipment during
drilling operations.
----------------------------------------------------------------------------------------------------------------
409.................................... Request departure 1 370 approvals... 370
approval from the
drilling
requirements
specified in this
subpart; identify
and discuss.
----------------------------------------------------------------------------------------------------------------
410(b); 417(b); 713.................... Reference well and 8 1 submittal..... 8
site-specific
information in case
it is not approved
in your Exploration
Plan, Development
and Production Plan,
Development
Operations
Coordination
Document. Burdens
pertaining to EPs,
DPPs, DOCDs are
covered under BOEM
1010-0151.
----------------------------------------------------------------------------------------------------------------
410(d)................................. Submit to the 0.5 380 submittals.. 190
District Manager: An R-0.5 380 submittals.. 190
original and two
complete copies of
APD and Supplemental
APD; separate public
information copy of
forms per Sec.
250.186.
----------------------------------------------------------------------------------------------------------------
411; 412............................... Submit plat showing 2 380 submittals.. 760
location of the
proposed well and
all the plat
requirements
associated with this
section.
----------------------------------------------------------------------------------------------------------------
411; 413; 414; 415; 420................ Submit design 15 707 submittals.. 10,605
criteria used and
all description
requirements;
drilling prognosis
with description of
the procedures you
will follow; and
casing and cementing
program requirements.
----------------------------------------------------------------------------------------------------------------
411; 416; 731.......................... Submit diverter and 11 380 submittals.. 4,180
BOP systems
descriptions and all
the regulatory
requirements
associated with this
section.
----------------------------------------------------------------------------------------------------------------
411; 713............................... Provide information 10 682 submittals.. 6,820
for using a MODU and
all the regulatory
requirements
associated with this
section.
----------------------------------------------------------------------------------------------------------------
411; 418............................... Additional 20 380 submittals.. 7,600
information required
when providing an
APD include, but not
limited to, rated
capacities of
drilling rig and
equipment if not
already on file;
drilling fluids
program, including
weight materials;
directional plot;
H2S contingency
plan; welding plan;
and information we
may require per
requirements, etc.
----------------------------------------------------------------------------------------------------------------
414(c)................................. Request preapproval 1 15 requests..... 15
to use alternative
equivalent downhole
mud weight prior to
submitting APD.
----------------------------------------------------------------------------------------------------------------
420(a)(7).............................. Include signed 3 1,034 3,102
registered certifications.
professional
engineer
certification and
related information.
----------------------------------------------------------------------------------------------------------------
423(c)................................. Submit for approval 3 527 procedures & 1,581
casing pressure test criteria.
procedures and
criteria. On casing
seal assembly ensure
proper installation
of casing or liner
(subsea BOP's only).
----------------------------------------------------------------------------------------------------------------
428(b)................................. Submit to District 125 1 submittal..... 125
Manager for approval
revised casing
setting depths or
hole interval
drilling depth;
include
certification by PE.
----------------------------------------------------------------------------------------------------------------
428(k)................................. Submit a description 125 1 submittal..... 125
of the plan to use a
valve(s) on the
drive pipe during
cementing operations
for the conductor
casing, surface
casing, or liner.
----------------------------------------------------------------------------------------------------------------
[[Page 79312]]
432.................................... Request departure 8 53 requests..... 424
from diverter
requirements; with
discussion and
receive approval.
----------------------------------------------------------------------------------------------------------------
460(a)................................. Include your 17 2 plans......... 34
projected plans if
well testing along
with the required
information.
----------------------------------------------------------------------------------------------------------------
462(c)................................. Submit a description 125 1 submittal..... 125
of your source
control and
containment
capabilities to the
Regional Supervisor
and receive
approval; all
required information.
----------------------------------------------------------------------------------------------------------------
470(h)................................. Submit certification 3 2 certs......... 6
signed by PE that
SSID and well design
meet requirements of
Sec. 250.472.
(Alaska only).
----------------------------------------------------------------------------------------------------------------
471(a); 472(b)......................... Submit, to Regional 1 2 requests...... 2
Supervisor, a
request to delay
access to your SCCE
and relief rig, if
applicable,
including adequate
documentation (such
as, but not limited
to, risk modeling
data, off-set well
data, analog data,
seismic data).
Demonstrate you will
not encounter any
abnormally high-
pressured zones or
other geologic
hazards. (Alaska
only).
----------------------------------------------------------------------------------------------------------------
490(c)................................. Request to classify 3 91 requests..... 273
an area for the
presence of H2S.
------------------------------------------------------------------------
Support request with 3 73 submittals... 219
available
information such as
G&G data, well logs,
formation tests,
cores and analysis
of formation fluids.
------------------------------------------------------------------------
Submit a request for 1 4 requests...... 4
reclassification of
a zone when a
different
classification is
needed.
----------------------------------------------------------------------------------------------------------------
Alaska Region: 410; 412 thru 418; 420; Due to the 2,800 1 request....... 2,800
442; 444; 449; 456; 470; 471; 472. difficulties of
drilling in Alaska,
along with the
shortened time
window allowed for
drilling, Alaska
hours are done here
as stand-alone
requirements. Also,
note that these
specific hours are
based on the first
APD in Alaska in
more than 10 years.
----------------------------------------------------------------------------------------------------------------
Subpart D subtotal........................................................ 5,467 responses. 39,558
----------------------------------------------------------------------------------------------------------------
Subpart E
----------------------------------------------------------------------------------------------------------------
513.................................... Obtain written 3 288 requests.... 864
approval to begin R-3 1 request....... 3
well completion
operations. If
completion is
planned and the data
are available you
may submit on forms.
------------------------------------------------------------------------
Submit description of 18.5 295 submittals.. 5,458
well-completion, R-26 1 submittal..... 26
schematics, logs,
any H2S..
----------------------------------------------------------------------------------------------------------------
Subpart E subtotal........................................................ 585 responses... 6,351
----------------------------------------------------------------------------------------------------------------
Subpart G
----------------------------------------------------------------------------------------------------------------
701; 720............................... Identify and discuss Burden covered under subpart A, 0
your proposed 1014-0022
alternate procedures
or equipment.
----------------------------------------------------------------------------------------------------------------
702.................................... Identify and discuss Burden covered under subpart A, 0
departure requests.. 1014-0022
----------------------------------------------------------------------------------------------------------------
713(b)................................. Submit plat of the 125 1 submittal..... 125
rig's anchor pattern
for a moored rig
approved in your EP,
DPP, or DOCD.
----------------------------------------------------------------------------------------------------------------
[[Page 79313]]
713(e)................................. Provide contingency 10 682 submittals.. 6,820
plan for using
dynamically
positioned MODU and
all the regulatory
requirements
associated with this
section.
----------------------------------------------------------------------------------------------------------------
713(g)................................. Describe specific 45 1 submittal..... 45
current speeds when
implementing rig
shutdown and/or move-
off procedures for
water depths > 400
meters; discussion
of specific measures
you will take to
curtail rig
operations/move-off
location.
----------------------------------------------------------------------------------------------------------------
720(b)................................. Request approval to 5 518 approval 2,590
displace kill-weight requests.
fluid; include
reasons why along
with step-by-step
procedures.
----------------------------------------------------------------------------------------------------------------
721(g)(4).............................. Submit test 2.5 R-4 355 submittals, 8,884
procedures and 1 change.
criteria for a
successful negative
pressure test for
approval. If any
change, submit
changes for approval.
----------------------------------------------------------------------------------------------------------------
731.................................... Submit complete 114 129 submittals.. 14,706
description of BOP
system and
components;
schematic drawings;
certification by ITP
(additional I3P if
BOP is subsea, in
HPHT, or surface on
floating facility);
autoshear, deadman,
EDS systems.
-------------------------------------------------
$31,000 x 129 submittal = $3,999,000
----------------------------------------------------------------------------------------------------------------
733(b)................................. Describe annulus 67 1 submittal..... 67
monitoring plan; and
how the well will be
secured if leak is
detected.
----------------------------------------------------------------------------------------------------------------
734(b)................................. Submit verification R-64 1 report........ 64
report from ITP
documenting repairs
and that BOP is fit
for service.
----------------------------------------------------------------------------------------------------------------
734(c)................................. Submit revision, R-66 1 submittal..... 66
including all
verifications
required, before
drilling out surface
casing.
----------------------------------------------------------------------------------------------------------------
737(a)................................. Request approval from 1 358 casing/liner 358
District Manager to info.
omit BOP pressure
test. Indicate which
casing strings and
liners meet the
criteria for this
request.
----------------------------------------------------------------------------------------------------------------
737(b)(2).............................. Request approval of 2 353 requests.... 706
test pressures (RAM
BOPs).
----------------------------------------------------------------------------------------------------------------
737(b)(3).............................. Request approval of 2 380 requests.... 760
pressure test
(annular BOPs).
----------------------------------------------------------------------------------------------------------------
737(d)(2).............................. Submit test 2.5 507 submittals.. 1,268
procedures for
approval for surface
BOP.
----------------------------------------------------------------------------------------------------------------
737(d)(3); (d)(4)...................... Submit test 2 507 submittals.. 1,014
procedures,
including how you
will test each ROV
intervention
function, for
approval (subsea
BOPs only).
----------------------------------------------------------------------------------------------------------------
737(d)(12)............................. Submit test 2.5 507 submittals.. 1,268
procedures
(autoshear and
deadman systems) for
approval. Include
documentation of the
controls/circuitry
system used for each
test; describe how
the ROV will be
utilized during this
operation.
----------------------------------------------------------------------------------------------------------------
738(b)................................. Submit a revised .5 50 submittals... 25
permit with a
written statement
from an independent
third party
documenting the
repairs,
replacement, or
reconfiguration and
certifying that the
previous
certification in
Sec. 250.731(c)
remains valid.
----------------------------------------------------------------------------------------------------------------
738(m)................................. Request approval to 66 1 request....... 66
use additional well
control equipment,
including BAVO
report; as well as
other information
required by District
Manager.
----------------------------------------------------------------------------------------------------------------
[[Page 79314]]
738(n)................................. Submit which pipe/ 64 1 submittal..... 64
variable bore rams
have no current
utility or well
control purposes.
----------------------------------------------------------------------------------------------------------------
Subpart G subtotal........................................................ 4,177 response.. 16,396
----------------------------------------------------------------------------------------------------------------
Subpart H
----------------------------------------------------------------------------------------------------------------
807(a)................................. Submit detailed 13 1 submittal..... 13
information that
demonstrates the
SSSVs and related
equipment are
capable of
performing in HPHT.
----------------------------------------------------------------------------------------------------------------
Subpart H subtotal........................................................ 1 response...... 13
----------------------------------------------------------------------------------------------------------------
Subpart P
----------------------------------------------------------------------------------------------------------------
Note that for Sulfur Operations, while there may be 49 burden hours listed, we have not had any sulfur leases
for numerous years, therefore, we have submitted minimal burden..
----------------------------------------------------------------------------------------------------------------
1605(b)(3)............................. Submit information on 6 1 submittal..... 6
the fitness of the
drilling unit.
----------------------------------------------------------------------------------------------------------------
1617................................... Submit fully 40 1 submittal..... 40
completed
application (Form
BSEE-0123) include
rated capacities of
the proposed
drilling unit and of
major drilling
equipment; as well
as all required
information listed
in this section.
----------------------------------------------------------------------------------------------------------------
1622(b)................................ Submit description of 3 1 submittal..... 3
well-completion or
workover procedures,
schematic, and if
H2S is present.
----------------------------------------------------------------------------------------------------------------
Subpart P subtotal........................................................ 3 responses..... 49
----------------------------------------------------------------------------------------------------------------
Total Burden for APD.................................................. 11,331 Responses 77,945
------------------------------------------------------------------------
$4,400,470 Non Hour Cost Burden
----------------------------------------------------------------------------------------------------------------
* In the future, BSEE may require electronic filing of some submissions.
In addition, the PRA requires agencies to estimate the total annual
reporting and recordkeeping non-hour cost burden resulting from the
collection of information, and we solicit your comments on this item.
For reporting and recordkeeping only, your response should split the
cost estimate into two components: (1) Total capital and startup cost
component and (2) annual operation, maintenance, and purchase of
service component. Your estimates should consider the cost to generate,
maintain, and disclose or provide the information. You should describe
the methods you use to estimate major cost factors, including system
and technology acquisition, expected useful life of capital equipment,
discount rate(s), and the period over which you incur costs. Generally,
your estimates should not include equipment or services purchased: (1)
Before October 1, 1995; (2) to comply with requirements not associated
with the information collection; (3) for reasons other than to provide
information or keep records for the Government; or (4) as part of
customary and usual business or private practices.
As part of our continuing effort to reduce paperwork and respondent
burdens, we invite the public and other Federal agencies to comment on
any aspect of this information collection, including:
(1) Whether the collection of information is necessary, including
whether the information will have practical utility;
(2) The accuracy of our estimate of the burden for this collection
of information;
(3) Ways to enhance the quality, utility, and clarity of the
information to be collected; and
(4) Ways to minimize the burden of the collection of information on
respondents.
Send your comments and suggestions on this information collection
by the date indicated in the DATES section to the Desk Officer for the
Department of the Interior at OMB-OIRA at (202) 395-5806 (fax) or via
the RegInfo.gov portal (online). You may view the information
collection request(s) at http://www.reginfo.gov/public/do/PRAMain.
Please provide a copy of your comments to the BSEE Information
Collection Clearance Officer (see the ADDRESSES section). You may
contact Kye Mason, BSEE Information Collection Clearance Officer at
(703) 787-1607 with any questions. Please reference Revisions to the
Requirements for Exploratory Drilling on the Arctic Outer Continental
Shelf (OMB Control No. 1014-0025), in your comments.
BOEM Information Collection--30 CFR Part 550
This proposed rule would add and remove requirements related to
submitting exploration plans and other information before conducting
oil and gas exploration drilling activities on the Arctic OCS. If final
regulations become effective, the information collection burdens for
this rulemaking would be
[[Page 79315]]
consolidated into the existing collection for Subpart B, Control Number
1010-0151, and will be adjusted as necessary. BOEM is requesting OMB
approve the modified collections of information for OMB Control Number
1010-0151 with the final rule publication.
Pertaining to this proposed rulemaking, BOEM would collect the
information to ensure that planned operations will be safe; will not
adversely affect the marine, coastal, or human environments; will
respond to the special conditions on the Arctic OCS; and will conserve
the resources of the Arctic OCS. BOEM would use the information to
ensure, through advanced planning, that operators are capable of safely
operating in the unique environmental conditions of the Arctic and to
make informed decisions on whether to approve EPs as submitted or
whether modifications are necessary.
BOEM proposes to remove the Integrated Operations Plan (IOP)
regulations by deleting Sec. 550.204 and removing the corresponding
references to the IOP from Sec. Sec. 550.200 and 550.206. BOEM's
existing requirement to submit the IOP at least 90 days before the
lessee or operator files an EP would be eliminated. The data and
information requested in the IOP is largely unnecessary in light of the
information already collected in the EP. The current approval for OMB
Control Number 1010-0151 counts the similar burdens associated with
IOPs and EPs in both. Therefore, BOEM would remove the burdens
attributed to the IOPs, and keep the burdens attributed to EPs.
Removing the IOP provision would decrease the annual burden hours by 1
response and 2,880 hours (- 1 response and 2,880 annual burden hours).
The proposed rule would add a requirement to Sec. 550.211(b) to
describe operational safety procedures that the operator has developed
specific to conditions relevant on the Arctic OCS in the EP. These
requirements were previously included in the IOP requirements that are
removed from this rulemaking. Retaining this provision would lessen the
2,880-burden hour decrease by 50 annual burden hours (i.e., by
retaining 50 annual burden hours).
BOEM proposes to revise Sec. 550.220(c)(1) to require a
description of how exploratory drilling will be designed and conducted,
including how all vessels and equipment will be designed, built, and/or
modified, to account for Arctic OCS conditions and how such activities
will be managed and overseen as an integrated endeavor, and in the
description of vessel modifications, a description of any approvals
from the flag state and the vessel classification society, including
any allowances or limitations placed upon the vessel by the
classification society and/or the USCG. Vessel modifications may
include the suitability of vessels for Arctic conditions. These vessels
may have or acquire classification from a ``recognized organization''
under the USCG's Alternative Compliance Program (ACP).\54\ BOEM is
seeking to confirm that the operator meets the requirements of other
entities with authority over vessels, not to impose requirements on
those vessels. BOEM believes that this change would not impose any
material additional burdens on the lessees or operators. BOEM is also
proposing to revise Sec. 550.220(c)(4) and (6) by requiring the
operator to provide a general description of how they will comply with
Sec. 250.472, including a description of the termination of their
operations.
---------------------------------------------------------------------------
\54\ 33 U.S.C. 3316 and 46 CFR part 8 implement the USCG's ACP.
---------------------------------------------------------------------------
BOEM estimates that the proposed revisions would remove 2,880
annual burden hours that correlate to the removal of the existing IOP
requirement. These changes would result in a net decrease of 2,830
annual burden hours.
Because not all EPs submitted to BOEM would involve Arctic OCS
exploration drilling, we are separating the burden associated with the
Arctic-specific requirements and burdens from the national EP
requirements. The burden table that follows this paragraph outlines the
revised requirements and burdens associated with this rulemaking. BOEM
has not identified any non-hour cost burdens associated with these
proposed requirements.
Title of Collection: Revisions to the Requirements for Exploratory
Drilling on the Arctic Outer Continental Shelf--30 CFR part 550,
subpart B, Plans and Information.
OMB Control Number: 1010-0151.
Form Number:
BOEM-0137, OCS Plan Information Form
BOEM-0138, EP Air Quality Screening Checklist
BOEM-0139, DOCD/DPP Air Quality Screening Checklist.
BOEM-0141, ROV Survey Report.
BOEM-0142, Environmental Impact Analysis Worksheet.
Type of Review: Revision of a currently approved collection.
Respondents/Affected Public: Respondents are Federal oil and gas or
sulfur lessees or operators.
Total Estimated Number of Annual Response: 4,265 respondents.
Total Estimated Number of Annual Burden Hours: 433,608 hours.
Respondent's Obligation: Some responses to the information
collection are required to obtain or retain a benefit, and some are
mandatory.
Frequency of Collection: The frequency of the response varies, but
primarily responses are required only on occasion.
Total Estimated Annual Nonhour Burden Cost: $3,939,435.
Burden Breakdown
[Current requirements in regular font; proposed expanded requirements shown in italic font]
----------------------------------------------------------------------------------------------------------------
Reporting &
Citation 30 CFR 550 subpart B recordkeeping Hour burden Average number of Burden hours
and NTLs requirement annual responses
----------------------------------------------------------------------------------------------------------------
Non-hour costs
----------------------------------------------------------------------------------------------------------------
200 thru 206..................... General requirements for Burden included with specific 0
plans and information; requirements below.
fees/refunds, etc.
----------------------------------------------------------------------------------------------------------------
201 thru 206; 211 thru 228: 241 BOEM posts EPs/DPPs/ Not considered IC as defined in 5 0
thru 262. DOCDs on FDMS and CFR 1320.3(h)(4).
receives public
comments in preparation
of EAs.
----------------------------------------------------------------------------------------------------------------
Subtotal............................................................... 0.................. 0
----------------------------------------------------------------------------------------------------------------
[[Page 79316]]
Ancillary Activities
----------------------------------------------------------------------------------------------------------------
208; NTL 2009-G34 *.............. Notify BOEM in writing, 11 61 notices......... 671
and if required by the
Regional Supervisor
notify other users of
the OCS before
conducting ancillary
activities.
----------------------------------------------------------------------------------------------------------------
208; 210(a)...................... Submit report 2 61 reports......... 122
summarizing & analyzing
data/information
obtained or derived
from ancillary
activities.
----------------------------------------------------------------------------------------------------------------
208; 210(b)...................... Retain ancillary 2 61 records......... 122
activities data/
information; upon
request, submit to BOEM.
----------------------------------------------------------------------------------------------------------------
Subtotal............................................................... 183 responses...... 91
----------------------------------------------------------------------------------------------------------------
Contents of Exploration Plans (EP)
----------------------------------------------------------------------------------------------------------------
209; 231(b); 232(d); 234; 235; Submit new, amended, 150 345 changed plans3. 51,750
281; 283; 284; 285; NTL 2015-N01. modified, revised, or
supplemental EP, or
resubmit disapproved
EP, including required
information; withdraw
an EP.
----------------------------------------------------------------------------------------------------------------
209; 211 thru 228; NTL 2015-N01.. Submit EP and all 600 163................ 97,800
required information
(including, but not
limited to, submissions
required by BOEM Forms
0137, 0138, 0142; lease
stipulations; reports,
including shallow
hazards surveys, H2S,
G&G, archaeological
surveys & reports (Sec.
550.194) ***, in
specified formats.
Provide notifications.
----------------------------------------------------
$3,673 x 163 EP surface locations = $598,699
----------------------------------------------------------------------------------------------------------------
210; 220(a)-(c); 291; 292........ For existing Arctic OCS 700 1.................. 700
exploration activities:
revise and resubmit
Arctic-specific
information, as
required.
----------------------------------------------------------------------------------------------------------------
202; 211; 216; 219, 220(a)-(c); For new Arctic OCS 400 1.................. 400
224, 227;. exploration activities:
submit required Arctic-
specific information
with EP.
----------------------------------------------------------------------------------------------------------------
Subtotal............................................................... 510 responses...... 150,650
------------------------------------------------------------------------------
$598,699 Non-hour costs
----------------------------------------------------------------------------------------------------------------
Review and Decision Process for the EP
----------------------------------------------------------------------------------------------------------------
235(b); 272(b);.................. Appeal State's objection Burden exempt as defined in 5 CFR 0
281(d)(3)(ii).................... 1320.4(a)(2), (c).
----------------------------------------------------------------------------------------------------------------
Contents of Development and Production Plans (DPP) and Development Operations Coordination Documents (DOCD)
----------------------------------------------------------------------------------------------------------------
209; 266(b); 267(d); 272(a); 273; Submit amended, 235 353 changed plans.. 82,955
281; 283; 284; 285; NTL 2015-N01. modified, revised, or
supplemental DPP or
DOCD, including
required information,
or resubmit disapproved
DPP or DOCD.
----------------------------------------------------------------------------------------------------------------
241 thru 262; 209; NTL 2015-N01.. Submit DPP/DOCD and 700 268................ 187,600
required/supporting
information (including,
but not limited to,
submissions required by
BOEM Forms 0137, 0139,
0142; lease
stipulations; reports,
including shallow
hazards surveys,
archaeological surveys
& reports (Sec.
550.194)), in specified
formats. Provide
notification.
----------------------------------------------------------------------------------------------------------------
$4,238 x 268 DPP/DOCD wells = $1,135,784.
----------------------------------------------------------------------------------------------------------------
Subtotal............................................................... 621 responses...... 270,555
------------------------------------------------------------------------------
$1,135,784 Non-hour costs
----------------------------------------------------------------------------------------------------------------
[[Page 79317]]
Review and Decision Process for the DPP or DOCD
----------------------------------------------------------------------------------------------------------------
267(a)........................... Once BOEM deemed DPP/ Not considered IC as defined in 5 0
DOCD submitted; CFR 1320.3(h)(4).
Governor of each
affected State, local
government official;
etc., submit comments/
recommendations.
----------------------------------------------------------------------------------------------------------------
267(b)........................... General public comments/ Not considered IC as defined in 5 0
recommendations CFR 1320.3(h)(4).
submitted to BOEM
regarding DPPs or DOCDs.
----------------------------------------------------------------------------------------------------------------
269(b)........................... For leases or units in 3 1 response......... 3
vicinity of proposed
development and
production activities
RD may require those
lessees and operators
to submit information
on preliminary plans
for their leases and
units.
----------------------------------------------------------------------------------------------------------------
Subtotal............................................................... 1 response......... 3
----------------------------------------------------------------------------------------------------------------
Post-Approval Requirements for the EP, DPP, and DOCD
----------------------------------------------------------------------------------------------------------------
280(b)........................... In an emergency, request Burden included under 1010-0114. 0
departure from your
approved EP, DPP, or
DOCD.
----------------------------------------------------------------------------------------------------------------
281(a)........................... Submit various BSEE Burdens included under appropriate 0
applications for subpart or form (1014-0003; 1014-
approval and submit 0011; 1014-0016; 1014-0018).
permits.
----------------------------------------------------------------------------------------------------------------
282.............................. Retain monitoring data/ 4 150 records........ 600
information; upon
request, make available
to BOEM.
------------------------------------------------------------------------------
Prepare and submit 2 6 plans............ 12
monitoring plan for
approval.
----------------------------------------------------------------------------------------------------------------
282(b)........................... Prepare and submit 3 12 reports......... 36
monitoring reports and
data (including BOEM
Form 0141 used in GOMR).
----------------------------------------------------------------------------------------------------------------
284(a)........................... Submit updated info on 4 56 updates......... 224
activities conducted
under approved EP/DPP/
DOCD.
----------------------------------------------------------------------------------------------------------------
Subtotal............................................................... 224 responses...... 872
----------------------------------------------------------------------------------------------------------------
Submit CIDs
----------------------------------------------------------------------------------------------------------------
296(a); 297...................... Submit CID and required/ 375 14 documents....... 5,250
supporting information;
submit CID for
supplemental DOCD or
DPP.
----------------------------------------------------
$27,348 x 14 = $382,872
----------------------------------------------------------------------------------------------------------------
296(b); 297...................... Submit a revised CID for 100 13 revisions....... 1,300
approval.
----------------------------------------------------------------------------------------------------------------
Subtotal............................................................... 27 responses....... 6,550
------------------------------------------------------------------------------
$382,872 Non-hour costs
----------------------------------------------------------------------------------------------------------------
Seismic Survey Mitigation Measures and Protected Species Observer Program NTL
----------------------------------------------------------------------------------------------------------------
NTL 2016-G02; 211 thru 228; 241 Submit to BOEM observer 1.5 hours 2 sets of material. 3
thru 262. training requirement
materials and
information.
------------------------------------------------------------------------------
Training certification 1 hour 1 new trainee...... 1
and recordkeeping.
------------------------------------------------------------------------------
During seismic 1.5 hours 344 reports........ 516
acquisition operations,
submit daily observer
reports semi-monthly.
------------------------------------------------------------------------------
If used, submit to BOEM 2 hours 6 submittals....... 12
information on any
passive acoustic
monitoring system prior
to placing it in
service.
------------------------------------------------------------------------------
[[Page 79318]]
During seismic 1.5 hours 1,976 reports...... 2,964
acquisition operations,
submit to BOEM marine
mammal observation
report(s) semi-monthly
or within 24 hours if
air gun operations were
shut down.
------------------------------------------------------------------------------
During seismic 1.5 hours 344 reports........ 516
acquisition operations,
when air guns are being
discharged, submit
daily observer reports
semi-monthly.
------------------------------------------------------------------------------
Observation Duty (3 3 observers x 8 hrs x 365 days = 8,760 hours x 4
observers fulfilling an vessels observing = 35,040 man-hours x $52/hr =
8-hour shift each for $1,822,080.
365 calendar days x 4
vessels = 35,040 man-
hours). This
requirement is
contracted out; hence
the non-hour cost
burden.
----------------------------------------------------------------------------------------------------------------
Subtotal............................................................... 2,673 responses.... 4,012
------------------------------------------------------------------------------
$1,822,080 Non-hour costs
----------------------------------------------------------------------------------------------------------------
Vessel Strike Avoidance and Injured/Protected Species Reporting NTL
----------------------------------------------------------------------------------------------------------------
NTL 2016-G01; 211 thru 228; 241 Notify BOEM within 24 1 hour 1 notice........... 1
thru 262. hours of strike, when
your vessel injures/
kills a protected
species (marine mammal/
sea turtle).
----------------------------------------------------------------------------------------------------------------
Subtotal............................................................... 1 response......... 1
----------------------------------------------------------------------------------------------------------------
General Departure
----------------------------------------------------------------------------------------------------------------
200 thru 299..................... General departure and 2 25 requests........ 50
alternative compliance
requests not
specifically covered
elsewhere in Subpart B
regulations.
----------------------------------------------------------------------------------------------------------------
Subtotal............................................................... 25 responses....... 50
----------------------------------------------------------------------------------------------------------------
Total Burden....................................................... 4,265 responses.... 433,608
------------------------------------------------------------------------------
$3,939,435 Non-hour costs
----------------------------------------------------------------------------------------------------------------
* The identification number of NTLs may change when NTLs are reissued periodically to update information.
In addition, the PRA requires agencies to estimate the total annual
reporting and recordkeeping non-hour cost burden resulting from the
collection of information, and we solicit your comments on this item.
For reporting and recordkeeping only, your response should split the
cost estimate into two components: (1) Total capital and startup cost
component and (2) annual operation, maintenance, and purchase of
service component. Your estimates should consider the cost to generate,
maintain, and disclose or provide the information. You should describe
the methods you use to estimate major cost factors, including system
and technology acquisition, expected useful life of capital equipment,
discount rate(s), and the period over which you incur costs. Generally,
your estimates should not include equipment or services purchased: (1)
Before October 1, 1995; (2) to comply with requirements not associated
with the information collection; (3) for reasons other than to provide
information or keep records for the Government; or (4) as part of
customary and usual business or private practices.
As part of our continuing effort to reduce paperwork and respondent
burdens, we invite the public and other Federal agencies to comment on
any aspect of this information collection, including:
(1) Whether the collection of information is necessary, including
whether the information will have practical utility;
(2) The accuracy of our estimate of the burden for this collection
of information;
(3) Ways to enhance the quality, utility, and clarity of the
information to be collected; and
(4) Ways to minimize the burden of the collection of information on
respondents.
Send your comments and suggestions on this information collection
by the date indicated in the DATES section to the Desk Officer for the
Department of the Interior at OMB-OIRA at (202) 395-5806 (fax) or via
the portal at RegInfo.gov (online). You may view the information
collection request(s) at http://www.reginfo.gov/public/do/PRAMain.
Please provide a copy of your comments to the BOEM Information
Collection Clearance Officer (see the ADDRESSES section). You may
contact Anna Atkinson, BOEM Information Collection Clearance Officer at
(703) 787-1025 with any questions. Please reference Revisions to the
Requirements for Exploratory Drilling on the Arctic Outer Continental
Shelf (OMB Control No. 1014-0151), in your comments.
J. National Environmental Policy Act of 1969 (NEPA)
BSEE and BOEM developed a draft Environmental Assessment (EA) to
[[Page 79319]]
determine whether this proposed rule would have a significant impact on
the quality of the human environment under the NEPA. The draft EA is
available for review in conjunction with this proposed rule at
www.regulations.gov (in the Search box, enter BSEE-2019-0008).
K. Data Quality Act
In developing this proposed rule, we did not conduct or use a
study, experiment, or survey requiring peer review under the Data
Quality Act (44 U.S.C. 3516 note).
L. Effects on the Nation's Energy Supply (E.O. 13211)
Although this proposed rule is a significant regulatory action
under E.O. 12866, it is not a significant energy action under the
definition of that term in E.O. 13211 because:
1. It is not likely to have a significant adverse effect on the
supply, distribution or use of energy; and
2. It has not been designated as a significant energy action by the
Administrator of OIRA.
Thus, a Statement of Energy Effects is not required.
While offshore Arctic OCS oil and gas studies indicate the
potential of vast resources, there is currently little exploration
activity and very little production of oil and gas on the Arctic OCS,
largely due to the inherent practical difficulties of exploration and
production in the area. The only existing oil production from the
Arctic OCS is through the Northstar Island facility.
M. Clarity of Regulations
We are required by E.O. 12866, E.O. 12988, and by the Presidential
Memorandum of June 1, 1998, to write all rules in plain language. This
means that each rule we publish must:
1. Be logically organized;
2. Use the active voice to address readers directly;
3. Use clear language rather than jargon;
4. Be divided into short sections and sentences; and
5. Use lists and tables wherever possible.
If you believe we have not met these requirements, send us comments
by one of the methods listed in the ADDRESSES section. To better help
us revise the rule, your comments should be as specific as possible.
For example, you should tell us the numbers of the sections or
paragraphs that you find unclear, which sections or sentences are too
long, or the sections where you believe lists or tables would be
useful.
List of Subjects
30 CFR Part 250
Administrative practice and procedure, Continental shelf,
Environmental impact statements, Environmental protection, Government
contracts, Incorporation by reference, Investigations, Oil and gas
exploration, Penalties, Pipelines, Public lands-mineral resources,
Public lands--rights of-way, Reporting and recordkeeping requirements,
Sulphur.
30 CFR Part 550
Administrative practice and procedure, Continental shelf,
Environmental impact statements, Environmental protection, Mineral
resources, Oil and gas exploration, Pipelines, Reporting and
recordkeeping requirements, Sulfur.
Katharine MacGregor,
Deputy Secretary, U.S. Department of the Interior.
For the reasons stated in the preamble, BSEE and BOEM amend 30 CFR
parts 250 and 550 as follows:
Title 30--Mineral Resources
CHAPTER II--BUREAU OF SAFETY AND ENVIRONMENTAL ENFORCEMENT, DEPARTMENT
OF THE INTERIOR
SUBCHAPTER B--OFFSHORE
PART 250--OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER
CONTINENTAL SHELF
0
1. The authority citation for 30 CFR part 250 continues to read as
follows:
Authority: 30 U.S.C. 1751, 31 U.S.C. 9701, 33 U.S.C.
1321(j)(1)(C), 43 U.S.C. 1334.
0
2. Amend Sec. 250.105 by revising the definition of ``Capping stack''
to read as follows:
Sec. 250.105 Definitions.
* * * * *
Capping stack means a mechanical device that can be installed on
top of a subsea or surface wellhead or blowout preventer to stop the
uncontrolled flow of fluids into the environment.
* * * * *
0
3. Amend Sec. 250.175 by adding paragraph (d) to read as follows:
Sec. 250.175 When may the Regional Supervisor grant an SOO?
* * * * *
(d) For leases or units on the Arctic OCS, you may request, and the
Regional Supervisor may grant, an SOO when you have conducted
leaseholding operations during the drilling season immediately
preceding the period for which you are seeking a suspension, and you
satisfy one of the following conditions:
(1) You are conducting drilling operations from a Mobile Offshore
Drilling Unit (MODU), but you are not able to safely continue
leaseholding operations due to the presence of seasonal ice;
(2) You are conducting drilling operations from an artificial
gravel island or a gravity-based structure, but you are not able to
safely continue leaseholding operations due to temporary seasonal
restrictions in your approved oil spill response plan; or
(3) You are conducting drilling operations from an artificial ice
island, but you are not able to safely continue leaseholding operations
due to seasonal temperature changes.
0
4. Amend Sec. 250.198 by revising paragraph (e)(73) to read as
follows:
Sec. 250.198 Documents incorporated by reference.
* * * * *
(e) * * *
(73) API RP 17H, Remotely Operated Tools and Interfaces on Subsea
Production Systems, Second Edition, June 2013; Errata, January 2014;
incorporated by reference at Sec. Sec. 250.472(a) and 250.734(a);
* * * * *
0
5. Amend Sec. 250.300 by revising paragraphs (b)(1) and (2) to read as
follows:
Sec. 250.300 Pollution prevention.
* * * * *
(b)(1) The District Manager may restrict the rate of drilling fluid
discharges or prescribe alternative discharge methods. The District
Manager may also restrict the use of components that could cause
unreasonable degradation to the marine environment. No petroleum-based
substances, including diesel fuel, may be added to the drilling mud
system without prior approval of the District Manager. For Arctic OCS
exploratory drilling, you must capture all petroleum-based mud to
prevent its discharge into the marine environment.
(2) You must obtain approval from the District Manager of the
method you plan to use to dispose of drill cuttings, sand, and other
well solids. For Arctic OCS exploratory drilling, you must capture all
cuttings from operations that use petroleum-based mud to prevent their
discharge into the marine environment.
* * * * *
0
6. Amend Sec. 250.470 by:
0
a. Revising paragraphs (b)(11) and (12);
0
b. Adding paragraph (b)(13);
0
c. Revising paragraph (f)(3); and
[[Page 79320]]
0
d. Adding paragraph (h).
The revisions and additions read as follows:
Sec. 250.470 What additional information must I submit with my APD
for Arctic OCS exploratory drilling operations?
* * * * *
(b) * * *
(11) Pick up the oil spill prevention booms and equipment;
(12) Offload the drilling crew; and
(13) Recover the subsea isolation device (SSID), where applicable.
* * * * *
(f) * * *
(3) Where applicable, proof of contracts or membership agreements
with cooperatives, service providers, or other contractors who will
provide you with the necessary SCCE or related supplies and services if
you do not possess them. The contract or membership agreement must
include provisions for ensuring the availability of the personnel and/
or equipment on a 24-hour per day basis while you are drilling below or
working below the surface casing, or before the last casing point prior
to penetrating a zone capable of flowing hydrocarbons in measurable
quantities, as approved by the Regional Supervisor.
* * * * *
(h) If you plan to install a subsea isolation device (SSID) on your
well in accordance with Sec. 250.472(a), a certification signed by a
registered professional engineer that your SSID and well design
(including casing and cementing program) meet the design requirements
in Sec. 250.472 and the design is appropriate for the purpose for
which it is intended under expected wellbore conditions.
0
7. Amend Sec. 250.471 by revising paragraph (a) introductory text, and
paragraphs (a)(2) and (3) and (b) to read as follows:
Sec. 250.471 What are the requirements for Arctic OCS source control
and containment?
* * * * *
(a) If you use a MODU, you must have access to the SCCE as
described in paragraphs (a)(1) through (3) of this section capable of
controlling and containing the flow from an out-of-control well when
drilling below or working below the surface casing. However, the
Regional Supervisor will approve delaying access to your SCCE until
your operations have reached the last casing point prior to penetrating
a zone capable of flowing hydrocarbons in measurable quantities,
provided that you submit adequate documentation (such as, but not
limited to, risk modeling data, off-set well data, analog data, seismic
data), with your APD, demonstrating that you will not encounter any
abnormally high-pressured zones or other geologic hazards. The Regional
Supervisor will base the determination on any documentation you provide
as well as any other available data and information.
* * * * *
(2) A cap and flow system that can be deployed as directed by the
Regional Supervisor pursuant to paragraph (h) of this section. The cap
and flow system must be designed to capture at least the amount of
hydrocarbons equivalent to the calculated worst case discharge rate
referenced in your BOEM-approved EP; and
(3) A containment dome that can be deployed as directed by the
Regional Supervisor pursuant to paragraph (h) of this section. The
containment dome must have the capacity to pump fluids without relying
on buoyancy.
(b) You must conduct a monthly stump test of dry-stored capping
stacks.
* * * * *
0
8. Revise Sec. 250.472 to read as follows:
Sec. 250.472 What are the additional well control equipment or relief
rig requirements for the Arctic OCS?
If you will be conducting exploratory drilling operations from a
Mobile Offshore Drilling Unit (MODU), you must either use a Subsea
Isolation Device (SSID) or have access to a relief rig as an additional
means to secure the well in the event of a loss of well control. If you
satisfy this requirement through use of an SSID, you must meet the
requirements in paragraph (a) in this section. If you satisfy this
requirement through maintaining access to a relief rig, you must meet
the requirements in paragraph (b) in this section.
(a) Subsea Isolation Device (SSID). If you use an SSID to satisfy
this requirement, your SSID and well (including the casing and
cementing program) must be designed to achieve a full shut-in, without
causing an underground blowout or having reservoir fluids broach to the
seafloor. Your SSID must also meet the following requirements:
Table 1 to Paragraph (a)
------------------------------------------------------------------------
Your SSID must
------------------------------------------------------------------------
(1) Be designed to:............... (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.
(2) Include the following (i) Dual shear rams, including ram
equipment: locks; one ram must be a blind
shear ram;
(ii) A redundant control system,
independent from the BOP control
system, that includes ROV
capabilities and a control station
on the rig;
(iii) Independent, dedicated subsea
accumulators with the capacity to
function all components of the
SSID; and
(iv) Two side inlets for
intervention; one inlet must be
located below the lowest ram on the
SSID.
(3) Include ROV intervention (i) Be able to close each shear ram
equipment and capabilities. Your under MASP conditions, as defined
ROV equipment and capabilities for the operation;
must:
(ii) Include an ROV panel that is
compliant with API RP 17H (as
incorporated by reference in Sec.
250.198);
(iii) Meet the ROV requirements in
Sec. 250.734(a)(5); and
(iv) Have the ability to function
the SSID in any environment (e.g.,
when in a mudline cellar).
[[Page 79321]]
(4) Be installed:................. (i) Below the BOP;
(ii) At or before the time that you
first install your BOP; and
(iii) To provide protection from
deep ice keels, in the event it
must remain in place over the
winter season (e.g., installed in a
mudline cellar).
(5) Be tested:.................... According to the BOP testing
requirements in Sec. 250.737.
------------------------------------------------------------------------
(b) Relief Rig. If you choose to satisfy this requirement by having
access to a relief rig, you must have access to your relief rig at all
times when you are drilling below or working below the surface casing
during Arctic OCS exploratory drilling operations. However, the
Regional Supervisor will approve delaying access to your relief rig
until your operations have reached the last casing point prior to
penetrating a zone capable of flowing hydrocarbons in measurable
quantities, provided that you submit adequate documentation (such as,
but not limited to, risk modeling data, off-set well data, analog data,
seismic data), with your APD, demonstrating that you will not encounter
any abnormally high-pressured zones or other geologic hazards. The
Regional Supervisor will base the determination on any documentation
you provide as well as any other available data and information. Your
relief rig must be different from your primary drilling rig, staged in
a location, such that it would be available to arrive on site, drill a
relief well, kill and abandon the original well, and abandon the relief
well no later than 45 days after the loss of well control.
(1) Your relief rig must comply with all other requirements of this
part pertaining to drill rig characteristics and capabilities, and it
must be able to drill a relief well under anticipated Arctic OCS
conditions.
(2) In the event of a loss of well control, the Regional Supervisor
may direct you to drill a relief well using a relief rig that is able
to kill and permanently plug an out-of-control well as described in
your APD.
0
9. Amend Sec. 250.720 by revising paragraph (c)(2) to read as follows:
Sec. 250.720 When and how must I secure a well?
* * * * *
(c) * * *
(2) In areas of ice scour, you must use a well mudline cellar or an
equivalent means of minimizing the risk of damage to the well head and
wellbore. You may request, and the Regional Supervisor may approve, an
alternate procedure or equipment in accordance with Sec. Sec. 250.141
and 250.408.
* * * * *
CHAPTER V--BUREAU OF OCEAN ENERGY MANAGEMENT, DEPARTMENT OF THE
INTERIOR
SUBCHAPTER B--OFFSHORE
PART 550--OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER
CONTINENTAL SHELF
0
10. The authority citation for 30 CFR part 550 continues to read as
follows:
Authority: 30 U.S.C. 1751; 31 U.S.C. 9701; 43 U.S.C. 1334.
Sec. 550.220 [Amended]
0
11. Amend Sec. 550.200 by removing the words ``IOP means Integrated
Operations Plan.'' in paragraph (a).
0
12. Remove and reserve Sec. 550.204.
Sec. 550.204 [Reserved]
0
13. Amend Sec. 550.206 by revising the section heading, paragraph (a)
introductory text, and paragraphs (a)(3), (b), and (c) to read as
follows:
Sec. 550.206 How do I submit the EP, DPP, or DOCD?
(a) Number of copies. When you submit an EP, DPP, or DOCD to BOEM,
you must provide:
* * * * *
(3) Any additional copies that may be necessary to facilitate
review of the EP, DPP, or DOCD by certain affected States and other
reviewing entities.
(b) Electronic submission. You may submit part or all of your EP,
DPP, or DOCD and its accompanying information electronically. If you
prefer to submit your EP, DPP, or DOCD electronically, ask the Regional
Supervisor for further guidance.
(c) Withdrawal after submission. You may withdraw your proposed EP,
DPP, or DOCD at any time for any reason. Notify the appropriate BOEM
Regional Office if you do.
0
14. Amend Sec. 550.211 by redesignating paragraphs (b) through (d) as
paragraphs (c) through (e), respectively, and adding new paragraph (b)
to read as follows:
Sec. 550.211 What must the EP include?
* * * * *
(b) A description of how you will ensure operational safety while
working in Arctic OCS conditions, including but not limited to:
(1) The safety principles that you intend to apply to yourself and
your contractors;
(2) The accountability structure within your organization for
implementing such principles;
(3) How you will communicate such principles to your employees and
contractors; and
(4) How you will determine successful implementation of such
principles.
* * * * *
0
15. Amend Sec. 550.220 by revising the section heading, paragraphs
(c)(1) and (4), and (c)(6)(ii) to read as follows:
Sec. 550.220 If I propose activities in the Arctic OCS Region, what
planning information must accompany the EP?
* * * * *
(c) * * *
(1) A description of how your exploratory drilling will be designed
and conducted, (including how all vessels and equipment will be
designed, built, and/or modified) to account for Arctic OCS conditions
and how such activities will be managed and overseen as an integrated
endeavor. In your description of vessel modifications, describe any
approvals from the flag state and the vessel classification society,
including any allowances or limitations placed upon the vessel by the
classification society and/or the United States Coast Guard.
* * * * *
(4) Additional well control equipment requirements for the Arctic
OCS. A general description of how you will comply with Sec. 250.472 of
this title.
(6) * * *
(ii) The termination of drilling operations consistent with the
well control planning requirements under Sec. 250.472 of this title.
[FR Doc. 2020-25818 Filed 12-8-20; 8:45 am]
BILLING CODE 4310-VH-P; 4310-MR-P