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

Federal RegisterDec 9, 2020

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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.

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,

mark.fesmire@bsee.gov,

(907) 334-5300. For technical questions related to regulatory changes BOEM is proposing in Part 550, contact Joel Immaraj, BOEM, Alaska Regional Office,

joel.immaraj@boem.gov,

(907) 334-5238. For procedural questions contact Bryce Barlan, BSEE, Regulations and Standards Branch,

regs@bsee.gov,

(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.”

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.

Outer Continental Shelf Lands Act, Public Law 95-372, sec. 102 (Sept. 8, 1978), 43 U.S.C. 1802(1)).

Since publication of the 2016 Arctic Exploratory Drilling Rule, new

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.

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.

These Orders did no dictate outcomes; rather, they directed a review in accordance with applicable law.

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

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

Subpart A—General

• Definitions. (§ 250.105)

• When may the Regional Supervisor grant an SOO? (§ 250.175)

• Documents incorporated by reference. (§ 250.198)

Subpart C—Pollution Prevention and Control

• Pollution prevention. (§ 250.300)

Subpart D—Oil and Gas Drilling Operations

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

• What are the requirements for Arctic OCS source control and containment? (§ 250.471)

• What are the additional well control equipment or relief rig requirements for the Arctic OCS? (§ 250.472)

Subpart G—Well Operations and Equipment

• When and how must I secure a well? (§ 250.720)

B. Key Revisions Proposed by BOEM

Subpart B—Plans and Information

• Definitions. (§ 550.200)

• Removal of § 550.204,

When must I submit my IOP for proposed Arctic exploratory drilling operations and what must the IOP include?

• How do I submit the EP, DPP, or DOCD? (§ 550.206)

• What must the EP include? (§ 550.211)

• If I propose activities in the Arctic OCS Region, what planning information must accompany the EP? (§ 550.220)

III. Additional Comments Solicited on the Same Season Relief Well and Relief Rig Requirement

IV. Procedural Matters

A. Regulatory Planning and Review (Executive Orders (E.O.) 12866, 13563, and 13771)

B. Regulatory Flexibility Act and Small Business Regulatory Enforcement Fairness Act

C. Unfunded Mandates Reform Act of 1995 (UMRA)

D. Takings Implication Assessment

E. Federalism (E.O. 13132)

F. Civil Justice Reform (E.O. 12988)

G. Consultation With Indian Tribes (E.O. 13175)

H. Environmental Justice in Minority Populations and Low-Income Populations (E.O. 12898)

E.O. 12898

I. Paperwork Reduction Act (PRA)

J. National Environmental Policy Act of 1969 (NEPA)

K. Data Quality Act

L. Effects on the Nation's Energy Supply (E.O. 13211)

M. Clarity of Regulations

List of Acronyms and References

60-Day report

Report to the Secretary of the Interior, review of Shell's 2012 Alaska Offshore Oil and

Gas Exploration Program

2016 Arctic Exploratory Drilling Rule

Oil and Gas and Sulfur Operations on the Outer Continental Shelf-Requirements for Exploratory Drilling on the Arctic Outer Continental Shelf, 81 FR 46478, July 15, 2016 (available at

https://www.doi.gov/sites/doi.gov/files/migrated/news/pressreleases/upload/Shell-report-3-8-13-Final.pdf.

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.

Environmental Assessment.

EIA

Environmental Impact Analysis.

EIS

Environmental Impact Statement.

E.O.

Executive Order.

Exploration Plan.

EPA

Environmental Protection Agency.

ESA

Endangered Species Act.

G&G

Geological and geophysical.

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.

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.

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.

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.

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.

Currently, the only offshore Federal production in the Arctic OCS

is Hilcorp's Northstar field, which includes both State and Federal acreage in the 8(g) Zone.

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

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.

https://dec.alaska.gov/spar/ppr/response/sum_fy06/060302301/factsheets/060302301_factsheet_PB.pdf.

http://aogweb.state.ak.us/DataMiner3/Forms/Production.aspx.

There are Federal OCS leases that do not have ongoing production in the Cook Inlet, which is not considered part of the Arctic.

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).

https://revenuedata.doi.gov/downloads/disbursements/.

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.

https://www.alyeska-pipe.com/TAPS.

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.

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.

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.

https://www.legfin.akleg.gov/,

Budget History Data (Excel) (posted 1-15-2020), Row 59.

https://www.legfin.akleg.gov/,

Budget History Data (Excel) (posted 1-15-2020), Row 55.

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.

Since 1978, this fund has grown to a total fund value of $60 billion as of March 2020.

Individual distributions to Alaskans from the fund have ranged from $386 per person to as high as $2,072 per person.

These annual payments are estimated to have lifted between 15,000 and 25,000 Alaskans above the Federal poverty line.

https://apfc.org/frequently-asked-questions/#why-did-alaskans-create-the-fund.

https://apfc.org/our-performance/.

https://pfd.alaska.gov/Division-Info/Summary-of-Applications-and-Payments.

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.

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.

http://www.north-slope.org/assets/images/uploads/13_Economic_Development_-_NSB_Comprehensive_Plan.pdf.

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.

In general, the formations are fairly continuous across the Arctic Alaska Petroleum Province.

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

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

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

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.

However, the Arctic OCS's vast potential has yet to be realized.

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.

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.

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.

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

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,

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.

“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).

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.

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.

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.

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.

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.

Over-pressure started to occur at around 6,700 feet subsea.

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.

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.

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.

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.

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.

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

Arctic Alaska coast: Gambell, Savoonga, Wales, Little Diomede, Kivalina, Point Hope, Point Lay, Wainwright, Barrow

(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.

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),

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.

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.

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.

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.

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)”.

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.

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

Salazar,

730 F. Supp.2d 1009 (D. Ak., 2010);

see also Native Village of Point Hope

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.

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.

Demand for oil remained relatively stable between 2008 and 2019, with only a minor increase in 2019 over 2008—approximately a 4% increase.

https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=F000000__3&f=M.

https://www.eia.gov/todayinenergy/detail.php?id=4910.

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

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.

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.

https://www.shell.com/media/news-and-media-releases/2015/shell-updates-on-alaska-exploration.html.

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‐season” relief well capacity, whereby the operator demonstrates its capability to drill a relief well and kill an out‐of‐control well in the same drilling season. Whereas the U.S. requires the ability to bring in a relief‐drilling rig and complete the plug and abandonment within 45 days, Norway and Greenland require a relief‐drilling rig to be on site within 12 days.

•

SCCE

—Canada is the only country besides the U.S. that has specific SCCE requirements. Canada's requirements, however, are less prescriptive in that they include a more general requirement for “cap and containment methods and same‐well intervention methods,” as compared to the U.S. requirement for access to specific SCCE equipment within a specified time period.

•

Alternative Technologies

—With respect to approval of alternative technologies in lieu of a relief rig or SCCE, the U.S. has specific regulations that allow for potential substitutions and accommodations for innovative technologies. Canada also provides for the approval of alternative technologies through specific approval processes. Norway's regulations, in general, are largely performance-based. As such, their regulations allow for the consideration of different technologies at the onset when planning a project.

B. BSEE and BOEM Statutory and Regulatory Authority and Responsibilities

The Outer Continental Shelf Lands Act, 43 U.S.C. 1331

et seq.,

was first enacted in 1953 and substantially amended in 1978. In amending OCSLA, Congress established a national policy of making the OCS “available for expeditious and orderly development, subject to environmental safeguards, in a manner which is consistent with the maintenance of competition and other national needs.” (43 U.S.C. 1332(3)). OCSLA authorizes the Secretary of the Interior (Secretary) to lease the OCS for mineral development and to regulate oil and gas exploration, development, and production operations on the OCS.

On May 19, 2010, Secretary Ken Salazar issued S.O. 3299, which

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

(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.

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.

Secretary's Order 3299 made BSEE responsible for safety and environmental enforcement functions, including, but not limited to, the authority to permit activities, inspect, investigate, summon witnesses and produce evidence: Levy penalties; cancel or suspend activities; and oversee safety, and oil spill response and removal preparedness. BSEE's mission is to promote safety, protect the environment, and conserve resources through vigorous regulatory oversight and enforcement. BSEE's functions include evaluating permit applications for post-lease oil and natural gas exploration and development activities on the OCS and conducting inspections to ensure compliance with laws, regulations, lease terms, and approved plans and permits.

BOEM evaluates EPs, and BSEE, thereafter, evaluates Applications for Permits to Drill (APDs) and other permits and applications, to determine whether the operator's proposed activities meet OCSLA's standards and each Bureau's regulations governing OCS exploration. Based on their respective evaluations, BSEE and BOEM will either approve the operator's EP and APD, require the operator to modify its submissions, or disapprove the EP or APD (§ 250.410,

How do I obtain approval to drill a well?

). The review and approval of these activities is outlined below in the following section.

1. BOEM Approval of the EP

As promulgated through the 2016 Arctic Exploratory Drilling Rule, § 550.204,

When must I submit my IOP for proposed Arctic exploratory drilling operations and what must the IOP include?,

requires that a lessee submit an IOP at least 90 days before filing an EP with BOEM, if that EP would involve exploration for oil and gas on the Arctic OCS. While the IOP is not subject to approval, the submission was intended to facilitate the prompt sharing of information among the relevant Federal agencies that may be involved in overseeing exploratory drilling operations conducted from MODUs. The operator may then submit an EP to BOEM for approval. An EP must include information such as a schedule of anticipated exploration activities, equipment to be used, the general location of each well to be drilled, and any other information deemed pertinent by BOEM (§§ 550.211 through 550.228).

2. BSEE Approval of the APD

Approval of an EP does not, by itself, permit the operator to proceed with exploratory drilling. After BOEM approves the EP, the operator must submit to BSEE an APD, which BSEE must approve before an operator may drill a well (43 U.S.C. 1340(d); § 250.410). Among other things, the APD must be consistent with the approved EP and include information on the well location, the drilling design and procedures, casing and cementing programs, the diverter and blowout preventer (BOP) systems, MODU (if one is to be used), and any additional information requested by the BSEE District Manager.

C. Executive and Secretary's Orders

On March 28, 2017, the President issued E.O. 13783—Promoting Energy Independence and Economic Growth (82 FR 16093). The E.O. directed Federal agencies to review all existing regulations and other similar agency actions, which potentially burden the development or use of domestically produced energy resources with the goal of “avoiding regulatory burdens that unnecessarily encumber energy production, constrain economic growth, and prevent job creation.” It made it U.S. policy for agencies to “review existing regulations that potentially burden the development or use of domestically produced energy resources and appropriately suspend, revise, or rescind those that unduly burden the development of domestic energy resources beyond the degree necessary to protect the public interest or otherwise comply with the law.”

On April 28, 2017, the President issued E.O. 13795—Implementing an America-First Offshore Energy Strategy (82 FR 20815), which directed the Secretary to “take all steps necessary to review” the 2016 Arctic Exploratory Drilling Rule and, “if appropriate, [to,] as soon as practicable and consistent with law, publish for notice and comment a proposed rule suspending, revising, or rescinding this rule.” The policy underlying E.O. 13795 is “to encourage energy exploration and production, including on the Outer Continental Shelf, in order to maintain the Nation's position as a global energy leader and foster energy security and resilience for the benefit of the American people, while ensuring that any such activity is safe and environmentally responsible.” These E.O.s did not dictate outcomes; rather, they provided direction for review in accordance with all relevant laws.

To further implement E.O. 13795, on May 1, 2017, the Secretary issued S.O. 3350,

America-First Offshore Energy Strategy,

directing BSEE and BOEM to review the 2016 Arctic Exploratory

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,

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

interference by seasonal constraints unique to the Arctic.

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).

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? (§ 250.471).

It is not practical for BSEE's regulations to prescribe that certain SCCE (containment dome and cap and flow system, in particular) be positioned within proximity to a well location when the conditions for safely deploying this equipment in the Arctic OCS are limiting. However, BSEE would retain other existing containment dome and cap and flow system requirements in § 250.471, which provide that the operator must:

(i) Demonstrate that it has access to a containment dome and cap and flow system;

(ii) Provide a containment dome and cap and flow system that meets BSEE's operating standards;

(iii) Conduct tests or exercises for all SCCE; and

(iv) Maintain records pertaining to the testing, inspection, maintenance, and use of the SCCE and make these available to BSEE upon request. The changes BSEE proposes to the SCCE requirements in § 250.471 would preserve the regulations' requirement that operators have redundant protective measures that are appropriate for Arctic OCS conditions because there is no guarantee that a single measure could control or contain a WCD.

4. Same Season Relief Well (SSRW) Requirement and Subsea Isolation Devices (SSID)—BSEE proposes to revise the relief rig and SSRW requirements by providing the operator with the option of using an SSID or having access to a relief rig as an additional means to secure the well in the event of a loss of well control, if the operator will be conducting exploratory drilling operations from a MODU. In addition, BSEE proposes to provide an opportunity to the operator to adjust the point in time during operations when it must stage its relief rig (if the operator elects to have access to a relief rig) when conducting Arctic OCS exploratory drilling operations—from when drilling below or working below the “surface casing” to when drilling below or working below the “last casing point prior to penetrating a zone capable of flowing hydrocarbons in measurable quantities.” If the operator is able to demonstrate to BSEE, based on 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 § 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.

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 §§ 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

lease stipulations.

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.

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.”

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 § 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),

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. (§ 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 § 250.471,

What are the requirements for Arctic OCS source control and containment?

Existing § 250.471(a)(1), specifically requires the operator, when drilling below or working below the surface casing, to have access to a capping stack that is positioned to ensure that it will be able to arrive at the well location within 24 hours after a loss of well control. Typically, an operator would comply with this requirement by having one or more support vessels capable of handling and deploying the capping stack down to the subsea wellhead, when needed. Installing an SSID below the subsea BOP allows the operator to comply with § 250.471(a)(1) and forgo the need to provide support vessels and a capping stack on standby at the surface.

However, BSEE is proposing to eliminate this language because a 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 § 250.472,

What are the additional well control equipment or relief rig requirements for the Arctic OCS?

This proposed revision would provide clarity concerning the capping stack requirements under § 250.471, specifically that installation of an SSID under § 250.472 does not constitute compliance with the capping stack requirements under § 250.471. For purposes of BSEE's proposed regulations, an SSID is not considered to be the same as, or to satisfy the requirement to have, a capping stack. The new SSID option that BSEE is proposing under § 250.472 does not, and is not intended to, replace any of the SCCE requirements in proposed § 250.471(a), where BSEE's capping stack requirement is addressed.

When may the Regional Supervisor grant an SOO? (§ 250.175)

BSEE proposes to revise § 250.175 by adding a new paragraph (d), which would allow an operator to request an SOO under certain situations that may be present in the Arctic OCS. This proposed revision is consistent with OCSLA's requirement that the Secretary promulgate suspensions regulations that “facilitate proper development of a lease . . . .”

The proposed regulation would list the factors upon which BSEE may rely when determining whether to grant an SOO and include when an operator:

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.

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.

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

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 § 250.175 would facilitate the proper development of a lease by addressing those seasonal conditions that limit leaseholding operations by providing an operator ready and able to complete its operations with the opportunity to obtain an SOO. If granted, this SOO would suspend the running of the lease term and effectively extend the term of the affected lease by a period equivalent to the period of such suspension. The SOO would allow a diligent operator to use the full 10 years in a 10-year lease term to explore for hydrocarbons, without the concern for a lease expiring because Arctic seasonal constraints prevented operations.

BSEE would continue to require the operator to comply with the existing requirements for requesting a suspension under existing § 250.171,

How do I request a suspension?

For example, § 250.171 requires the operator to submit a reasonable schedule of work for resuming the suspended operations on the subject lease for which the operator requests the suspension. A schedule of work typically includes milestones describing what activities the operator will perform to resume operations and when those operations will be performed. If the operator submits a schedule of work that demonstrates a reasonable plan and schedule for resuming operations, BSEE will typically grant the SOO (assuming the other requirements are satisfied). BSEE will use the reasonable schedule of work as an established measuring stick by which the Bureau would assess the operator's diligence and progress toward prudent development. If the operator does not adhere to its approved work schedule, BSEE may terminate the SOO under existing regulations. Paragraph (e) of existing § 250.170,

How long does a suspension last?

authorizes BSEE to terminate any suspension when the Regional Supervisor determines the circumstances that justified the suspension no longer exist. Because a reasonable schedule of work serves as a required foundation for BSEE's SOO approval, the operator's adherence to that schedule is necessary to maintain the SOO. This allows BSEE to ensure that the operator complies with the OCSLA Congressional declaration of purpose. Other regulations under Subpart A that would also apply to BSEE's implementation of proposed paragraph (d) of § 250.175 includes § 250.170,

How long does a suspension last?

which allows BSEE to issue a suspension for up to five years and provides that the suspension automatically ends when the suspended operation commences.

BSEE understands the requirement in OCSLA to supervise operations in a manner that assures due diligence in the exploration and development of each lease. Therefore, BSEE is contemplating the option of limiting the period for when the suspension would remain in effect; only during the period between one drilling season and the next when the operator is prevented from continuing its drilling or other leaseholding activities due to seasonal conditions. This option would still provide operators more time to effectively explore their leases without fear of an expiring lease. It could also provide BSEE with a better means of tracking an operator's diligence efforts. This option, however, could result in additional unnecessary burdens, since an operator would have to “reapply” for a new suspension if the operator is unable to return to the location during the next open-water season. BSEE is seeking comment on this regulatory option for the SOO or any other option that could avoid or minimize additional burden, but still assure diligent lease exploration and development.

BSEE's proposed regulatory change would address concerns raised in the NPC reports, which suggested that the current approach toward administration of the 10-year primary lease term allowed under OCSLA “comes from other offshore areas in the U.S., where operators have access to the leases all year-round.” (NPC 2015 Report at 31 and NPC 2019 Report at 25). The NPC 2019 Report pointed out that a “10-year lease in the U.S. Arctic equates to about 3 to 4 years of working time, compared with the equivalent 10 years working time in the Gulf of Mexico.” (NPC 2019 Report at 25). While it is not possible for BOEM to award leases with more than the maximum ten-year primary lease term allowed under OCSLA, this proposed regulatory change would rely on the Secretary's statutorily delegated authority, which has, in turn, been delegated to BSEE, to administer suspensions to address, as appropriate, the effects of Arctic working conditions when they may limit the operator's ability to perform leaseholding activities.

Documents Incorporated by Reference. (§ 250.198)

BSEE proposes to revise the existing relief rig and SSRW requirements in § 250.472 by providing the operator with an option to either use an SSID or have access to a relief rig if the operator will conduct exploratory drilling operations from a MODU. As part of that proposed regulatory change, which is discussed in detail later below in the

What are the relief rig or additional well control equipment or relief rig requirements for the Arctic OCS? (§ 250.472)

section-by-section discussion, BSEE proposes to require the SSID to include Remotely Operated Vehicle (ROV) intervention equipment that has the capabilities to function the SSID. Under proposed § 250.472(a)(3)(ii), BSEE would require the ROV to have panels that are compliant with API RP 17H,

Remotely Operated Tools and Interfaces on Subsea Production Systems,

Second Edition, June 2013; Errata, January 2014, to ensure that the operator's ROV capabilities for the SSID follow BSEE's existing ROV panel requirements for BOP systems. In conjunction with proposed paragraph (a)(3)(ii) that would require the operator's ROV panels to be compliant with API RP 17H, BSEE proposes to add the citation for proposed § 250.472(a)(3) to § 250.198(e)(73). Paragraph (e)(73) of § 250.198 documents the locations in the regulations where API RP 17H is incorporated by reference as a regulatory requirement, which would include § 250.472(a)(3) under this proposed rule. Adding the citation for § 250.472(a)(3) to § 250.198(e)(73) would clarify that API RP 17H is a regulatory requirement when complying with § 250.472 and is subject to BSEE

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:

regs@bsee.gov

), 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

regs@bsee.gov.

Subpart C—Pollution Prevention and Control

Pollution prevention. (§ 250.300)

BSEE proposes to revise paragraphs (b)(1) and (2) of § 250.300 by eliminating the existing language that states the Regional Supervisor may require the capture of all water-based mud, and associated cuttings, from operations after completion of the hole for the conductor casing to prevent its discharge into the marine environment. While this proposed rule would eliminate the language regarding the Regional Supervisor's discretionary authority to require the capture of water-based muds and cuttings, it would maintain the existing requirement in § 250.300(b)(1) and (2) that operators capture all petroleum-based mud and associated cuttings while operating on the Arctic OCS.

Existing § 250.300(b)(1) and (2) state that the BSEE Regional Supervisor may exercise his or her discretionary authority to restrict discharges of 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

does not allow the discharge of water-based muds and cuttings during the fall bowhead whale hunt. However, the Chukchi Sea permit

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.

https://www.epa.gov/sites/production/files/2017-12/documents/r10-npdes-beaufort-oil-gas-gp-akg282100-final-permit-2012.pdf.

https://www.epa.gov/sites/production/files/2017-12/documents/r10-npdes-chukchi-oil-gas-gp-akg288100-final-permit-2012.pdf.

https://www.epa.gov/sites/production/files/2017-12/documents/r10-npdes-chukchi-oil-gas-gp-akg288100-odce-2012.pdf,

pp. 6-14 to 6-17.

Under this proposed rule, BSEE would preserve the requirements in § 250.300(b)(1) and (2) that the operator capture all petroleum-based mud and associated cuttings. This requirement is consistent with a longstanding, OCS-wide regulatory authority that existed prior to the promulgation of the 2016 Arctic Exploratory Drilling Rule. BSEE must preserve the petroleum-based muds and cuttings requirement since it is not unusual for petroleum-based

muds to contain constituents that are toxic and harmful to the environment. Although water-based muds may not be a feasible option for all drilling operations, such as when drilling through hydrophobic geologic formations that could be damaged by water-based muds, its use is a more environmentally benign approach in comparison to the use of petroleum-based muds. However, BSEE's proposed revisions reflect the Bureau's understanding that the express statements regarding the Regional Supervisor's discretionary authority to require the capture of water-based muds and cuttings in existing § 250.300(b)(1) and (2) are not necessary. In particular, the EPA already addresses the goals of protecting water quality through the NPDES program, protecting marine species and their habitats, as well as the effectiveness of subsistence hunting activities, through the exercise of that agency's authorities. Thus, BSEE does not expect the Regional Supervisor to need to exercise the discretionary authority under existing § 250.300(b)(1) and (2) in the foreseeable future.

Furthermore, BSEE understands, and did so even while it was preparing the 2016 Arctic Exploratory Drilling rule, that the references to the BSEE Regional Supervisor's authority in existing paragraphs (b)(1) and (2) created some uncertainty for the regulated industry because it appeared to overlap with EPA's jurisdiction and, if implemented, might result in BSEE issuing duplicative or conflicting requirements. BSEE addressed this concern by explaining that the amendments were meant to clarify the Regional Supervisor's authority to impose operational measures that complement EPA's discharge limitations by considering potential impacts to specific components of the Arctic environment, such as subsistence activities, marine resources, and coastal areas (81 FR 46505). Given the policy in E.O. 13783 to review existing regulations that potentially burden the development or use of domestically produced energy resources and the general principles in Section 1 of E.O. 13563—

Improving Regulation and Regulatory Review

(76 FR 3821)—to promote predictability and reduce uncertainty, BSEE believes it is appropriate to propose eliminating the water-based mud, and associated cuttings, provisions in § 250.300(b)(1) and (2).

This proposed regulatory change does not suggest any change in BSEE's recognition that it is responsible for ensuring that oil and gas exploration and production activities on the OCS are conducted in a safe and environmentally responsible manner pursuant to OCSLA. Therefore, the proposed rule would not alter the longstanding regulation at § 250.300(b)(1), under which the District Manager (or Regional Supervisor) retains the ability to restrict the rate of drilling fluid discharges or prescribe alternative discharge methods where warranted. Pursuant to § 250.300(b)(1), BSEE would be able to determine whether there is a need to require capture of water-based muds and cuttings on a case-by-case basis, if the EPA has not done so. In particular, the District Manager would consider and determine whether such a requirement would be appropriate for any facility. The District Manager would make this determination on a case-by-case basis, in conjunction with the EP and APD approval process. This process includes coordinating with BOEM, particularly at the EP stage, when BOEM conducts an environmental review to identify the direct, indirect, and cumulative environmental effects that may be expected as a result of implementing the EP. That environmental review also incorporates input about potential environmental effects that may be obtained through consultations and review by interested parties, Federal agencies (

e.g.,

EPA), State or local agencies, Tribes, or the public. Nothing would change BSEE's position from the 2016 rule to communicate with other agencies responsible for oversight of discharges related to oil and gas exploration drilling in the Arctic. This communication will help ensure that conflicts do not arise (81 FR 46504). BSEE expects that such input from EPA would address whether that agency has issued or plans to issue a permit for the same exploratory drilling facilities, and whether that agency believes that capture of water-based muds in a specific case is warranted. Through BSEE's longstanding authority under § 250.300(b)(1), the District Manager could require an operator to restrict the rate of drilling fluid discharges or prescribe alternative discharge methods. Such a restriction on the discharge of water-based muds and cuttings might be appropriate if identified in the EP environmental review process.

In addition to the proposed revisions just described, BSEE proposes a minor modification to the second sentence in existing paragraph (b)(2), which requires the operator to capture all cuttings from operations that “utilize” 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? (§ 250.470)

BSEE proposes to revise paragraph (b) of § 250.470 by adding paragraph (b)(13) to include “Recover the subsea isolation device (SSID), where applicable.” This revision is necessary to address the SSID alternative proposed in § 250.472, and to ensure the operator's permit addresses how it would recover the SSID, if one is used. For operations relying on an SSID, the SSID is a critical piece of equipment. Therefore, BSEE must understand how the operators will handle it, prior to and after drilling operations. We also propose minor, 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 § 250.471, which houses the substance of the Arctic OCS SCCE requirements. This proposed change is discussed in further detail in connection with that provision.

Finally, BSEE proposes to add a new paragraph (h) to complement the proposed revisions to § 250.472, which would provide the operator with the option to use an SSID or have access to a relief rig, as an additional means to secure the well in the event of a loss of well control, if the operator will be conducting exploratory drilling operations from a MODU (that change is discussed in further detail in connection with that provision). Under proposed paragraph (h), if the operator elects to use an SSID, BSEE would require the operator to provide a certification, signed by a registered professional engineer, confirming that its SSID and

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

What are the requirements for Arctic OCS source control and containment? (§ 250.471)

Section 250.471(a) currently requires the operator to have access to the SCCE described in paragraphs (a)(1) through (3), which must be capable of stopping or capturing the flow of an out-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 § 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

capturing

the flow

an out-of-control well” with “capable of

controlling

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.,

§ 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—§ 250.462 (

What are the source control, containment, and collocated equipment requirements?

) and is able to deploy the equipment as directed by the Regional Supervisor. Details regarding BSEE's proposed revisions to § 250.471(a)(2) and (3) are discussed in the subsection below, entitled,

Revisions to the Cap and Flow System, and Containment Dome Requirements.

•

Revisions to the Capping Stack Requirements

BSEE's proposed revisions to paragraph (a) would provide an opportunity to the operator to adjust the point in time during operations when it must position its capping stack, so that it will be available to arrive at the well location within 24 hours after a loss of well control. If the operator is able to demonstrate to BSEE that the operations it plans to conduct below the surface casing would not encounter any abnormally high-pressured zones or other geologic hazards before reaching the last casing point prior to penetrating a zone capable of flowing hydrocarbons in measurable quantities, then BSEE would allow the operator delay its positioning of the capping stack until that point. A capping stack, as defined under the existing regulations at § 250.105, is a mechanical device that can be installed on top of a subsea or surface well head or BOP to stop the uncontrolled flow of fluids into the environment. BSEE also proposes certain non-substantive language changes for clarity.

The existing capping stack requirements in paragraphs (a) and (a)(1) are intended to ensure that a capping stack is readily available to stop or capture the flow of hydrocarbons in case of a loss of well control when drilling below or working below the surface casing. While BSEE does not propose to eliminate the requirement in paragraph (a)(1) to ensure that the capping stack will be able to arrive at the well location within 24 hours after a loss of well control, the existing requirement in paragraph (a) to ensure the equipment is accessible when drilling below the surface casing does not fully take into consideration the known geology of an area. The formations below the surface casing, based on the known geology of the area, may have minimal or no potential to flow hydrocarbons in measurable quantities during drilling operations. This obviates the need for ensuring capping stack availability during operations in those zones. Prior to submitting an APD, operators assess the formations they will potentially encounter during drilling operations,

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

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, § 250.471, BSEE is also proposing to revise paragraphs (a)(2) and (3) of existing § 250.471, which refers to the timing of the arrival of a cap and flow system and containment dome, respectively, by removing the phrase “positioned to ensure that it will arrive at the well location within 7 days after a loss of well control” from each paragraph. This proposed change would remove the requirement to have a cap and flow system or a containment dome positioned to ensure the equipment will be available to arrive at the well location within 7 days after the loss of well control, while preserving the existing requirement to deploy those pieces of equipment as directed by BSEE.

BSEE proposes to allow the operator to adjust the point in time during operations when it must position its capping stack under paragraph (a), from “when drilling or working below the surface casing” to “when drilling below or working below last casing point prior to penetrating a zone capable of flowing hydrocarbons in measurable quantities” if the operator is able to demonstrate that it will not encounter any abnormally high-pressured zones or other geologic hazards before that casing point. Only the 7-day arrival timing related to the “flow” part of the cap and flow system would be altered as a result of BSEE's proposed modification to paragraph (a)(2) of § 250.471.

Existing § 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 § 250.471 for the operator to ensure:

(i) Access to a containment dome and cap and flow system;

(ii) that the cap and flow system is designed to capture at least the amount of hydrocarbons equivalent to the calculated WCD rate referenced in the operator's BOEM-approved EP;

(iii) that the containment dome has the capacity to pump fluids without relying on buoyancy;

(iv) that tests or exercises are conducted for the SCCE, as directed by the Regional Supervisor;

(v) that records pertaining to the testing, inspection, maintenance, and use of the SCCE are maintained and made available to BSEE upon request;

(vi) that all SCCE identified in § 250.471 are transported to the well upon a loss of well control; and

(vii) that SCCE is deployed as directed by the Regional Supervisor.

BSEE proposes to remove the cap and flow system and containment dome 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

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‐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 tha

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