Oil and Gas and Sulfur Operations on the Outer Continental Shelf-Revisions to the Requirements for Exploratory Drilling on the Arctic Outer Continental Shelf, 79266-79321 [2020-25818]

Download as PDF 79266 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules DEPARTMENT OF THE INTERIOR Bureau of Safety and Environmental Enforcement 30 CFR Part 250 Bureau of Ocean Energy Management 30 CFR Part 550 [Docket ID: BSEE–2019–0008, EEEE500000, 21XE1700DX, EX1SF0000.EAQ000] RIN 1082–AA01 Oil and Gas and Sulfur Operations on the Outer Continental Shelf—Revisions to the Requirements for Exploratory Drilling on the Arctic Outer Continental Shelf Bureau of Safety and Environmental Enforcement (BSEE); Bureau of Ocean Energy Management (BOEM), Interior. ACTION: Proposed rule. AGENCIES: The Department of the Interior (DOI or Department), acting through BOEM and BSEE, has reviewed and is proposing to revise its existing regulations for exploratory drilling and related operations on the Arctic Outer Continental Shelf (OCS), to reduce unnecessary burdens on stakeholders while ensuring that energy exploration on the Arctic OCS is safe and environmentally responsible. In particular, this proposed rule would revise certain requirements promulgated through the rule entitled, Oil and Gas and Sulfur Operations on the Outer Continental Shelf-Requirements for Exploratory Drilling on the Arctic Outer Continental Shelf (‘‘2016 Arctic Exploratory Drilling Rule’’). This proposed rule would also add new provisions to BSEE’s regulations pertaining to suspensions of operations (SOO), and BOEM’s Exploration Plan (EP) and Development and Production Plan (DPP) regulations. DATES: Submit comments by February 8, 2021. BSEE and BOEM may not fully consider comments received after this date. You may submit comments to the Office of Management and Budget (OMB) on the information collection burden in this proposed rule by January 8, 2021. The deadline for comments on the information collection burden does not affect the deadline for the public to comment to BSEE and BOEM on the proposed regulations. ADDRESSES: You may submit comments on BSEE’s or BOEM’s sections of the rulemaking by any of the following methods. For comments on this proposed rule, please use the Regulation jbell on DSKJLSW7X2PROD with PROPOSALS2 SUMMARY: VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 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: https:// 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, PO 00000 Frm 00002 Fmt 4701 Sfmt 4702 (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 BOEMinitiated environmental and safety reviews of potential oil and gas operations on the Arctic OCS, experiences gained from Shell’s 2012 and 2015 Arctic operations, and concerns expressed by environmental organizations and Alaska Natives, BSEE and BOEM published the 2016 Arctic Exploratory Drilling Rule (see 81 FR 46478, July 15, 2016). The rule was narrowly focused, applying solely to exploratory drilling operations conducted during the Arctic OCS openwater drilling season by drilling vessels and ‘‘jack-up rigs’’ (collectively known as mobile offshore drilling units or MODU) in the Beaufort Sea and Chukchi Sea Planning Areas. The regulations were intended to ensure that Arctic OCS exploratory drilling operations are conducted in a safe and responsible manner, while taking into account the unique conditions of the Arctic OCS, as well as Alaska Natives’ cultural traditions and their need for access to subsistence resources. BSEE and BOEM have since reviewed the 2016 Arctic Exploratory Drilling Rule taking into account a Congressional declaration of purposes in the Outer Continental Shelf Lands Act (OCSLA) to ‘‘establish policies and procedures for managing the oil and natural gas resources of the Outer Continental Shelf which are intended to result in expedited exploration and development of the Outer Continental Shelf in order to achieve national economic and energy policy goals, assure national security, reduce dependence on foreign sources, and maintain a favorable balance of payments in world trade.’’ 1 The bureaus have also reviewed new information about technological developments in an ice environment. Based on that review, BSEE and BOEM are proposing revisions in this proposed rule that are consistent with OCSLA, and would reduce unnecessary burdens on stakeholders while still maintaining safety and environmental protection. Since publication of the 2016 Arctic Exploratory Drilling Rule, new 1 Outer Continental Shelf Lands Act, Public Law 95–372, sec. 102 (Sept. 8, 1978), 43 U.S.C. 1802(1)). E:\FR\FM\09DEP2.SGM 09DEP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules Executive Orders (E.O.) and Secretary’s Orders (S.O.) called on Federal agencies to review existing regulations that potentially burden the development or use of domestically produced energy resources and appropriately begin processes to potentially suspend, revise, or rescind those regulations that are determined to unduly burden the development of domestic energy resources, beyond the degree necessary to protect the public interest or otherwise comply with the law. Executive Order 13795, Implementing an America-First Offshore Energy Strategy (82 FR 20815) and Secretary’s Order 3350, America-First Offshore Energy Strategy, which are discussed in more detail below in Section I. Background, Subsection C. Executive and Secretary’s Orders, specifically called for a review of the 2016 Arctic Exploratory Drilling Rule.2 In response to these E.O.s and S.O.s, BSEE and BOEM undertook a review of the regulations promulgated through the 2016 Arctic Exploratory Drilling Rule with a view toward encouraging energy exploration and production on the Arctic OCS, as appropriate and consistent with applicable law, and reducing unnecessary regulatory burdens, while ensuring that any such activity is safe and environmentally responsible. BSEE’s and BOEM’s views about certain features of the existing regulations were also informed by new information that has become available since the 2016 rule was finalized. This new information includes a BSEEcommissioned Technology Assessment Program (TAP) study entitled, Suitability of Source Control and Containment Equipment versus Same Season Relief Well in the Alaska Outer Continental Shelf Region (Bratslavsky and SolstenXP, 2018) and a National Petroleum Council (NPC) report entitled, Supplemental Assessment to the 2015 Report on Arctic Potential: Realizing the Promise of U.S. Arctic Oil and Gas Resources (NPC 2019 Report). BSEE also re-assessed the original NPC report entitled, Arctic Potential: Realizing the Promise of U.S. Arctic Oil and Gas Resources (NPC 2015 Report; together with the NPC 2019 Report, the NPC reports). Both NPC reports include discussions about global Arctic operations. These global operations are discussed in further detail below in Subsection 5. Industry Interest in the Arctic OCS of Section I. Background, under the subheading entitled, Global 2 These Orders did no dictate outcomes; rather, they directed a review in accordance with applicable law. VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 Arctic Exploration Activities. The Bratslavsky and SolstenXP study was finalized in October 2018 and may be downloaded from BSEE’s TAP website at: https://www.bsee.gov/researchrecord/suitability-of-source-controlcontainment-equipment-versus-sameseason-relief-well. The NPC 2019 Report was finalized in April 2019 and may be downloaded from an NPC website at: https://www.npc.org/ARSA-FINAL052219-LoRes.pdf. The NPC 2015 Report was finalized in March 2015 and may be downloaded from an NPC website at: https:// 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; PO 00000 Frm 00003 Fmt 4701 Sfmt 4702 79267 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 E:\FR\FM\09DEP2.SGM 09DEP2 79268 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules Subpart A—General • Definitions. (§ 250.105) • When may the Regional Supervisor grant an SOO? (§ 250.175) • Documents incorporated by reference. (§ 250.198) Subpart C—Pollution Prevention and Control • Pollution prevention. (§ 250.300) Subpart D—Oil and Gas Drilling Operations • What additional information must I submit with my APD for Arctic OCS exploratory drilling operations? (§ 250.470) • What are the requirements for Arctic OCS source control and containment? (§ 250.471) • What are the additional well control equipment or relief rig requirements for the Arctic OCS? (§ 250.472) Subpart G—Well Operations and Equipment • When and how must I secure a well? (§ 250.720) B. Key Revisions Proposed by BOEM Subpart B—Plans and Information • Definitions. (§ 550.200) • Removal of § 550.204, When must I submit my IOP for proposed Arctic exploratory drilling operations and what must the IOP include? • How do I submit the EP, DPP, or DOCD? (§ 550.206) • What must the EP include? (§ 550.211) • If I propose activities in the Arctic OCS Region, what planning information must accompany the EP? (§ 550.220) III. Additional Comments Solicited on the Same Season Relief Well and Relief Rig Requirement IV. Procedural Matters A. Regulatory Planning and Review (Executive Orders (E.O.) 12866, 13563, and 13771) B. Regulatory Flexibility Act and Small Business Regulatory Enforcement Fairness Act C. Unfunded Mandates Reform Act of 1995 (UMRA) D. Takings Implication Assessment E. Federalism (E.O. 13132) F. Civil Justice Reform (E.O. 12988) G. Consultation With Indian Tribes (E.O. 13175) H. Environmental Justice in Minority Populations and Low-Income Populations (E.O. 12898) E.O. 12898 I. Paperwork Reduction Act (PRA) J. National Environmental Policy Act of 1969 (NEPA) K. Data Quality Act L. Effects on the Nation’s Energy Supply (E.O. 13211) M. Clarity of Regulations LIST OF ACRONYMS AND REFERENCES 60-Day report Report to the Secretary of the Interior, review of Shell’s 2012 Alaska Offshore Oil and Gas Exploration Program 2016 Arctic Exploratory Drilling Rule .. Oil and Gas and Sulfur Operations on the Outer Continental Shelf-Requirements for Exploratory Drilling on the Arctic Outer Continental Shelf, 81 FR 46478, July 15, 2016 (available at https://www.doi.gov/ sites/doi.gov/files/migrated/news/pressreleases/upload/Shell-report-3-8-13-Final.pdf.). American Bureau of Shipping. Alternative Compliance Program. Alaska Department of Natural Resources. Alaska Eskimo Whaling Commission. Alaska National Interest Lands Conservation Act. Alaska Native Claims Settlement Act. Arctic National Wildlife Refuge. Application for Permit to Drill. American Petroleum Institute. OCS within the Beaufort Sea and Chukchi Sea Planning Areas. Alternative Well Kill System. Bureau of Ocean Energy Management. Bureau of Ocean Energy Management, Regulation and Enforcement. Blowout Preventer. Suitability of Source Control and Containment Equipment versus Same Season Relief Well in the Alaska Outer Continental Shelf Region, October 2018. Bureau of Safety and Environmental Enforcement. Bureau of Land Management. Conflict Avoidance Agreement. Code of Federal Regulations. Coastal Zone Management Act. Clean Water Act. Department of the Interior. Det Norske Veritas and Germanischer Lloyd. Development Operations Coordination Document. Department of the Interior. Development and Production Plan. Environmental Assessment. Environmental Impact Analysis. Environmental Impact Statement. Executive Order. Exploration Plan. Environmental Protection Agency. Endangered Species Act. Geological and geophysical. Information Collection. Inupiat Community of the Arctic Slope. Integrated Operations Plan. Initial Regulatory Impact Analysis. International Whaling Commission. Lower Marine Riser Package. Maximum Anticipated Surface Pressures. Marine Mammal Protection Act. Minerals Management Service. Mobile Offshore Drilling Unit. jbell on DSKJLSW7X2PROD with PROPOSALS2 ABS ..................................................... ACP ..................................................... ADNR .................................................. AEWC .................................................. ANILCA ............................................... ANCSA ................................................ ANWR ................................................. APD ..................................................... API ....................................................... Arctic OCS .......................................... AWKS .................................................. BOEM .................................................. BOEMRE ............................................. BOP ..................................................... Bratslavsky and SolstenXP, 2018 ....... BSEE ................................................... BLM ..................................................... CAA ..................................................... CFR ..................................................... CZMA .................................................. CWA .................................................... Department .......................................... DNV GL ............................................... DOCD .................................................. DOI ...................................................... DPP ..................................................... EA ........................................................ EIA ....................................................... EIS ....................................................... E.O. ..................................................... EP ........................................................ EPA ..................................................... ESA ..................................................... G&G .................................................... IC ......................................................... ICAS .................................................... IOP ...................................................... IRIA ..................................................... IWC ..................................................... LMRP .................................................. MASP .................................................. MMPA .................................................. MMS .................................................... MODU ................................................. VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 PO 00000 Frm 00004 Fmt 4701 Sfmt 4702 E:\FR\FM\09DEP2.SGM 09DEP2 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules 79269 LIST OF ACRONYMS AND REFERENCES—Continued 60-Day report Report to the Secretary of the Interior, review of Shell’s 2012 Alaska Offshore Oil and Gas Exploration Program NAICS ................................................. NEPA ................................................... NMFS .................................................. NOAA .................................................. NPC ..................................................... NPC 2015 Report ................................ NPC 2019 Report ................................ North American Industry Classification System. National Environmental Policy Act of 1969. National Marine Fisheries Service. National Oceanic and Atmospheric Administration. National Petroleum Council. Arctic Potential: Realizing the Promise of U.S. Arctic Oil and Gas Resources. Supplemental Assessment to the 2015 Report on Arctic Potential: Realizing the Promise of U.S. Arctic Oil and Gas Resources. National Pollutant Discharge Elimination System. National Petroleum Reserve—Alaska. North Slope Borough. Notice to Lessees and Operators. Outer Continental Shelf. Outer Continental Shelf Lands Act. Ocean Discharge Criteria Evaluations. Office of Information and Regulatory Affairs. Office of Management and Budget. Office of Natural Resources Revenue. Oil Spill Response Plan. Permanent Fund Dividend. Paperwork Reduction Act. pounds per square inch per foot. Regulation Identifier Number. Remotely Operated Vehicle. Recommended Practice. Source Control and Containment Equipment. Secretary of the Interior. Secretary’s Orders. Safety and Environmental Management Systems. Subsea Isolation Device. Same Season Relief Well. Suspensions of Operations. Technology Assessment Program. Trans-Alaska Pipeline System. Trillion Cubic Feet. Unfunded Mandates Reform Act of 1995. United States. U.S. Coast Guard. U.S. Fish and Wildlife Service. United States Geological Survey. Barrow. Worst Case Discharge. NPDES ................................................ NPR–A ................................................ NSB ..................................................... NTL ...................................................... OCS ..................................................... OCSLA ................................................ ODCE .................................................. OIRA ................................................... OMB .................................................... ONRR .................................................. OSRP .................................................. PFD ..................................................... PRA ..................................................... psi/ft ..................................................... RIN ...................................................... ROV ..................................................... RP ....................................................... SCCE .................................................. Secretary ............................................. S.O. ..................................................... SEMS .................................................. SSID .................................................... SSRW .................................................. SOO .................................................... TAP ..................................................... TAPS ................................................... TCF ..................................................... UMRA .................................................. U.S. ..................................................... USCG .................................................. USFWS ............................................... USGS .................................................. Utquiavik .............................................. WCD .................................................... I. Background A. Overview of the Alaska Arctic Region jbell on DSKJLSW7X2PROD with PROPOSALS2 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 VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 the Prudhoe Bay State #1 well. BP Exploration drilled a confirmation well the following year. However, production did not come online until June 20, 1977, after the TAPS was completed and other companies with lease holdings in the area undertook a host of activities to delineate the reservoir, resolve equity participation, and put together initial infrastructure for the field. After over 40 years of production, Prudhoe Bay remains the largest oil field in North America and is the 18th largest field ever discovered worldwide.3 According to data maintained by the Alaska Oil and Gas Conservation Commission, Alaska’s North Slope has produced over 17.3 billion barrels of oil, with Prudhoe Bay contributing approximately 68 3 https://dec.alaska.gov/spar/ppr/response/sum_ fy06/060302301/factsheets/060302301_factsheet_ PB.pdf. PO 00000 Frm 00005 Fmt 4701 Sfmt 4702 percent of that amount.4 Currently, the only offshore Federal production in the Arctic OCS 5 is Hilcorp’s Northstar field, which includes both State and Federal acreage in the 8(g) Zone.6 Located in the Beaufort Sea about 12 miles northwest of Prudhoe Bay, this prospect has been producing since 2001. Over 150 million barrels of oil have been produced to date at Northstar. In 2019, the Federal Government received nearly $5 million in royalty payments from oil production on Federal leases at Northstar, and from 2003 to 2018, royalty payments ranged 4 https://aogweb.state.ak.us/DataMiner3/Forms/ Production.aspx. 5 There are Federal OCS leases that do not have ongoing production in the Cook Inlet, which is not considered part of the Arctic. 6 Section 8(g) of the OCSLA requires the Federal Government to share with the State of Alaska 27% of revenue from leases in the 8(g) Zone (the first three nautical miles of the Outer Continental Shelf). 43 U.S.C. 1337(g). E:\FR\FM\09DEP2.SGM 09DEP2 79270 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules jbell on DSKJLSW7X2PROD with PROPOSALS2 from $3 million to over $20 million in any given year. In 2019, the Federal Government disbursed just over $1.5 million to the State of Alaska for Northstar Federal leases in the 8(g) Zone.7 The construction of TAPS enhanced the significance of the Arctic’s production to the State of Alaska. TAPS is an 800-mile-long pipeline system that was designed to accommodate the transport of over 2 million barrels of oil per day. The pipeline begins at Prudhoe Bay and stretches south to Valdez in southern Alaska, which is the northernmost ice-free port in North America. TAPS is one of the world’s largest pipeline systems, an engineering icon that was the biggest privately funded construction project when it was constructed in the 1970s. At peak flow in 1988, 11 pump stations helped to move 2.1 million barrels of oil a day.8 2. Budgetary Economic Impact on the People of Alaska North Slope Alaska oil and gas exploration and production has been a significant economic driver, not only to the State of Alaska and Alaskan Native communities, but also to the national domestic energy supply. The State’s oil and gas endowments have provided greater economic prosperity to its people than other important resources in the State. Specifically, Alaska relies on revenues generated from oil and gas resources, along with other revenuegenerating streams, to fund a major portion of the State’s operating and capital budgets. This has allowed Alaska to be the only State in the United States that does not have either a State sales tax or personal income tax. Oil and gas revenues are generated by means of a variety of taxes, royalties, and other charges related to oil and gas development and production. Other examples of revenue-generating streams for Alaska include corporate income, fuel, alcohol, and tobacco taxes. In 2016, 72 percent of Alaska’s unrestricted general funds, which come from the State’s overall revenue-generating stream, were derived from oil and gas revenues and were available to the State’s budget.9 In 2012, as much as 93 percent of Alaska’s unrestricted general funds were derived from oil and gas revenues and were also available to the State’s budget.10 The reduced contribution of oil and gas-generated 7 https://revenuedata.doi.gov/downloads/ disbursements/. 8 https://www.alyeska-pipe.com/TAPS. 9 https://www.legfin.akleg.gov/, Budget History Data (Excel) (posted 1–15–2020), Row 59. 10 https://www.legfin.akleg.gov/, Budget History Data (Excel) (posted 1–15–2020), Row 55. VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 revenue to the State’s budget since 2012 is due primarily to declining oil production in the North Slope, but also due to a general downward trend in oil prices. Aside from annual State operating and capital budgets, several Statewide government programs established for the benefit of the people of Alaska are largely dependent on oil and gas-related revenues, most notably the Alaska Permanent Fund. In 1976, Alaska’s State constitution was amended to establish the Alaska Permanent Fund, which provides that at least 25 percent of all mineral lease rentals, royalties, royalty sale proceeds, Federal mineral revenue sharing payments, and bonuses received by the State are to be placed in a permanent fund, known as the Alaska Permanent Fund, the principal of which is used only for income-producing investments. All income generated from the permanent fund is available for distribution to all Alaskan residents— adults and children—on an annual basis through the State’s Permanent Fund Dividend (PFD) program.11 Since 1978, this fund has grown to a total fund value of $60 billion as of March 2020.12 Individual distributions to Alaskans from the fund have ranged from $386 per person to as high as $2,072 per person.13 These annual payments are estimated to have lifted between 15,000 and 25,000 Alaskans above the Federal poverty line.14 Much of the North Slope Borough’s economy is tied to the oil and gas industry, primarily in the greater Prudhoe Bay region. Some borough residents have rotational work in the oilfields or in a position supporting the oil industry, but the greatest contribution to the economy is through tax revenue. The borough assesses property taxes on infrastructure, the primary funding source for the borough’s operations and capital projects, which include building roads, operating schools, and funding for other public services, such as health clinics and fire departments.15 In March and April of 2020, global oil prices experienced significant volatility 11 https://apfc.org/frequently-asked-questions/ #why-did-alaskans-create-the-fund. 12 https://apfc.org/our-performance/. 13 https://pfd.alaska.gov/Division-Info/Summaryof-Applications-and-Payments. 14 Berman, Matt., Random Reamy. ‘‘Permanent Fund Dividends and Poverty in Alaska.’’ Institute of Social and Economic Research, University of Alaska Anchorage. (November 2016), available online at: https://iseralaska.org/static/legacy_ publication_links/2016_12-PFDandPoverty.pdf. p. 25 of pdf. 15 https://www.north-slope.org/assets/images/ uploads/13_Economic_Development_-_NSB_ Comprehensive_Plan.pdf. PO 00000 Frm 00006 Fmt 4701 Sfmt 4702 due to a confluence of events, including decreased demand from coronavirus effects, as well as production output negotiations between OPEC and Russia. These events caused the price of oil to slide to 17-year lows. While prices have already partially recovered and stabilized, this could affect interest and activity in the region if the low-price environment continues into the future, as drilling and other exploration activities in the Arctic are more expensive than other regions. Given the long period of time before exploratory drilling in the Arctic is expected to start and the short-term nature of the underlying price events, the Bureaus expect that prices will continue to rebound. The events in 2020 also underscore the importance of ensuring that BOEM and BSEE regulations are no more burdensome than necessary to protect safety and the environment. 3. Arctic Resource Potential and Geology The Arctic region is characterized by its extensive oil and gas resources. The Arctic Alaska Petroleum Province, which consists of up to 43 geologic plays between the Chukchi Sea and the Beaufort Sea planning areas, extends about 684 miles from the United StatesCanadian border westward to the maritime boundary with Russia, and from 62 to 372 miles northward from the Brooks Range to the approximate edge of the Continental Shelf. Although the edge of the Continental Shelf provides a well-defined physiographic boundary for the province, this edge does not represent a geologic limit to potential petroleum resources. The offshore part of the province is characterized by a relatively narrow (62mile-wide) shelf in the Beaufort Sea and a broad (372-mile-wide) shelf in the Chukchi Sea. The province is bounded onshore on the south by the Brooks Range-Herald mountain range and offshore to the north by the passive continental margin of the Canada Basin.16 In general, the formations are fairly continuous across the Arctic Alaska Petroleum Province. Although most of the Arctic’s oil production to date is attributed to the North Slope, most of the undiscovered resources are located off the Arctic coast, within the Chukchi Sea and Beaufort Sea Planning Areas. According to BOEM’s 2016 Assessment of Undiscovered Technically Recoverable Oil and Gas Resources of the Nation’s 16 Houseknecht, D.W., and Bird, K.J., 2006, Oil and gas resources of the Arctic Alaska petroleum province: U.S. Geological Survey Professional Paper 1732–A, 11 p., available online at: https:// pubs.usgs.gov/pp/pp1732/pp1732a/. E:\FR\FM\09DEP2.SGM 09DEP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules OCS (mean estimates available at https:// www.boem.gov/National-Assessment2016/), there are approximately 23.6 billion barrels of undiscovered technically recoverable oil and about 104.4 trillion cubic feet (TCF) of technically recoverable natural gas (mean estimates) in the combined Beaufort Sea and Chukchi Sea Planning Areas. BOEM re-assessed its Beaufort Sea Planning Area estimates due to recent onshore discoveries in the National Petroleum Reserve-Alaska (NPR–A) from two formations that extended offshore. In December 2017, BOEM published its updated reassessment (mean estimates available at https://www.boem.gov/2016a-NationalAssessment-Fact-Sheet/), which estimated that there are approximately 24.3 billion barrels of technically recoverable oil and about 104. TCF of technically recoverable natural gas in the combined Beaufort Sea and Chukchi Sea Planning Areas; an increase of about 680 million barrels of oil and 100 billion cubic feet of natural gas. Of the 24.3 billion barrels of oil, the Chukchi Sea Planning Area makes up about 63% of the estimate, while the Beaufort Sea Planning Area makes up 37%. With respect to gas, the Chukchi Sea Planning Area makes up about 73% of the 104.5 TCF of gas and the Beaufort Sea Planning Area makes up 27% of the estimate. These estimates represent about one-quarter of the technically recoverable oil resources and one-third of the technically recoverable gas resources on the OCS. While not as large, the Arctic’s onshore undiscovered oil and gas resources are also considerable. In January 2020, the United States Geological Survey (USGS) published an assessment of undiscovered oil and gas resources in the central portion of the Alaska North Slope, (mean estimates available at https://pubs.usgs.gov/fs/ 2020/3001/fs20203001.pdf). The assessment estimated that there are approximately 3.6 billion barrels of undiscovered technically recoverable oil and about 8.9 TCF of undiscovered technically recoverable natural gas resources on State and Native lands, and State waters, east of the NPR–A and west of the Arctic National Wildlife Refuge (ANWR). According to a 2017 USGS assessment of undiscovered oil and gas resources in the Alaska North Slope, (mean estimates available at https://pubs.usgs.gov/fs/2017/3088/ fs20173088.pdf), there are approximately 8.8 billion barrels of undiscovered technically recoverable oil and about 39 TCF of undiscovered technically recoverable natural gas in VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 the NPR–A. In addition, USGS’s assessment of the 1002 Area 17 of the ANWR estimated (mean estimates available at https://pubs.usgs.gov/of/ 2005/1217/pdf/2005-1217.pdf) there are 7.6 billion barrels of technically recoverable oil and 7.04 18 TCF of technically recoverable natural gas. Efforts are already underway to bring some of these new onshore resources online. Collectively, these offshore and onshore assets are enormous, and most of the resources are located offshore.19 However, the Arctic OCS’s vast potential has yet to be realized. In the Arctic, the circumstances associated with drilling from a MODU can be different than those in the Gulf of Mexico. The geological pressures in the hydrocarbon bearing zones in the shallow seas of Alaska’s Arctic are, in many cases, likely to be substantially lower than those encountered during the Deepwater Horizon incident, reducing certain risk factors of a major blowout. As reviewed by the NPC, through the NPC 2019 Report, subsurface conditions (below the seafloor) for the Arctic OCS—geology, pressure, resource depth, and drilling depth—are much simpler as compared to other areas, such as the deepwater Gulf of Mexico OCS. The NPC 2019 Report states that the targeted Arctic potential reservoirs are shallow and normally pressured, but that exploration and development are dominated by other challenges, such as water depth, ice conditions, and the length of the open-water season, which make the Arctic unique (NPC 2019 Report at 10). The NPC 2015 Report found, however, that most of the U.S. Arctic offshore conventional oil and gas potential can 17 The Alaska National Interest Lands Conservation Act (ANILCA) of 1980 required ANWR to be managed as a protected wilderness. Section 1002 of ANILCA, however, deferred a decision regarding future management of a 1.5 million-acre coastal plain portion of ANWR (known as the ‘‘1002’’ area) in order to continuously study the various natural resources on the coastal plain, and analyze how oil and gas exploration, development, and production could potentially impact those resources. Section 20001 of the Tax Cuts and Jobs Act of 2017 lifted a provision in Section 1003 of ANILCA that prohibits oil and gas leasing and production in the 1002 area, and the BLM is in the process of developing an oil and gas leasing program for that area. 18 This value represents the combined estimates of natural gas that could technically be produced from gas fields as well as associated gas that could be produced from oil fields. 19 D.L. Gautier et al., ‘‘Circum-Arctic Resource Appraisal: Estimates of Undiscovered Oil and Gas North of the Arctic Circle,’’ U.S. Geological Survey, USGS Fact Sheet 2008–3049, 2008. M.E. Brownfield et al., ‘‘An Estimate of Undiscovered Conventional Oil and Gas Resources of the World,’’ U.S. Geological Survey, USGS Fact Sheet 2012–3024, 2012, available at https://pubs.usgs.gov/fs/2008/ 3049/fs2008-3049.pdf. PO 00000 Frm 00007 Fmt 4701 Sfmt 4702 79271 be developed using existing fieldproven technology, which was reaffirmed by the NPC 2019 Report (NPC 2015 Report at 28). As identified by the NPC, targeted potential reservoirs in the Arctic OCS may be shallow and normally pressured.20 However, this condition is not consistent throughout all areas in the Arctic OCS that have already been explored. For example, a study published by the American Rock Mechanics Association 21 analyzed wells drilled in the Chukchi Sea in order to provide an improved interpretation and delineation of pore pressure in the Chukchi shelf region. A majority of the wells contained significant overpressure at depths ranging from 1,098 to 2,317 meters (i.e., 3,602 to 7,601 feet) subsea. In the Beaufort Sea, the Alaska Department of Natural Resources (ADNR) noted that, as part of its findings to support Beaufort Sea areawide oil and gas lease sales,22 operators may reasonably expect to encounter extremely high pore pressures along the central Beaufort Sea region where ‘‘ . . . Cenozoic strata (sedimentary layers) are very thick, such as in the Kaktovik, Camden, and Nuwuk Basins,’’ and suggests that challenges from over pressured areas could be reduced by ‘‘. . . identifying locations of overpressured sediments via seismic data analysis, and then adjusting the mud mixture accordingly as the well is drilled.’’ In the Point Thomson area, for example, where drilling has taken place from an onshore facility into a reservoir located primarily offshore, the pore pressure gradients were measured as high as 0.8 pounds per square inch per foot (psi/ft) at depths of 2.5 miles (13,200 feet). A pore pressure gradient of 0.433 psi/ft is considered normal in this area.23 20 ‘‘Normally pressured’’ is not defined in the NPC 2019 Report. However, as a general matter, normal pressure generally refers to the hydrostatic pressure within a well. ‘‘Normally pressured’’ refers to conditions present when formation pressures are predictable at any given depth and follow a normal formation pressure gradient or ‘‘hydrostatic pressure gradient.’’ Normal formation pressure, at any given depth, equals the normal formation pressure gradient multiplied by the depth. The normal pressure is expressed in pounds per square inch (psi). 21 Elowe, K.E., & Sherwood, K.W., 2017, ‘‘Abnormal Formation Pressure in the Chukchi Shelf, Alaska,’’ American Rock Mechanics Association Conference Paper, Document ID ARMA–2017–0194, available online at https:// www.onepetro.org/conference-paper/ARMA-20170194. 22 Alaska Department of Natural Resources, 2019, ‘‘Beaufort Sea Areawide Oil and Gas Lease Sales,’’ p. 3–20, available online at https://aws.state.ak.us/ OnlinePublicNotices/Notices/View.aspx?id=193811. 23 Craig, J.D., K.W. Sherwood, and P.P. Johnson. 1985. Geologic report for the Beaufort Sea planning E:\FR\FM\09DEP2.SGM Continued 09DEP2 79272 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules jbell on DSKJLSW7X2PROD with PROPOSALS2 While these reports’ findings do not fully align with the NPC’s findings, there are other sources of information confirming that, to a certain degree, typical geologic conditions in the Arctic OCS are normally pressured. For example, a BOEM report that studied the Chukchi Sea’s Burger gas discovery calculated the pore pressure gradient for one of the Chukchi Sea wells in the study to be 0.44 psi/ft up to 4,850 feet subsea, which the report determined to be normally pressured. However, beneath 4,850 feet, the pore pressure gradient became over-pressurized having a pore pressure gradient of 0.88 psi/ft.24 For the Beaufort Sea, a USGS report analyzed pressure data from five offshore wells and found that the pressures in the area where the wells were located were normally pressured (i.e., at hydrostatic pressure) up to 2,000 feet subsea, and increased only slightly above hydrostatic pressure deeper into the well. By 10,000 feet, however, the pressure in all five wells were overpressured, 1.5 times higher than the hydrostatic pressure.25 Over-pressure started to occur at around 6,700 feet subsea. While it is not possible to confirm that all targeted potential reservoirs would be shallow and normally pressured in all exploratory drilling situations, BSEE and BOEM will have access to the relevant geologic and geophysical information to help identify hydrocarbon bearing zones and zones with potential geologic risk, such as over-pressurized zones, that may be encountered during drilling operations. These higher pressured, hydrocarbon zones are, in fact, the targeted formations the industry has attempted to produce. For example, the BOEM report analyzing the Chukchi Sea’s Burger gas discovery illustrated the regional geology of all the wells included in the study, and showed that the higher pressured zones in the wells occurred at the same point where the area, Alaska: Regional geology, petroleum geology, environmental geology. U.S. Department of the Interior, Minerals Management Service, Alaska OCS Region, OCS Report MMS 85–0111. Anchorage, Alaska. https://www.boem.gov/BOEM-Newsroom/ Library/Publications/1985/85_0111.aspx. 24 Craig, J.D., & Sherwood, K.W., 2001 (revised 2004), ‘‘Economic Study of the Burger Gas Discovery, Chukchi Shelf, Northwest Alaska,’’ U.S. Department of the Interior, Minerals Management Service, p. 67, available online at https:// www.boem.gov/sites/default/files/boem-newsroom/ Library/Publications/2004/Economic-Study-of-theBurger-Gas-Discovery.pdf. 25 Hayba, D.O., Houseknecht, D.W., and Rowan, E., 1999, ‘‘Stratigraphic, Hydrogeologic, and Thermal Evolution of the Canning River Region, North Slope, Alaska,’’ U.S. Department of the Interior, U.S. Geological Survey, p. FF–21, available online at https://pubs.usgs.gov/of/1998/ofr-980034/FF.pdf. VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 oil-bearing zones were located.26 The Bureaus have the means, through access to relevant geological and geophysical (G&G) data and drilling application regulatory reviews, to confirm that operators identify and plan for these potential risks. For example, the bureaus confirm that operators have properly designed well casing and drilling programs and ensure that operators have access to properly designed equipment that is readily available to quickly respond to an incident, such as the availability of a capping stack in advance of drilling into the targeted productive zones. 4. Partnership With Alaska Natives in Northern Alaska The bowhead whale provides the largest subsistence resource available to the native villages of Alaska’s northern shores. In 1977, Eskimo whalers from these villages established the Alaska Eskimo Whaling Commission (AEWC), whose mission is to safeguard the bowhead whale and its habitat, defend the Aboriginal Subsistence Whaling Rights of their members, and preserve the cultural and traditional values of their villages. Eskimo whalers established the AEWC in response to actions taken by the International Whaling Commission (IWC) that resulted in the IWC’s assumption of direct jurisdiction over the Alaskan Native bowhead whale subsistence hunt, without Alaska Native input. The IWC assumed direct jurisdiction over Alaska Native’s bowhead whale subsistence in response to the IWC’s concerns regarding the decline in the western Arctic bowhead whale stock. The IWC’s only mechanism for protecting whale stocks is the setting of hunting quotas. Therefore, the IWC’s only recourse for addressing its concerns was to prohibit the Alaska Native bowhead whale subsistence hunt. This action devastated local communities, creating immediate and severe food shortages. In response, in 1981, the AEWC was able to establish an agreement with the Federal Government to co-manage the bowhead whale hunting quotas. Although the AEWC was able to regain control of its bowhead whale hunting quotas, the organization shared a similar concern with the IWC regarding the potential effects of 26 Craig, J.D., & Sherwood, K.W., 2001 (revised 2004), ‘‘Economic Study of the Burger Gas Discovery, Chukchi Shelf, Northwest Alaska,’’ U.S. Department of the Interior, Minerals Management Service, p. 72, available online at https:// www.boem.gov/sites/default/files/boem-newsroom/ Library/Publications/2004/Economic-Study-of-theBurger-Gas-Discovery.pdf. PO 00000 Frm 00008 Fmt 4701 Sfmt 4702 offshore oil exploration and development on the bowhead whale. Whalers observed how bowhead whales were responding to the presence of ocean-going oil and gas industry exploration vessels, which were making the whales skittish and affecting the whalers’ ability to effectively meet the quotas for their communities. In response, the AEWC worked with industry stakeholders to establish the ‘‘Oil/Whaler Agreement,’’ which was a communication plan between whalers and exploration vessels that was intended to prevent direct threats to the whalers’ safety from industry vessels. The AEWC and industry stakeholders eventually turned the ‘‘Oil/Whaler Agreement’’ into a framework for understanding and addressing indirect interference with hunting activities, resulting from behavioral changes in bowhead whales as they react to the noise and other pollutants accompanying oil and gas work. This framework of understanding eventually formed the basis of what is now known as a CAA.27 While DOI does not require executing a CAA, BSEE and BOEM highly encourage operators to work with the AEWC to establish CAAs, since these agreements essentially acknowledge, within CAA provisions, that both subsistence hunting activities and oil and gas development can and should coexist. See discussion in Section I.E.3, History and Background on the Conflict Avoidance Agreement, of this preamble describing the provisions typically included in a CAA. This longstanding process allows for industry representatives to sit, in council, with members of the AEWC, local tribes, and village and regional corporations to determine cultural circumstances and situations that could cause conflict—and thus avoid them. For example, during whale (or walrus) hunting seasons in the spring and fall, the CAA may include provisions whereby industry will avoid construction or production noise and related activities during those times when whales are transiting nearby, and the hunters are in the area. With this early initiative, direct collaboration with local hunters, specifically the whaling captains and their representative organization, the AEWC, became a critical element of offshore industrial development planning and management in the Alaskan Arctic. Today, the AEWC includes registered whaling captains and their crews from eleven whaling communities of the 27 Conflict Avoidance Agreements are contracts signed by the operators and the Alaska native communities to which BOEM is not a party. E:\FR\FM\09DEP2.SGM 09DEP2 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules Arctic Alaska coast: Gambell, Savoonga, Wales, Little Diomede, Kivalina, Point Hope, Point Lay, Wainwright, Barrow 28 (Utquiavik), Nuiqsut, and Kaktovik. The AEWC often represents the Inupiat Community of the Arctic Slope (ICAS) in matters pertaining to energy exploration or development specifically for the OCS. The ICAS is a unique federally recognized tribal entity. ICAS membership is based on an individual’s ancestral lineage to a village tribe; it includes the peoples of eight Native Villages: Kaktovik, Atqasuk, Nuiqsut, Anaktuvuk Pass, Barrow, Wainwright, Point Lay, and Point Hope. Each village tribe acts independently but will interact with ICAS and its membership as it relates to Federal and State energy issues. Conflict avoidance tools are often incorporated into leasing stipulations addressing consultation with subsistence communities, and will continue to be essential to help satisfy the need to provide a secure source of energy for the Nation while at the same time protecting the subsistence resources and uses of the local communities where these energy resources are located. 5. Industry Interest in the Arctic OCS In 1979, a year after the first Arctic offshore discovery (i.e., the Endicott oil field) was made in State waters, the Department, acting through the Bureau of Land Management (BLM), held the first oil and gas lease sale in the Arctic OCS, offering tracts adjacent to Prudhoe Bay in the Beaufort Sea Planning Area. That sale resulted in 24 leases, covering 85,776 acres, being issued. Although it was the first sale ever conducted for the Arctic OCS, the revenues generated from that sale, over $491 million, make it the 4th largest sale in Arctic OCS history. That dollar amount would represent almost $1.9 billion dollars in 2019 after adjusting for inflation. Between 1979 and 2008, the Department, acting through the BLM and Minerals Management Service (MMS),29 held 13 oil and gas lease sales, and issued nearly 1,800 leases, covering over 9.7 million acres, on the Arctic OCS. These sales generated over $6.8 billion in bonus bids. As many as 23 companies/bidders have participated in an Alaska OCS lease sale and, while the number of companies/bidders participating from one sale to the next varied, an average of 10 companies/ bidders participated in each sale. By 2008, U.S. oil production had been steadily declining for 5 years to an average of 5 million barrels per day, while U.S. consumption of crude oil and petroleum products reached an alltime high of 20.68 million barrels per 79273 day.30 The price of oil increased steadily through 2007 from approximately $50 to $90 per barrel by the time the most recent Arctic sale, Lease Sale 193, was held in February of 2008.31 These market factors may have contributed to the outcome of Lease Sale 193, one of the most successful in Arctic OCS history, based on multiple metrics—the number of bids received, the number of tracts receiving bids, and the total amount of bonus bids received from the sale. The MMS received a total of 667 bids on 488 blocks; both record-setting numbers for the Arctic OCS. A total of 487 leases, covering over 2.7 million acres, were issued, and the sale generated over $2.6 billion in bonus bids, which went to the U.S. Treasury. Since 2008, however, the Department has not conducted any new lease sales for the Arctic OCS. A description of the status of active leases in the Artic OCS is discussed in further detail below within this subsection, prior to the subheading entitled, Global Arctic Exploration Activities. Sale 193 was significant, not only in number of tracts sold and the amount received from the sale, but in that the industry’s interest spurred a flurry of activities on the Arctic OCS prior to and after the sale. The following table lists those activities: 2006 June 20 .............. MMS authorizes ConocoPhillips, Shell, and GX Technology Corporation to conduct geophysical operations for a portion of Chukchi Sea Planning Area, which covered the Sale 193 area. 2007 July 13 ............... MMS authorizes Shell to conduct additional geophysical operations in Chukchi Sea Planning Area covering the same area as their 2006 geophysical permit. 2008 February 6 ......... February 15 ....... MMS holds Chukchi Sea Lease Sale 193. Seven companies were issued leases from this sale—NACRA; Repsol; Shell; ConocoPhillips; Eni Petroleum; StatoilHydro; and Iona Energy Company. MMS authorizes Shell to conduct even further geophysical operations, also covering the same area as their 2006 geophysical permit. 2009 May 9 ................ Shell submits its initial EP for the Chukchi Sea. 2010 jbell on DSKJLSW7X2PROD with PROPOSALS2 April 10 ............. May 19 .............. June 18 .............. August 8 ............ BP Deepwater Horizon Incident—Blowout of the Macondo well (Gulf of Mexico). Secretary’s Order 3299 reorganizing the Minerals Management Service and dividing its functions between three separate bureaus. Secretary’s Order 3302 creating the Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE). BOEMRE authorizes Statoil to conduct geophysical operations within and around the area where their leases were located in the Chukchi Sea Planning Area. 28 Although the Alaska Native tribe is based in Utquiavik, at any given time, the whaling may involve members of the Apugauti and Nalukatq tribes, whose native lands do not border the coast. For this reason, the AEWC prefers to refer to this VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 group of whaling captains collectively by the broader term ‘‘Barrow.’’ 29 MMS was the predecessor agency of BSEE and BOEM. 30 https://www.eia.gov/dnav/pet/hist/ LeafHandler.ashx?n=PET&s=MTTUPUS2&f=A, PO 00000 Frm 00009 Fmt 4701 Sfmt 4702 table entitled, ‘‘U.S. Product Supplied of Crude Oil and Petroleum Products (Thousand Barrels per Day)’’. 31 https://www.eia.gov/dnav/pet/hist/ LeafHandler.ashx?n=PET&s=F000000__3&f=M. E:\FR\FM\09DEP2.SGM 09DEP2 79274 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules December 7 ....... BOEMRE conditionally approves Shell’s initial EP for the Chukchi Sea. 2011 May 11 .............. August 29 .......... December 16 ..... Shell submits a revised EP for the Chukchi Sea. Secretary’s Order 3299 was amended to divide BOEMRE into the Bureau of Ocean Energy Management (BOEM), the Bureau of Safety and Environmental Enforcement (BSEE), and the Office of Natural Resources Revenue (ONRR). BOEM conditionally approves Shell’s revised EP for the Chukchi Sea. 2012 August 30 .......... September 9 ...... September 20 .... October 3 ........... BSEE authorizes Shell to initiate certain limited preparatory exploration drilling activities; drilling of the top hole for Burger A exploration well in the Chukchi Sea. Shell begins drilling operations for its Burger A exploration well in the Chukchi Sea, but was not able to complete its well operations. Shell returned in 2016 to complete its well operations, ultimately plugging and abandoning the well. While not applicable to the Chukchi Sea, BSEE also authorizes Shell to initiate drilling of the top hole for the Sivuliq N exploration well in the Beaufort Sea. Shell begins drilling operations for its Sivuliq N exploration well in the Beaufort Sea, but was not able to complete its well operations. Shell returned in 2016 to complete its well operations, ultimately plugging and abandoning the well. 2013 August 5 ............ November 6 ....... BOEM authorizes TGS to conduct geophysical operations for a portion of Chukchi Sea Planning Area covering a portion of the Sale 193 area. Shell submits a revised EP for the Chukchi Sea in response to lessons learned from its 2012 drilling operations of the Sivuliq N and Burger A exploration wells. 2014 August 28 .......... Shell submits a revised EP for the Chukchi Sea, replacing its November 2013 submission. 2015 January 21 ......... January 27 ......... February 24 ....... May 11 .............. July 22 ............... July 31 ............... September 21 .... October 16 ......... President Obama signed E.O. 13689, which calls for multiple agencies that may have jurisdictional responsibilities in the Arctic to enhance their coordination efforts to protect the nation’s various interests in the region. President Obama issues Presidential Memorandum withdrawing certain areas of the OCS within the Beaufort and Chukchi Seas from leasing. These areas included the Hannah Shoal in the Chukchi Sea and lease deferral areas identified in BOEM’s 2012–2017 National OCS Oil and Gas Leasing Program. BSEE and BOEM published the 2015 Proposed Arctic Exploratory Drilling Rule, providing a 90-day period for the public to review and comment on the proposed rule. BOEM conditionally approves Shell’s revised EP for the Chukchi Sea. BSEE authorizes Shell to initiate certain limited preparatory exploration drilling activities; drilling of the top hole for Burger J exploration well in the Chukchi Sea. Shell begins drilling operations for its Burger J exploration well in the Chukchi Sea. Shell completes its Burger J exploration operations, and ultimately plugs and abandons the well. The Department cancels all Beaufort and Chukchi lease sales that were scheduled to take place as part of BOEM’s 2012– 2017 National OCS Oil and Gas Leasing Program. 2016 jbell on DSKJLSW7X2PROD with PROPOSALS2 December 30 ..... President Obama issues a Presidential Memorandum that expands the withdrawal to all areas of the Chukchi Sea planning area and much of the Beaufort Sea planning area that were not currently withdrawn at that time. The withdrawal excludes Beaufort tracts located nearshore in an area that included existing leases at the time. A key factor that contributed to the length of time taken to authorize Shell’s exploration drilling activities was a lawsuit filed by the Native Village of Point Hope challenging the Department’s decision to hold Sale 193. See Native Village of Point Hope v. Salazar, 730 F. Supp.2d 1009 (D. Ak., 2010); see also Native Village of Point Hope v. Jewell, 740 F.3d 489 (9th Cir., 2014). The original Environmental Impact Statement (EIS) for Sale 193 was published in 2007, and the lease sale was held, but subsequent legal challenges and Federal court decisions remanded the lease sale to BOEM for further analysis. In response to the court remand, BOEM conducted additional analysis and incorporated that VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 information into a Supplemental EIS that was published in February 2015 and affirmed the sale as held. Only thereafter were BOEM and BSEE able to complete their formal review of Shell’s exploration plan for the Chukchi Sea and approve the drilling activities that took place in the summer of 2015. Between 2008 and 2019, oil prices remained unstable, increasing to an alltime high of almost $96 per barrel in 2013 to $44 per barrel in 2015, which increased to $56 per barrel in 2019.32 Domestic oil production had grown since 2008, in part due to developments in tight oil onshore and Gulf of Mexico production, to about 9.4 million barrels 32 https://www.eia.gov/dnav/pet/hist/ LeafHandler.ashx?n=PET&s=F000000__3&f=M. PO 00000 Frm 00010 Fmt 4701 Sfmt 4702 per day in 2015 and 12.2 million barrels in 2019.33 Demand for oil remained relatively stable between 2008 and 2019, with only a minor increase in 2019 over 2008—approximately a 4% increase.34 On September 28, 2015, Shell announced that it would cease further exploration activity in offshore Alaska for the foreseeable future. Shell stated that its decision was based on the results of their Burger J well, which found indications of oil and gas, but were insufficient to warrant further 33 https://www.eia.gov/todayinenergy/ detail.php?id=4910. 34 https://www.eia.gov/dnav/pet/hist/ LeafHandler.ashx?n=PET&s=MTTUPUS2&f=A, table titled ‘‘U.S. Product Supplied of Crude Oil and Petroleum Products (Thousand Barrels per Day). E:\FR\FM\09DEP2.SGM 09DEP2 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules jbell on DSKJLSW7X2PROD with PROPOSALS2 exploration in the Burger prospect. The company also stated that its decision was motivated by the high costs associated with the project, and the challenging and unpredictable Federal regulatory environment offshore Alaska.35 On November 17, 2015, Statoil announced its decision to exit Alaska and relinquish its leases acquired from Sale 193. All leaseholders that acquired leases in Sale 193 eventually relinquished their leases. Despite these setbacks, industry interest in the Arctic OCS and other areas of the Arctic, globally, has shown to be consistent amidst fluctuating commodity prices and concerns about regulatory challenges. Since 1998, nineteen geological and geophysical seismic surveys were permitted and completed for the Beaufort Sea and Chukchi Sea Planning Areas. The data from these surveys provide information to both industry and the government for use in lease sales and for design and evaluation of activities described in EPs and DPPs. Several different companies participated in each of the four Beaufort Sea Planning Area lease sales and the one Chukchi Sea Planning Area lease sale indicating on-going industry interest in the area. Companies submitted EPs, three in the Beaufort and one in the Chukchi Sea. These plans, and their revisions, received evaluation and conditional approval. BOEM approved two DPPs, both for the Beaufort Sea. Currently, there are 19 oil and gas leases in the Arctic OCS, all of which are located in the Beaufort Sea Planning Area. Exploratory drilling and development on these leases have taken place from gravel islands in State waters. Global Arctic Exploration Activities In addition to the Arctic OCS activities just described, global interest and development has taken place in other parts of the Arctic. Countries, such as Russia, Norway, Canada, and Greenland have been diligently exploring their oil and gas resources in or near the Arctic. Greenland—Since the 1970s, exploration activities have taken place on the offshore waters of western Greenland. While these exploration activities have taken place in sub-Arctic regions, operators do experience some of the key challenges present in the Arctic. It is not uncommon for icebergs to pose dangers to drilling operations. Operators use ice management plans to identify, monitor, and tow away any 35 https://www.shell.com/media/news-and-mediareleases/2015/shell-updates-on-alaskaexploration.html. VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 icebergs that may impact their exploration operations. Operators also have contingency plans that may require disconnecting their drilling rig from the well and moving off location to avoid contact with icebergs. Canada—In the Jeanne d’Arc, Orphan, and Flemish Pass oil and gas basins on the Grand Banks of Newfoundland, operators have conducted exploration drilling from MODUs in shallow and deep waters. Like Greenland, the areas with oil and gas potential are located in sub-Arctic regions that experience some seasonal sea ice and significant iceberg incursions. In these areas, operators also employ strong ice management and contingency plans. Norway—In Norway’s portion of the Barents Sea, which is located entirely within the Arctic, exploration activities have taken place since 1980. Most of the area is free of sea ice year-round, but drilling has taken place in areas that do experience challenging Arctic OCS conditions. As late as 2014, exploration drilling took place in Norway’s northern portion of the Barents Seas in what is known as the Hoop area. Those exploration operations entailed the use of winterized semisubmersible rigs and the availability of a capping stack. Russia—Russia’s latest drilling operations also took place in 2014 when ExxonMobil drilled a well in the South Kara Sea. The operation took place in an area of the Arctic where drilling could not take place during the winter months, similar to the Chukchi and Beaufort Seas. Exploration activities took place during the summer, when little to no sea ice was present at the drilling location and were completed in mid-fall. The operation was similar to the operations from the other countries just described—a winterized MODU and robust ice management and contingency plans. However, unique to this project was the use of a subsea isolation device (SSID). (NPC Report 2015 at 6–17 and 6–18, and NPC Report 2019 at C–10). The Kara Sea project is discussed in more detail below in Section II. Sectionby-Section Discussion of Proposed Changes, Subsection A. Key Revisions Proposed by BSEE, under the subheading entitled, Supplemental Assessment to the 2015 Report on Arctic Potential: Realizing the Promise of U.S. Arctic Oil and Gas Resources (NPC 2019 Report). Global Arctic Exploration Requirements Norway, Canada, and Greenland have similar regulatory requirements to the United States for Arctic offshore drilling operations performed from a MODU. The Bratslavsky and SolstenXP study also included a review of the regulatory PO 00000 Frm 00011 Fmt 4701 Sfmt 4702 79275 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 E:\FR\FM\09DEP2.SGM 09DEP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 79276 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules restructured and divided the former MMS’s responsibilities under OCSLA among three new bureaus: (i) BOEM; (ii) BSEE; and the (iii) Office of Natural Resources Revenue (ONRR). S.O. 3299 delegated those responsibilities for oil and gas operations to BSEE and BOEM, both of which are charged with administering and regulating aspects of the Nation’s OCS oil and gas program (see 30 CFR parts 250 and 550). On June 18, 2010, Secretary Salazar issued S.O. No. 3302, which announced the name change of part of the former MMS to the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE). This name, BOEMRE, would remain in effect until BOEM and BSEE were officially created under S.O. 3299, effective October 1, 2011. On October 1, 2010, the revenuecollection functions of the former MMS were transferred to ONRR, reporting to the Assistant Secretary for Policy, Management and Budget. S.O. 3299 assigned BOEM the responsibility for managing the development of the Nation’s offshore conventional and renewable energy resources. BOEM’s mission is to manage the development of the OCS energy and mineral resources in an environmentally and economically responsible way. BOEM’s functions include: Leasing; EP administration; DPP administration; permitting of geological and geophysical activities; environmental analyses in compliance with NEPA; environmental studies; compliance with relevant laws (e.g., the Endangered Species Act (ESA), the Marine Mammal Protection Act, the Magnuson-Stevens Fishery Conservation and Management Act, and the Coastal Zone Management Act 36 (CZMA)); resource evaluation; oil spill worst case discharge (WCD) determination; economic analysis and fair market value bid/lease evaluations; management of the OCS renewable energy and marine mineral programs; and consultation with other entities at the local (e.g., North Slope Borough, Native Villages), tribal (e.g., Federally recognized tribes and Alaska Native Claims Settlement Act Corporations), State, and Federal levels (e.g., National Oceanic and Atmospheric Administration (NOAA) Fisheries, U.S. Coast Guard (USCG)) related to 36 BOEM is not subject to the requirements of the CZMA in Alaska as it is on the rest of the OCS, where it is required to provide opportunities to the coastal State to review the proposed Federal actions for consistency with the state’s federally approved coastal management program. More specifically, on July 1, 2011, Alaska repealed its CZMA program. VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 activities within BOEM’s activities and areas of responsibility. Secretary’s Order 3299 made BSEE responsible for safety and environmental enforcement functions, including, but not limited to, the authority to permit activities, inspect, investigate, summon witnesses and produce evidence: Levy penalties; cancel or suspend activities; and oversee safety, and oil spill response and removal preparedness. BSEE’s mission is to promote safety, protect the environment, and conserve resources through vigorous regulatory oversight and enforcement. BSEE’s functions include evaluating permit applications for post-lease oil and natural gas exploration and development activities on the OCS and conducting inspections to ensure compliance with laws, regulations, lease terms, and approved plans and permits. BOEM evaluates EPs, and BSEE, thereafter, evaluates Applications for Permits to Drill (APDs) and other permits and applications, to determine whether the operator’s proposed activities meet OCSLA’s standards and each Bureau’s regulations governing OCS exploration. Based on their respective evaluations, BSEE and BOEM will either approve the operator’s EP and APD, require the operator to modify its submissions, or disapprove the EP or APD (§ 250.410, How do I obtain approval to drill a well?). The review and approval of these activities is outlined below in the following section. 1. BOEM Approval of the EP As promulgated through the 2016 Arctic Exploratory Drilling Rule, § 550.204, When must I submit my IOP for proposed Arctic exploratory drilling operations and what must the IOP include?, requires that a lessee submit an IOP at least 90 days before filing an EP with BOEM, if that EP would involve exploration for oil and gas on the Arctic OCS. While the IOP is not subject to approval, the submission was intended to facilitate the prompt sharing of information among the relevant Federal agencies that may be involved in overseeing exploratory drilling operations conducted from MODUs. The operator may then submit an EP to BOEM for approval. An EP must include information such as a schedule of anticipated exploration activities, equipment to be used, the general location of each well to be drilled, and any other information deemed pertinent by BOEM (§§ 550.211 through 550.228). 2. BSEE Approval of the APD Approval of an EP does not, by itself, permit the operator to proceed with PO 00000 Frm 00012 Fmt 4701 Sfmt 4702 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 E:\FR\FM\09DEP2.SGM 09DEP2 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules jbell on DSKJLSW7X2PROD with PROPOSALS2 Drilling Rule ‘‘for consistency with the policy set forth in section 2 of E.O. 13795’’ and to prepare a report ‘‘summarizing the review and providing recommendations on whether to suspend, revise, or rescind the rule.’’ Consistent with E.O.s 13783 and 13795, and S.O. 3350, BSEE and BOEM reviewed the regulations promulgated through the 2016 Arctic Exploratory Drilling Rule and are proposing revisions to those regulations to reduce unnecessary burdens on industry while maintaining safety and environmental protection. D. Purpose and Summary of the Rulemaking BSEE and BOEM promulgated the 2016 Arctic Exploratory Drilling Rule based on experiences gained from Shell’s 2012 and 2015 Arctic operations, internal reviews conducted on potential oil and gas operations on the Arctic OCS, and concerns expressed by environmental organizations and Alaska Natives. Since publication of the 2016 Arctic Exploratory Drilling Rule, however, BSEE and BOEM have become aware of additional information informing and warranting the bureaus’ reconsideration of certain regulatory provisions promulgated through that rule. BSEE commissioned a Technology Assessment Program study (Bratslavsky and SolstenXP, 2018) that entailed a historical statistical analysis of recent Alaska Arctic OCS drilling seasons (5year period between 2012 and 2016), in which meteorology and physical oceanographic (‘‘metocean’’) and operational conditions would support the safe deployment of SCCE, the drilling of a relief well, or both. The study included a comprehensive review and gap analysis of U.S. and international regulations, standards, recommended practices, specifications, technical reports, and common industry methods regarding the safe deployment of SCCE, as compared to the effectiveness of drilling a relief well in Arctic conditions. The Bratslavsky and SolstenXP study determined that metocean conditions prevalent in the Chukchi Sea and Beaufort Sea (i.e., rough sea states and sea ice conditions, primarily) are key factors that limit the ability to safely deploy SCCE throughout the Arctic OCS. The study determined that, when operating in the presence of sea ice in the Chukchi Sea and the Beaufort Sea, there is a greater probability for safe relief well deployment versus SCCE deployment. When operating in open water conditions (i.e., those prone to rough sea states) in the Chukchi Sea, VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 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 PO 00000 Frm 00013 Fmt 4701 Sfmt 4702 79277 addressed by the 2016 Arctic Exploratory Drilling Rule, they are unique to the Arctic OCS and, therefore, are appropriate to address as part of this proposed rulemaking. BSEE and BOEM recognize that the 2016 Arctic Exploratory Drilling Rule addressed specific operational and environmental conditions that are unique to the Arctic OCS. While this proposed rule would leave most of the regulations promulgated by the 2016 rule unaltered, certain of these regulations are worth reconsidering to accommodate technological innovation and encourage energy exploration on the Arctic OCS. Based on the new scientific information gathered from the Bratslavsky and SolstenXP study, and global practical experience gained in recent years, as described in the NPC Reports, the bureaus believe that these proposed revisions reduce unnecessary regulatory burdens on stakeholders and increase the ability to review and apply advancing technological innovations, while ensuring safety and environmental protection. The following paragraphs briefly summarize the key elements of this proposed rule, which are more fully explained in Section II. Section-bySection Discussion of Proposed Changes of this preamble: 1. Seasonal Conditions SOO—The unique seasonal conditions in the Arctic make it difficult or physically impossible for operators to explore their leases for a significant portion of each year. To facilitate the proper development of Arctic leases in accordance with OCSLA sec. 5,37 BSEE proposes to add a new provision to its regulations that would provide those operators that are conducting drilling operations, but are prevented from completing those leaseholding operations due to seasonal constraints unique to the Arctic, with the opportunity to obtain an SOO. If granted, this type of SOO would suspend the running of the lease term and effectively extend the term of the affected lease by a period equivalent to the period of such suspension. This would provide operators that are otherwise ready and able to conduct drilling operations with additional time to diligently explore their leases, without facing lease expiration due to 37 OCSLA sec. 5 (as amended) provides in pertinent part: ‘‘The regulations prescribed by the Secretary . . . shall include . . . provisions . . . for the suspension . . . of any operation or activity . . . at the request of a lessee, in the national interest, [or] to facilitate proper development of a lease . . . and for the extension of any permit or lease affected by [such] suspension . . . by a period equivalent to the period of such suspension . . . .’’ 43 U.S.C. 1334(a)(1). E:\FR\FM\09DEP2.SGM 09DEP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 79278 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules interference by seasonal constraints unique to the Arctic. 2. Water-Based Mud and Cuttings— BSEE proposes to eliminate references to the Regional Supervisor’s discretionary authority to require the capture of water-based muds and cuttings in those cases where subsistence values might be impacted by such discharges. While not intended, BSEE understands that this reference created some uncertainty for the regulated industry, because it appeared to overlap with regulation by the Environmental Protection Agency (EPA) and, if implemented, might result in BSEE issuing requirements that contradict EPA’s requirements. 3. SCCE—BSEE would preserve the requirement for the operator to have access to its SCCE when drilling below or working below the surface casing. However, with respect to the capping stack, the Bureau proposes to provide an opportunity to the operator to adjust the point in time during operations when it must position its capping stack so that it is available to arrive at the well location within 24 hours after a loss of well control. The existing regulations also impose a positioning requirement on the cap and flow system, and containment dome—slightly different from the capping stack—‘‘positioned to ensure that it will arrive at the well location within 7 days after a loss of well control.’’ BSEE’s proposed changes to the positioning requirement for the cap and flow system and containment dome are discussed in more detail later in this paragraph. If the operator is able to demonstrate to BSEE, based on documentation it submits as part of its APD, that the operations it plans to conduct below the surface casing would not encounter any abnormally highpressured zones or other geological hazards before reaching the last casing point prior to penetrating a zone capable of flowing hydrocarbons in measurable quantities, then BSEE will allow the operator to delay its positioning of the capping stack until reaching that casing point. BSEE’s proposal to delay the positioning of the capping stack would be based on the documentation that the operator provides as well as any other available data and information. As previously mentioned, BSEE also proposes to eliminate the requirement for the operator to ensure that the containment dome and cap and flow system are positioned so as to arrive at the well location within seven days after a loss of well control. The Bratslavsky and SolstenXP study evaluated current industry methods and standards for deploying SCCE in Arctic OCS conditions, and determined that VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 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 PO 00000 Frm 00014 Fmt 4701 Sfmt 4702 documentation it submits as part of its APD, that the operations it plans to conduct below the surface casing would not encounter any abnormally highpressured zones or other geological hazards before reaching the last casing point prior to penetrating a zone capable of flowing hydrocarbons in measurable quantities, then BSEE will allow the operator to delay its staging of the relief rig until reaching that casing point. BSEE’s proposal to permit the delay of the staging of the relief rig will be based on the documentation that operator provides, as well as any other available data and information. In the relief rig and SSRW regulation, BSEE would also eliminate the reference to expected seasonal ice encroachment because the relevant timeframes for operations should be based on the capabilities of the operator’s rig and equipment to operate in the applicable ice conditions, rather than an absolute date. 5. Mudline Cellars—BSEE proposes to clarify the requirement for the operator, in areas of ice scour, to use a mudline cellar when drilling that is designed to minimize the risk of damage to the well head and wellbore. The existing regulation could be read to require the operator to use a mudline cellar in all cases, except when the operator can prove that the mudline cellar would present an operational risk, and that was not BSEE’s intent. This proposed change would make it clear that the operator has more flexibility to propose to employ alternate procedures or equipment instead of the mudline cellar under appropriate circumstances, as provided by the longstanding provisions of § 250.141, May I ever use alternate procedures or equipment?; not just when a mudline cellar would present an operational risk and if the operator is able to demonstrate that the alternate procedure or equipment would provide a level of safety and environmental protection that equals or surpasses the mudline cellar requirement. 6. IOP—BOEM proposes to eliminate the requirement that the operator submit an IOP because it requires submission of information that overlaps with that required in the EP and the IOP’s early information sharing is unnecessary in light of BOEM’s practice for reviewing and coordinating review of the EP. Consequently, the operator is already aware that it must plan for how it will reduce operational risks and address the challenges associated with operations on the Arctic OCS through its EP. E:\FR\FM\09DEP2.SGM 09DEP2 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules E. Partner Engagement in Preparation for This Proposed Rule jbell on DSKJLSW7X2PROD with PROPOSALS2 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, VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 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 PO 00000 Frm 00015 Fmt 4701 Sfmt 4702 79279 a commitment to consultation with tribes and recognition of their right to self-governance and tribal sovereignty. E.O. 13175, Consultation and Coordination with Indian Tribal Governments and DOI’s tribal consultation policy, which implements the E.O., provide for procedures for consultation with tribes when taking an action with tribal implications. DOI has extended its consultation policy to ANCSA corporations. Furthermore, BSEE and BOEM recently issued their own expanded tribal consultation guidance on August 20, 2019 and June 29, 2018, respectively. BSEE’s guidance (Bureau of Safety and Environmental Enforcement (BSEE) Tribal Consultation Guidance, August 20, 2019, available at https://www.bsee.gov/bsee-tribalguidance-2019) and BOEM’s guidance (BOEM Tribal Consultation Guidance, June 29, 2018, available at https:// www.boem.gov/Tribal-Engagement/), identify various consultation authorities that BSEE and BOEM will follow in consulting with tribes and ANCSA corporations. DOI recognizes and respects the distinct, unique, and individual cultural traditions and values of Alaska Native people and the statutory relationship between ANCSA Corporations and the Federal Government. BSEE and BOEM will endeavor to go above and beyond their consultation responsibilities where and when appropriate throughout the rulemaking process to maintain a strong working relationship with their tribal and ANCSA corporation partners. BSEE and BOEM also received a comment from one of the ANCSA corporations recommending that this rulemaking take into account the NPC 2019 Report. BSEE and BOEM considered the NPC reports when preparing this proposed rule and based some of the proposed regulatory revisions on that report’s recommendations, as discussed more fully below. Another common comment that BSEE and BOEM received was a recommendation to include a requirement for a CAA between the oil and gas operator and those whaling communities potentially affected by an operator’s proposed drilling project. A CAA is typically established through a collaborative process whereby both parties work to create mitigation strategies that would avoid adverse impacts to bowhead whales and other marine mammals, their habitat, and hunting opportunities. Historically, operators have voluntarily used the CAA process and, currently, existing lessees are required to do so through E:\FR\FM\09DEP2.SGM 09DEP2 79280 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules jbell on DSKJLSW7X2PROD with PROPOSALS2 lease stipulations.38 See discussion in Section I.E.3, History and Background on the Conflict Avoidance Agreement, of this preamble describing the history and background of the CAA. In addition, under the MMPA, the taking of marine mammals without a permit or exception is prohibited in order to prevent the decline of species and populations. To avoid liability for take, operators must obtain an Incidental Take Authorization or Incidental Harassment Authorization for activities related to offshore exploration, development and production. Implementation of the MMPA is shared between NMFS and USFWS. Section 7(a)(2) of the ESA requires every Federal agency to ensure that any action they authorize, fund, or carry out is not likely to jeopardize the continued existence of a listed species or result in the adverse modification of designated critical habitat. When any exploration or development plan, or G&G permit application, is submitted to BOEM, BOEM evaluates the proposal, and consults with NMFS and USFWS on species listed under the ESA. During this process, mitigation measures (e.g., vessel speed restrictions, rig lighting specifications, and protected species observer requirements) are developed to reduce impacts to protected species. These measures are then included in BOEM’s conditions of approval for the EP, DPP, or G&G permit. BOEM did not include any regulatory changes in this proposed rule specifically designed to respond to this comment. BOEM cannot require whaling communities to establish agreements with operators, since BOEM has no jurisdiction over such 38 Every BOEM Arctic lease contains a variant of the following stipulation: ‘‘Prior to submitting an exploration plan or development and production plan (including associated oil-spill contingency plans) to MMS for activities proposed during the bowhead whale migration period, the lessee shall consult with the directly affected subsistence communities, Barrow, Kaktovik, or Nuiqsut, the North Slope Borough (NSB), and the AEWC to discuss potential conflicts with the siting, timing, and methods of proposed operations and safeguards or mitigating measures which could be implemented by the operator to prevent unreasonable conflicts. Through this consultation, the lessee shall make every reasonable effort, including such mechanisms as a conflict avoidance agreement, to assure that exploration, development, and production activities are compatible with whaling and other subsistence hunting activities and will not result in unreasonable interference with subsistence harvests. A discussion of resolutions reached during this consultation process and plans for continued consultation shall be included in the exploration plan or the development and production plan. In particular, the lessee shall show in the plan how its activities, in combination with other activities in the area, will be scheduled and located to prevent unreasonable conflicts with subsistence activities.’’ VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 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 PO 00000 Frm 00016 Fmt 4701 Sfmt 4702 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), E:\FR\FM\09DEP2.SGM 09DEP2 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules 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 jbell on DSKJLSW7X2PROD with PROPOSALS2 Subpart A—General Definitions. (§ 250.105) BSEE proposes to revise the definition of Capping Stack by deleting the phrase ‘‘including one that is pre-positioned’’ from the definition. BSEE included this phrase as part of the 2016 Arctic Exploratory Drilling Rule in response to a suggestion that the definition in the 2015 Arctic Proposed Rule should be expanded to allow pre-positioned capping stacks to be used below subsea BOPs when deemed technically and operationally appropriate. Recognizing that the comment was helpful, BSEE agreed with the suggestion and added the phrase ‘‘including one that is prepositioned’’ to the capping stack definition (see 81 FR 46492). As a practical matter, pre-positioned capping VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 stacks are similar to SSIDs. Accordingly, this modification in the 2016 final rule effectively allows the operator to install an SSID below a subsea BOP and would be in compliance with the capping stack requirement in the existing § 250.471, What are the requirements for Arctic OCS source control and containment? Existing § 250.471(a)(1), specifically requires the operator, when drilling below or working below the surface casing, to have access to a capping stack that is positioned to ensure that it will be able to arrive at the well location within 24 hours after a loss of well control. Typically, an operator would comply with this requirement by having one or more support vessels capable of handling and deploying the capping stack down to the subsea wellhead, when needed. Installing an SSID below the subsea BOP allows the operator to comply with § 250.471(a)(1) and forgo the need to provide support vessels and a capping stack on standby at the surface. However, BSEE is proposing to eliminate this language because a prepositioned capping stack is a piece of equipment that, as previously mentioned, aligns closely with an SSID. The Bureau is currently proposing distinct SSID requirements under § 250.472, What are the additional well control equipment or relief rig requirements for the Arctic OCS? This proposed revision would provide clarity concerning the capping stack requirements under § 250.471, specifically that installation of an SSID under § 250.472 does not constitute compliance with the capping stack requirements under § 250.471. For purposes of BSEE’s proposed regulations, an SSID is not considered to be the same as, or to satisfy the requirement to have, a capping stack. The new SSID option that BSEE is proposing under § 250.472 does not, and is not intended to, replace any of the SCCE requirements in proposed § 250.471(a), where BSEE’s capping stack requirement is addressed. When may the Regional Supervisor grant an SOO? (§ 250.175) BSEE proposes to revise § 250.175 by adding a new paragraph (d), which would allow an operator to request an SOO under certain situations that may be present in the Arctic OCS. This proposed revision is consistent with OCSLA’s requirement that the Secretary promulgate suspensions regulations that ‘‘facilitate proper development of a lease . . . .’’ 39 The proposed regulation 39 OCSLA sec. 5, as amended, codified at 43 U.S.C. 1334(a)(1). PO 00000 Frm 00017 Fmt 4701 Sfmt 4702 79281 would list the factors upon which BSEE may rely when determining whether to grant an SOO and include when an operator: (1) Has conducted operations on the lease during the drilling season immediately preceding the period for which the operator is seeking a suspension; (2) is drilling from: A MODU, an artificial gravel island or a gravity-based structure, or an artificial ice island; and (3) is not able to safely continue its operations due to the presence of seasonal ice, temporary seasonal drilling restrictions in its approved oil spill response plan, or seasonal temperature changes (respectively, for each facility type). Currently, BOEM issues Alaska OCS leases with the maximum 10-year primary lease term allowed under OCSLA.40 However, operators may be precluded from properly developing leases because it is not possible to conduct leaseholding operations for significant portions of those 10-year terms. Offshore drilling locations on the Arctic OCS are inaccessible for a significant portion of each year, due to seasonal changes that make operating conditions unsafe or otherwise preclude operations. Moreover, it is difficult to predict precisely when sea ice will persist or break-up. MODUs—For example, drilling operations performed from a MODU may occur only during the open-water drilling season (generally late June to early November), when sea ice is nonexistent or minimal. This practical limitation, without considering other logistical problems unique to the Arctic OCS, could mean that during a consecutive 10-year period, a lease may be unavailable for operations for approximately 70 percent of the time. Artificial Gravel Islands or Gravitybased Structures—Drilling from artificial gravel islands and gravitybased structures is prohibited during the spring/summer ice break-up and the fall/early winter freeze-up periods, because of the potential impact of weather and ice conditions on potential oil spill response and cleanup efforts. In particular, response and cleanup techniques for a large spill are not as effective when sea ice is broken and unconsolidated around the drilling location. By contrast, response and 40 OCSLA sec. 8, as amended, states in part: ‘‘An oil and gas lease issued pursuant [OCSLA] shall be for an initial period of (A) five years; or (B) not to exceed ten years where the Secretary finds that such longer period is necessary to encourage exploration and development in areas because of unusually deep water or other unusually adverse conditions . . . .’’ 43 U.S.C. 1337(b). E:\FR\FM\09DEP2.SGM 09DEP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 79282 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules cleanup efforts for a large oil spill from an artificial gravel island or a gravitybased structure could be executed effectively during the summer (i.e., in open-water conditions) using existing oil spill response technologies. During the winter (i.e., under solid ice conditions), the ice, and any snow on the ice, could provide an effective platform for oil spill response and cleanup efforts, and help absorb the spill and contain it to an area relatively close to the gravel island or gravitybased structure. Land-based equipment could then be used to collect and transport the oil-covered ice out of the location. For context, a gravity-based structure would include a concrete island drilling structure and a steel drilling caisson(s). Artificial Ice Islands—A similar issue would be encountered if drilling were to take place from a man-made ice island. In those cases, the drilling location would be accessible only during the winter season when temperatures are very low, and the area is completely covered by ice stable enough to safely support a drilling rig and associated equipment. As temperatures rise during the spring and summer seasons, the ice breaks or melts away, making the drilling location inaccessible until the next winter season. The new paragraph (d) of § 250.175 would facilitate the proper development of a lease by addressing those seasonal conditions that limit leaseholding operations by providing an operator ready and able to complete its operations with the opportunity to obtain an SOO. If granted, this SOO would suspend the running of the lease term and effectively extend the term of the affected lease by a period equivalent to the period of such suspension. The SOO would allow a diligent operator to use the full 10 years in a 10-year lease term to explore for hydrocarbons, without the concern for a lease expiring because Arctic seasonal constraints prevented operations. BSEE would continue to require the operator to comply with the existing requirements for requesting a suspension under existing § 250.171, How do I request a suspension? For example, § 250.171 requires the operator to submit a reasonable schedule of work for resuming the suspended operations on the subject lease for which the operator requests the suspension. A schedule of work typically includes milestones describing what activities the operator will perform to resume operations and when those operations will be performed. If the operator submits a schedule of work that demonstrates a reasonable plan and VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 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 PO 00000 Frm 00018 Fmt 4701 Sfmt 4702 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 E:\FR\FM\09DEP2.SGM 09DEP2 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules jbell on DSKJLSW7X2PROD with PROPOSALS2 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: https:// 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: https://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 VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 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 petroleumbased mud and associated cuttings while operating on the Arctic OCS. Existing § 250.300(b)(1) and (2) state that the BSEE Regional Supervisor may exercise his or her discretionary authority to restrict discharges of waterbased muds and associated cuttings from Arctic OCS exploratory drilling based on various factors, such as: Proximity of drilling operations to subsistence hunting and fishing locations; the extent to which discharged water-based mud or cuttings may cause marine mammals to alter their migratory patterns in a manner that impedes subsistence users’ access to or use of those resources, or increases the risk of injury to subsistence users; or the extent to which discharged mud or cuttings may adversely affect marine mammals, fish, or their habitat. BSEE promulgated the existing provisions in response to concerns raised by Alaska Native Tribes during preparation of the 2015 Arctic Proposed Rule. These concerns included how water-based muds or cuttings could adversely affect marine species (e.g., whales and fish) and their habitats and compromise the effectiveness of subsistence hunting activities. BSEE re-examined the language in paragraphs (b)(1) and (2) of this section in light of EPA’s authority to address water-based muds and cuttings discharges. The Clean Water Act (CWA) (Section 301(a), 33 U.S.C. 1311(a)) provides EPA with the authority to issue National Pollutant Discharge Elimination System (NPDES) general permits, which authorize certain discharges, including certain restricted discharges of water-based muds and cuttings, from oil and gas exploratory facilities on the OCS in the Beaufort Sea PO 00000 Frm 00019 Fmt 4701 Sfmt 4702 79283 and the Chukchi Sea. Those general permits additionally prohibit the discharge of oil-based and non-aqueous based muds and cuttings. The EPA must issue an NPDES general permit before an operator may seek coverage under that general permit. Compliance with the CWA, including gaining coverage under an applicable NPDES general permit, is necessary before an operator may discharge pollutants from its exploratory drilling operations. Before issuing an NPDES permit, EPA must make specific determinations to ensure that issuance of a permit will not lead to unreasonable degradation of the marine environment. EPA’s determination is guided by an Ocean Discharge Criteria Evaluation (ODCE). The ODCE requires the agency to consider multiple environmental factors, such as potential impacts on human health through direct and indirect pathways, and the importance of the receiving water area to the surrounding biological community. These factors take into consideration how discharges could impact subsistence activities, marine resources, and coastal areas. The most relevant NPDES permits issued for offshore oil and gas exploration activities conducted from a MODU on the Arctic OCS are two 2012 general permits that covered oil and gas exploration facilities conducting operations in Federal waters of the Beaufort Sea and the Chukchi Sea. The Beaufort Sea permit 41 does not allow the discharge of water-based muds and cuttings during the fall bowhead whale hunt. However, the Chukchi Sea permit 42 did not include a similar restriction. According to the ODCE for the Chukchi Sea permit, the restriction was not necessary because the migration of bowhead whales would be over before discharge-related activities would begin.43 Under this proposed rule, BSEE would preserve the requirements in § 250.300(b)(1) and (2) that the operator capture all petroleum-based mud and associated cuttings. This requirement is consistent with a longstanding, OCSwide regulatory authority that existed prior to the promulgation of the 2016 Arctic Exploratory Drilling Rule. BSEE must preserve the petroleum-based muds and cuttings requirement since it is not unusual for petroleum-based 41 https://www.epa.gov/sites/production/files/ 2017-12/documents/r10-npdes-beaufort-oil-gas-gpakg282100-final-permit-2012.pdf. 42 https://www.epa.gov/sites/production/files/ 2017-12/documents/r10-npdes-chukchi-oil-gas-gpakg288100-final-permit-2012.pdf. 43 https://www.epa.gov/sites/production/files/ 2017-12/documents/r10-npdes-chukchi-oil-gas-gpakg288100-odce-2012.pdf, pp. 6–14 to 6–17. E:\FR\FM\09DEP2.SGM 09DEP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 79284 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules muds to contain constituents that are toxic and harmful to the environment. Although water-based muds may not be a feasible option for all drilling operations, such as when drilling through hydrophobic geologic formations that could be damaged by water-based muds, its use is a more environmentally benign approach in comparison to the use of petroleumbased muds. However, BSEE’s proposed revisions reflect the Bureau’s understanding that the express statements regarding the Regional Supervisor’s discretionary authority to require the capture of water-based muds and cuttings in existing § 250.300(b)(1) and (2) are not necessary. In particular, the EPA already addresses the goals of protecting water quality through the NPDES program, protecting marine species and their habitats, as well as the effectiveness of subsistence hunting activities, through the exercise of that agency’s authorities. Thus, BSEE does not expect the Regional Supervisor to need to exercise the discretionary authority under existing § 250.300(b)(1) and (2) in the foreseeable future. Furthermore, BSEE understands, and did so even while it was preparing the 2016 Arctic Exploratory Drilling rule, that the references to the BSEE Regional Supervisor’s authority in existing paragraphs (b)(1) and (2) created some uncertainty for the regulated industry because it appeared to overlap with EPA’s jurisdiction and, if implemented, might result in BSEE issuing duplicative or conflicting requirements. BSEE addressed this concern by explaining that the amendments were meant to clarify the Regional Supervisor’s authority to impose operational measures that complement EPA’s discharge limitations by considering potential impacts to specific components of the Arctic environment, such as subsistence activities, marine resources, and coastal areas (81 FR 46505). Given the policy in E.O. 13783 to review existing regulations that potentially burden the development or use of domestically produced energy resources and the general principles in Section 1 of E.O. 13563—Improving Regulation and Regulatory Review (76 FR 3821)—to promote predictability and reduce uncertainty, BSEE believes it is appropriate to propose eliminating the water-based mud, and associated cuttings, provisions in § 250.300(b)(1) and (2). This proposed regulatory change does not suggest any change in BSEE’s recognition that it is responsible for ensuring that oil and gas exploration and production activities on the OCS are conducted in a safe and VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 environmentally responsible manner pursuant to OCSLA. Therefore, the proposed rule would not alter the longstanding regulation at § 250.300(b)(1), under which the District Manager (or Regional Supervisor) retains the ability to restrict the rate of drilling fluid discharges or prescribe alternative discharge methods where warranted. Pursuant to § 250.300(b)(1), BSEE would be able to determine whether there is a need to require capture of water-based muds and cuttings on a case-by-case basis, if the EPA has not done so. In particular, the District Manager would consider and determine whether such a requirement would be appropriate for any facility. The District Manager would make this determination on a case-by-case basis, in conjunction with the EP and APD approval process. This process includes coordinating with BOEM, particularly at the EP stage, when BOEM conducts an environmental review to identify the direct, indirect, and cumulative environmental effects that may be expected as a result of implementing the EP. That environmental review also incorporates input about potential environmental effects that may be obtained through consultations and review by interested parties, Federal agencies (e.g., EPA), State or local agencies, Tribes, or the public. Nothing would change BSEE’s position from the 2016 rule to communicate with other agencies responsible for oversight of discharges related to oil and gas exploration drilling in the Arctic. This communication will help ensure that conflicts do not arise (81 FR 46504). BSEE expects that such input from EPA would address whether that agency has issued or plans to issue a permit for the same exploratory drilling facilities, and whether that agency believes that capture of water-based muds in a specific case is warranted. Through BSEE’s longstanding authority under § 250.300(b)(1), the District Manager could require an operator to restrict the rate of drilling fluid discharges or prescribe alternative discharge methods. Such a restriction on the discharge of water-based muds and cuttings might be appropriate if identified in the EP environmental review process. In addition to the proposed revisions just described, BSEE proposes a minor modification to the second sentence in existing paragraph (b)(2), which requires the operator to capture all cuttings from operations that ‘‘utilize’’ petroleumbased mud to prevent their discharge into the marine environment. BSEE proposes to replace the word ‘‘utilize’’ PO 00000 Frm 00020 Fmt 4701 Sfmt 4702 with ‘‘use’’ to improve the readability of the regulation. Subpart D—Oil and Gas Drilling Operations What additional information must I submit with my APD for Arctic OCS exploratory drilling operations? (§ 250.470) BSEE proposes to revise paragraph (b) of § 250.470 by adding paragraph (b)(13) to include ‘‘Recover the subsea isolation device (SSID), where applicable.’’ This revision is necessary to address the SSID alternative proposed in § 250.472, and to ensure the operator’s permit addresses how it would recover the SSID, if one is used. For operations relying on an SSID, the SSID is a critical piece of equipment. Therefore, BSEE must understand how the operators will handle it, prior to and after drilling operations. We also propose minor, nonsubstantive edits to paragraphs (b)(11) and (12) to accommodate this addition. In cases where an operator obtains SCCE capabilities through contracting, paragraph (f)(3) currently requires the operator to provide proof of contracts or membership agreements with cooperatives, service providers, or other contractors. This includes information demonstrating the availability of the personnel and/or equipment on a 24hour per day basis during operations below the surface casing. BSEE proposes to revise paragraph (f)(3) by replacing the ‘‘below the surface casing’’ language in this paragraph with the phrase ‘‘below the surface casing, or before the last casing point prior to penetrating a zone capable of flowing hydrocarbons in measurable quantities, as approved by the Regional Supervisor.’’ This change would make the requirement in paragraph (f)(3) consistent with the changes BSEE is proposing to § 250.471, which houses the substance of the Arctic OCS SCCE requirements. This proposed change is discussed in further detail in connection with that provision. Finally, BSEE proposes to add a new paragraph (h) to complement the proposed revisions to § 250.472, which would provide the operator with the option to use an SSID or have access to a relief rig, as an additional means to secure the well in the event of a loss of well control, if the operator will be conducting exploratory drilling operations from a MODU (that change is discussed in further detail in connection with that provision). Under proposed paragraph (h), if the operator elects to use an SSID, BSEE would require the operator to provide a certification, signed by a registered professional engineer, confirming that its SSID and E:\FR\FM\09DEP2.SGM 09DEP2 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules 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. jbell on DSKJLSW7X2PROD with PROPOSALS2 What are the requirements for Arctic OCS source control and containment? (§ 250.471) Section 250.471(a) currently requires the operator to have access to the SCCE described in paragraphs (a)(1) through (3), which must be capable of stopping or capturing the flow of an out-ofcontrol well if the operator will be using a MODU when drilling below or working below the surface casing. Paragraph (a)(1) specifically requires the capping stack to be positioned to ensure that it will be able to arrive at the well location within 24 hours after a loss of well control. Paragraphs (a)(2) and (3) require the cap and flow system and the containment dome to be positioned to ensure that they will be able to arrive at the well location within 7 days after a loss of well control. BSEE proposes to revise § 250.471 by: (i) Adding a new provision at the end of paragraph (a) stating that ‘‘However, the Regional Supervisor will approve delaying access to your SCCE until your operations have reached the last casing point prior to penetrating a zone capable of flowing hydrocarbons in measurable quantities provided that you submit adequate documentation (such as, but not limited to, risk modeling data, offset well data, analog data, seismic data), with your APD, demonstrating that you will not encounter any abnormally highpressured zones or other geologic hazards. The Regional Supervisor will base the determination on any documentation you provide as well as any other available data and information.’’ (ii) modifying the language in paragraph (a) describing the performance standard that the SCCE must meet by replacing ‘‘capable of stopping or capturing the flow of an outof-control well’’ with ‘‘capable of controlling or containing the flow from an out-of-control well when drilling below or working below the surface casing;’’ and VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 (iii) removing the phrase ‘‘positioned to ensure that it will arrive at the well location within 7 days after a loss of well control’’ from subparagraphs (a)(2) and (3), which apply to the cap and flow system and containment dome, respectively. The changes described in item (i) from the previous paragraph could allow the operator to adjust the point in time during operations when it must position its capping stack—from ‘‘when drilling or working below the surface casing’’ to ‘‘when drilling or working below the last casing point prior to the zone capable of flowing hydrocarbons in measurable quantities’’—if the operator is able to demonstrate that it will not encounter any abnormally highpressured zones or other geological hazards before that casing point. However, unless otherwise approved by BSEE, the operator must have access to their SCCE as described in paragraph (a)(1) and proposed paragraphs (a)(2) and (3), when drilling or working below the surface casing. While BSEE does not propose changes to the capping stack provision in paragraph (a)(1), changes to paragraph (a) would have a practical effect on the existing capping stack requirements. Changes to the capping stack requirements are discussed in the next subsection, entitled, Revisions to the Capping Stack Requirements. BSEE’s proposed modifications to the language in paragraph (a), describing the performance standard that the operator’s SCCE must meet, is administrative in nature. BSEE proposes this change so that the language is consistent with the source ‘‘control’’ and ‘‘containment’’ description of this equipment, as well as the title of this section of the regulations (i.e., § 250.471 What are the requirements for Arctic OCS source control and containment?). It would not change the performance standard that the operator’s SCCE must meet. BSEE’s proposed changes to remove the phrase ‘‘positioned to ensure that it will arrive at the well location within 7 days after a loss of well control’’ from paragraphs (a)(2) and (3) would still require the operator to ensure it has access to a cap and flow system or a containment dome. However, the operator would no longer be required to ensure the equipment is positioned to be able to arrive at the well location within 7 days after the loss of well control. The distinction between the positioning requirement and the requirement to have access to the equipment is that ‘‘having access’’ refers to ensuring the operator has identified the equipment that would meet the performance requirements in this section and in other existing BSEE PO 00000 Frm 00021 Fmt 4701 Sfmt 4702 79285 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, E:\FR\FM\09DEP2.SGM 09DEP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 79286 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules including the potential for hydrocarbon flow. Operators base this assessment on existing G&G data that they include in the APD. In many cases, flowable hydrocarbons are not anticipated or encountered in measurable quantities until the target productive formation is reached. For example, a surface casing shoe setting depth for an Arctic OCS exploration well could be only 1,500 feet, but the hydrocarbon bearing formation may be thousands of feet below that point. The existing regulations require the operator to have access to an available capping stack when drilling or working below the surface casing, even though geologic and engineering risk analyses the operator must submit as part of their APD may show that there is little or no potential for hydrocarbons to escape the formation and flow into the well prior to reaching the targeted productive formation. In such circumstances, the operator could safely drill for thousands of feet below the surface casing, without any identifiable need for a capping stack. This proposed change would, when appropriate, eliminate an unnecessary burden for the operator to maintain a positioned capping stack while drilling into low risk, nonproductive sections of the well below the surface casing. An extensive amount of geophysical data already exists for certain areas of both the Beaufort and Chukchi Sea Planning Areas, and there has been extensive drilling in certain areas of the Beaufort Sea Planning Area. In the known geologic conditions of the U.S. Arctic, operators have a good understanding of the locations of reservoirs that they will encounter, which can be relatively shallow and normally pressured above certain geologic depths. Therefore, it may not be necessary to have access to a capping stack when drilling through zones below the surface casing that do not have abnormally high formation pressures or contain other geological hazards, and do not have the potential to flow hydrocarbons in measurable quantities, as they are penetrated. However, because geologic conditions are not uniformly normally pressured throughout the Arctic OCS, BSEE is maintaining the existing requirement to have the capping stack positioned when drilling or working below the surface casing. At the same time, BSEE does not discount the possibility that future projects would not need to have SCCE (i.e., the capping stack) positioned until reaching the last casing point prior to penetrating a zone capable of flowing hydrocarbons. VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 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 PO 00000 Frm 00022 Fmt 4701 Sfmt 4702 criteria, other than ‘‘abnormally highpressured zones or other geologic hazards,’’ that the Bureau should use to determine whether to allow the operator to delay positioning of the capping stack. BSEE’s proposed regulatory language describing the types of documentation it would consider adequate to demonstrate that abnormally high-pressured zones or other geological hazards would not be encountered before reaching the last casing point prior to penetrating a zone capable of flowing hydrocarbons in measurable quantities—‘‘such as, but not limited to, risk modeling data, offset well data, analog data, seismic data’’—is not meant to be an exhaustive list. BSEE would accept any other types of documentation the operator may provide that will help its demonstration. BSEE does not anticipate this submission requirement would lead to a significant information collection burden on the operator because it is normal practice for operators to gather these types of information to develop and design an offshore exploration drilling project on the OCS in the Arctic. BSEE is requesting comment on what other types of information could be used to demonstrate the absence of abnormally pressured zones or other geologic hazards, and how burden on the operator could change—increase or decrease—if BSEE were to require its submission. At the APD stage, BSEE would evaluate the operator’s documentation along with other accompanying geologic and engineering information/analyses that must be submitted as part of its APD. BSEE would also consider any other available G&G information, such as information gathered from prior drilling operations in the area (e.g., well log and pressure testing information), and any other applicable geophysical (e.g., seismic data) information. BSEE makes clear in its proposed regulatory language that the Regional Supervisor will base the determination on whether to allow the operator to delay positioning of the capping stack on the documentation that the operator submits, as well as any other available data and information. BSEE is also considering an alternative regulatory approach whereby the Bureau would instead revise existing paragraph (a) by replacing ‘‘surface casing’’ with ‘‘last casing point prior to penetrating a zone capable of flowing hydrocarbons in measurable quantities.’’ This regulatory option would uniformly adjust the point in time during operations when the operator must have access to its capping stack, by requiring the operator to have E:\FR\FM\09DEP2.SGM 09DEP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules 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 VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 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 PO 00000 Frm 00023 Fmt 4701 Sfmt 4702 79287 proposed change would remove the requirement to have a cap and flow system or a containment dome positioned to ensure the equipment will be available to arrive at the well location within 7 days after the loss of well control, while preserving the existing requirement to deploy those pieces of equipment as directed by BSEE. BSEE proposes to allow the operator to adjust the point in time during operations when it must position its capping stack under paragraph (a), from ‘‘when drilling or working below the surface casing’’ to ‘‘when drilling below or working below last casing point prior to penetrating a zone capable of flowing hydrocarbons in measurable quantities’’ if the operator is able to demonstrate that it will not encounter any abnormally high-pressured zones or other geologic hazards before that casing point. Only the 7-day arrival timing related to the ‘‘flow’’ part of the cap and flow system would be altered as a result of BSEE’s proposed modification to paragraph (a)(2) of § 250.471.44 The changes proposed in paragraphs (a)(2) and (3) to remove the requirement for the cap and flow system and the containment dome to arrive at the well location within 7 days after a loss of well control would not change other existing requirements throughout § 250.471 for the operator to ensure: (i) Access to a containment dome and cap and flow system; (ii) that the cap and flow system is designed to capture at least the amount of hydrocarbons equivalent to the calculated WCD rate referenced in the operator’s BOEM-approved EP; (iii) that the containment dome has the capacity to pump fluids without relying on buoyancy; (iv) that tests or exercises are conducted for the SCCE, as directed by the Regional Supervisor; (v) that records pertaining to the testing, inspection, maintenance, and use of the SCCE are maintained and made available to BSEE upon request; (vi) that all SCCE identified in § 250.471 are transported to the well upon a loss of well control; and (vii) that SCCE is deployed as directed by the Regional Supervisor. BSEE proposes to remove the cap and flow system and containment dome 7day arrival timing requirements based on the Bratslavsky and SolstenXP study. The Bratslavsky and SolstenXP study determined that the time periods when SCCE may be safely deployed throughout the Arctic OCS is limited based on typical Arctic conditions. In 44 Existing § 250.105 defines Cap and flow system and Capping stack. E:\FR\FM\09DEP2.SGM 09DEP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 79288 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules the Chukchi Sea, this means that safe SCCE deployment could only occur between August and October in the historically active exploration area. Moving north from the historically active exploration area of the Chukchi Sea, the ability to safely deploy SCCE diminishes significantly (id. at 100). The study mentions there are more opportunities for safe deployment of SCCE in other portions of the Chukchi Sea (June through December). However, it is only in the southwestern extent of the Chukchi Sea Planning Area; outside of the historically active exploration area. In the Beaufort Sea, the study noted that sea ice concentrations tend to be greater year-round as compared to the Chukchi Sea (id. at 75). Accordingly, safe SCCE deployment could occur from ice capable vessels between early August and October in the historically active exploration area of the Beaufort Sea (i.e., the southern portion of the Beaufort Sea Planning Area). However, moving north beyond the historically active exploration area, time windows for safe SCCE deployment decrease significantly (id. at 104). In the case of open water operations in both the Chukchi and Beaufort Seas, the study points out that sea state is an important limiting factor for safe SCCE deployment. Rough sea states—high waves and longer wave periods—can affect the safety and operating limits of SCCE deployment. The vessel carrying the SCCE can become very unstable in rough sea states and the heave action on the deck can therefore increase significantly beyond the vessel’s tolerance levels for conducting operations, which may negatively affect the ability to safely deploy the SCCE. Rough sea states are most likely to occur when there is less sea ice coverage and larger open water areas to generate large waves, which is more of an issue in the Chukchi Sea, where there are larger open water areas throughout the open water season (id. at 11). When operating in open water conditions, sea states generally dictate that safe SCCE deployment could occur only between late September and October in the historically active exploration area of the Chukchi Sea, and that window diminishes significantly moving north of the historically active exploration area. In the Beaufort Sea, where there is less open water throughout the operating season, sea states would generally permit safe deployment of SCCE between lateAugust and early-to mid-October in the historically active exploration area. Beyond that, the probability for safe SCCE deployment decreases rapidly in VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 the historically active exploration area and in the other areas of the Beaufort Sea. (id. at 98,102) Water depth is also an important factor to consider for the safe deployment of SCCE. Deployment is likely to be impaired in water depths shallower than 984 feet because the equipment would potentially be subject to a gas boil at the surface from a subsea blowing well (id. at 143). A gas boil is a forceful release of hazardous gases which can present human-health hazards to workers, fire hazards, and potential stability problems for support vessels and the vessel deploying the SCCE directly above the blowing well. Water depths in the majority of the Chukchi Sea and Beaufort Sea where exploration has historically occurred are relatively shallow—167 feet or less (Table 1–1 and Table 1–2, id. at 7 to 9). As recently as April of 2020,45 there were active leases in the Arctic OCS where SCCE may be deployed. These leases were located in the Beaufort Sea in water depths less than approximately 170 feet deep. This water depth range limits the fleet of support vessels that can be used for the safe deployment of SCCE. A possible solution that could enable SCCE deployment in the presence of a gas boil is the use of offset-deployment technology to remotely position SCCE over the blowing well in shallow water (id. at A– 35). When BSEE proposed its original Arctic OCS SCCE requirements in 2015, the Bureau explained that there is limited ability in the Arctic region to summon additional source control and containment resources. Accordingly, the Bureau required operators to plan for response redundancies and planning complexities not required elsewhere (80 FR 9938). BSEE determined that the provisions finalized in 2016 provided for the necessary redundancy and sequencing of the responses, based on the time necessary to deploy, and therefore provided sufficient safety and environmental protection to allow for exploratory drilling on the Arctic OCS. At that time, BSEE believed that the technologies identified in its SCCE requirements represented the optimal approach to well control capabilities available for the Arctic OCS (81 FR 46520). 45 In April of 2020, the only leases with potential projects that would be subject to the Arctic OCS’s SCCE requirements were relinquished. However, there are other active leases in the Beaufort Sea located nearer to the shore in shallow waters where exploration and development projects are being pursued (primarily through man-made gravel islands). PO 00000 Frm 00024 Fmt 4701 Sfmt 4702 Since publication of the 2016 rule, however, BSEE has sought to better understand the ability to safely deploy SCCE (and relief rigs) in Arctic OCS conditions, through a study it commissioned to Bratslavsky Consulting Engineers, Inc., and SolstenXP, Inc. According to the Bratslavsky and SolstenXP study, the time periods when SCCE may be safely deployed throughout the Arctic OCS is limited in comparison to relief-well drilling operations, based on typical Arctic conditions. BSEE did not have the benefit of having the Bratslavsky and SolstenXP study when finalizing the 2016 Arctic Exploratory Drilling Rule. BSEE’s proposed changes to § 250.471(a)(2) and (3) for the containment dome and cap and flow system responds to the information it has gathered from the study. In light of these findings, BSEE proposes the revisions under § 250.471 to the containment dome and cap and flow system deployment requirements in paragraphs (a)(2) and (3) because it is not reasonable to impose such universal, prescriptive requirements for equipment that may not be safely deployed (moved to the location, equipment put into place, and activated) and effectively used under certain Arctic OCS conditions. The deployment and arrival schedules of the cap and flow system and the containment dome will be directed by the BSEE Regional Supervisor on a case-by-case basis. However, as previously described, BSEE proposes only to adjust, rather than eliminate, the reference to the point in time during operations when the operator must have access to a capping stack that is positioned to be able to arrive at the well location within 24 hours after a loss of well control. The Bratslavsky and SolstenXP study shows that the time periods when SCCE (capping stack, containment dome, and cap and flow system) may safely be deployed and effectively used are limited. Metocean conditions (i.e., rough sea states and sea ice concentrations) prevalent in the Arctic OCS can exceed the operating limits of the vessels that transport and deploy the SCCE. In addition, SCCE deployment is likely impaired in water depths shallower that 984 feet, where gas boils could form above a blowing well. Water depths in the majority of the Chukchi Sea and Beaufort Sea where exploration has historically occurred are relatively shallow—167 feet or less. However, BSEE’s independent observation outside of the study is that the chances for successfully deploying a capping stack under Arctic OCS conditions is greater in comparison to the containment dome E:\FR\FM\09DEP2.SGM 09DEP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules and cap and flow system. More specifically, in comparison to the containment dome, the capping stack has proven to be a more effective technology when successfully deployed and has a different function compared to a containment dome. The capping stack latches on to a connector or pipe stub located on or in the well to achieve a pressure tight seal to capture or stop all fluids flowing out of the well. A containment dome, which removes oil and gas from the water column, will likely capture only a portion of the hydrocarbon flow due to the non-sealing design. In addition, the use of a containment dome may be constrained by the drilling unit itself. Certain drilling rigs, such as jackups and submersible drilling vessels, are unlikely to provide adequate structural clearance for deployment of a containment dome without moving the rig off the drill site. (id. at 33). Furthermore, containment domes have limited field application to prove their capabilities while, in contrast, capping stacks have been field tested and successfully deployed in multiple practice drills (id. at 32 and 34).46 With respect to the cap and flow system, the flow portion of the system would require additional vessel support activities on the surface (e.g., support vessels for oil and gas processing, and hydrocarbon storage/transfer) to keep the system working in comparison to what would be needed to deploy a capping stack (e.g., a single vessel that would load the capping stack and deploy to the well when needed). The support activities and the vessel on which the flow system is loaded would be subject to the same challenging metocean conditions previously described, thus limiting their ability to be safely deployed throughout the Arctic drilling season. The capping stack would generally have a better opportunity for deployment because once the capping stack is lowered under the water and attached to the wellhead, weather becomes less of a factor. BSEE believes it is critical to ensure that operators have redundant protective measures in place, as there is no guarantee that a single measure could control or contain a worst-case discharge (see 81 FR 46487). Because the chances of successfully deploying a capping stack under Arctic OCS conditions may be greater in comparison to the containment dome and cap and flow system, BSEE is revising, and not eliminating, the 46 For example, the capping stack technology was used to shut-in the Macondo well during the Deepwater Horizon incident. VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 capping stack positioning requirement. BSEE invites comments on any technological upgrades or methods that exist for SCCE that would meet the objective of being a redundant system that could control or contain a WCD. Although BSEE is proposing to remove the requirement in existing paragraphs (a)(2) and (3) to ensure that the cap and flow system and containment dome will be available to arrive at the well location within 7 days after a loss of well control, BSEE would maintain the provisions under the same paragraphs that require that the operator identify and have access to a containment dome and cap and flow system capable of deployment as directed by BSEE. BSEE would also maintain the requirement under existing paragraph (g) to initiate transit of all SCCE identified under § 250.471 upon a loss of well control. Collectively, the proposed revisions to paragraphs (a)(2), (a)(3), and existing paragraph (g) would mean that, in the event of a loss of well control, the containment dome and cap and flow system would be in transit while the capping stack is being deployed at the well location. In light of the distinct functions and capabilities of these various elements of SCCE under anticipated Arctic OCS exploratory drilling conditions, BSEE proposes to retain these requirements, as modified, to preserve the regulations’ requirement for redundant protective measures, while acknowledging the capability of each SCCE component, as there is no guarantee that a single measure could control or contain a WCD. Finally, BSEE proposes to revise existing paragraph (b) by eliminating the requirement for the operator to conduct a stump test of a pre-positioned capping stack, if the operator elects to use one, prior to installation on each well. This proposed change would provide consistency with BSEE’s proposed revision to the definition of a capping stack in § 250.105 and the new SSID alternative BSEE is proposing under § 250.472. BSEE’s proposed SSID alternative includes specific testing procedures, which is discussed in detail later in this preamble. BSEE’s prior references to ‘‘pre-positioned capping stacks’’ were intended to address a comment on the 2015 Arctic Exploratory Drilling Proposed Rule suggesting that the definition of a capping stack be expanded to allow prepositioned capping stacks to be used below subsea BOPs when deemed technically and operationally appropriate. PO 00000 Frm 00025 Fmt 4701 Sfmt 4702 79289 What are the additional well control equipment or relief rig requirements for the Arctic OCS? (§ 250.472) Paragraph (b) of § 250.472 currently requires the operator to have access to a relief rig (different from the primary drilling rig), when drilling or working below the surface casing. In addition, when drilling or working below the surface casing, paragraph (b) requires the operator to stage the relief rig so that it could arrive on site, drill a relief well, kill and permanently plug the out-ofcontrol well, and abandon the relief well prior to expected seasonal ice encroachment at the drill site, and in no event later than 45 days after the loss of well control. BSEE proposes to revise the existing relief rig and SSRW requirements in § 250.472 by: (i) Providing the operator with an option to either use an SSID or have access to a relief rig, if the operator will conduct exploratory drilling operations from a MODU; (ii) Establishing the requirements that the operator must satisfy if the operator elects to use an SSID to comply with § 250.472; (iii) Establishing the requirements that the operator must satisfy if the operator elects to have access to a relief rig to comply with § 250.472; (iv) Adding a new provision that would apply if the operator elects to have access to a relief rig, which states, ‘‘However, the Regional Supervisor will approve delaying access to your relief rig until your operations have reached the last casing point prior to penetrating a zone capable of flowing hydrocarbons in measurable quantities provided that you submit adequate documentation (such as, but not limited to, risk modeling data, off-set well data, analog data, seismic data), with your APD, demonstrating that you will not encounter any abnormally highpressured zones or other geological hazards. The Regional Supervisor will base the determination on any documentation you provide as well as any other available data and information.’’; and (v) Eliminating the reference to expected seasonal ice encroachment at the drill site, which applies to relief rig operations. With respect to the structure of § 250.472, proposed paragraph (a) would establish the requirements the operator must follow if the operator elects to use an SSID, and proposed paragraph (b) would establish the requirements the operator must follow if the operator elects to maintain access to a relief rig. BSEE would combine the E:\FR\FM\09DEP2.SGM 09DEP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 79290 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules requirements in existing paragraphs (a) and (b) into a single paragraph— proposed paragraph (b)—for organizational purposes, since existing paragraphs (a) and (b) cover relief rigs. Proposed paragraph (b) would also include the relief rig-related revision described in item (iv) of the previous paragraph, which could allow the operator to adjust the point in time during operations when it must stage its relief rig—from ‘‘when drilling or working below the surface casing’’ to ‘‘when drilling or working below the last casing point prior to the zone capable of flowing hydrocarbons in measurable quantities’’—if the operator is able to demonstrate that it will not encounter any abnormally highpressured zones or other geological hazards before that casing point. However, unless otherwise approved by BSEE, the operator must stage its relief rig in a location, such that the relief rig would be available to arrive on site, drill a relief well, kill and abandon the original well, and abandon the relief well no later than 45 days after the loss of well control, when drilling or working below the surface casing. Finally, proposed paragraph (b) would include the proposed relief rig-related revision to eliminate the reference to expected seasonal ice encroachment at the drill site, which could potentially extend the open-water drilling season for MODUs. The changes included in proposed paragraphs (a) and (b) are discussed in further detail below, respectively, under the two subheadings entitled, Proposed Paragraph (a)— Complying with § 250.472 by Using an SSID and Proposed Paragraph (b)— Complying with § 250.472 by Having Access to a Relief Rig. In addition, the general alternative compliance language in existing paragraph (c) would be eliminated because the proposed rule would provide the operator with the alternatives of either using an SSID or having access to a relief rig, and because § 250.141, May I ever use alternate procedures or equipment?, already provides an option for an operator to seek approval to use alternate procedures or equipment, potentially including future technologies that have not yet been developed. When it promulgated the 2016 Arctic Exploratory Drilling Rule, BSEE understood that, based on past loss of well control events (including the Deepwater Horizon incident), it was important for the operator to be prepared to drill a relief well to permanently plug a well, in the event of a loss of well control. Arctic OCS exploratory drilling operations VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 conducted from MODUs are complicated by the fact that these operations can take place only during a short period each year, when ice hazards can be physically managed and there is no continuous ice layer over the water. Outside of that window, ice encroachment complicates or prevents drilling, including drilling a relief well, and transit operations. Therefore, BSEE concluded in the proposed rule: Oil and Gas and Sulphur Operations on the OCS—Requirements for Exploratory Drilling on the Arctic OCS (February 24, 2015, 80 FR 9916) that, for Arctic OCS Conditions, it was necessary to establish a relief rig and SSRW requirements, whereby the rig would be positioned at a location that would enable it to transit to the well site, drill a relief well, kill and permanently plug the out-of-control well, plug the relief well, and demobilize from the site, prior to expected seasonal ice encroachment. (see 80 FR 9940). Prior to finalizing the 2016 Arctic Exploratory Drilling Rule, BSEE did not identify any alternative technologies that provided a comparable level of results to drilling a relief well and permanently killing an out-of-control well. Drilling a relief well prior to seasonal ice encroachment eliminates the risk of a prolonged uncontrolled flow of hydrocarbons under the ice, throughout the winter season. The SCCE intervention options in BSEE’s existing regulations (capping stack, cap and flow system, and containment dome) are intended only to temporarily control a well and not to be left in place over an entire ice season. However, BSEE did provide an option through the 2016 rule for the operator to request that BSEE approve ‘‘alternative compliance measures to the relief rig requirement,’’ as provided in the longstanding regulation at § 250.141, May I ever use alternate procedures or equipment? Since the promulgation of the 2016 Arctic Exploratory Drilling Rule, BSEE has received and considered new information regarding the current relief rig and SSRW requirements in § 250.472. BSEE used the following information when developing the proposed requirements of this section: • Supplemental Assessment to the 2015 Report on Arctic Potential: Realizing the Promise of U.S. Arctic Oil and Gas Resources (NPC 2019 Report) In April 2018, the Secretary of Energy, in cooperation with DOI, requested that the NPC develop a supplemental assessment to the NPC 2015 Report. In April 2019, the NPC issued a report entitled, ‘‘Supplemental Assessment to the 2015 Report on Arctic Potential: Realizing the Promise of U.S. Arctic Oil PO 00000 Frm 00026 Fmt 4701 Sfmt 4702 and Gas Resources.’’ The supplemental assessment evaluated recent experiences with Arctic exploration and advancements in technology, and it provided findings and recommendations directed toward enhancing the Nation’s regulatory environment to improve reliability, safety, efficiency, and environmental stewardship for Arctic oil and gas development. One of the key areas the Secretary of Energy requested that the NPC address was regulatory burdens related to development on the Arctic OCS. (NPC 2019 Report at A–1) The NPC 2015 Report described various technologies employed by industry as preventative measures, to reduce the risk of a well control incident or to mitigate the impacts of an incident through response and recovery measures. It recommended further examination of source control and containment technologies, including capping stacks and SSIDs, noting that such alternatives ‘‘. . . could prevent or significantly reduce the amount of spilled oil compared to a relief well, which could take a month or more to be effective.’’ (NPC 2015 Report at 4–16). In July/August of 2007, BSEE’s predecessor, MMS, published a paper entitled, ‘‘Absence of fatalities in blowouts encouraging in MMS study of OCS incidents 1992–2006.’’ You may download and view the paper at https:// drillingcontractor.org/dcpi/dcjulyaug07/DC_July07_ MMSBlowouts.pdf. The paper summarizes BSEE’s assessment of statistical information about loss of well control events that occurred during drilling operations on the OCS from 1992 through 2006. The paper noted that although relief wells were initiated in 2 of the 39 blowouts that occurred during the study period, both wells were controlled by other means prior to completion of the relief well. According to the NPC 2015 report, ‘‘[a] relief well under good weather conditions may take 30 to 90 days plus rig mobilization, whereas a capping stack could be installed significantly sooner, and a subsea shut-in device could be activated in minutes.’’ (NPC 2015 Report at 8–17) The NPC 2019 Report noted that, when ExxonMobil drilled an exploratory well in the Russian waters of the Kara Sea, it used an SSID that was built and tested in Norway. According to the NPC 2019 Report, the SSID used in the Kara Sea used existing capping stack technology, including dual blind shear rams; an upgraded, redundant control system; and side inlets for intervention below the shear rams. (id. at C–10). At the same time, the NPC 2019 Report described the SSID as E:\FR\FM\09DEP2.SGM 09DEP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules similar to a second BOP that was designed to be left on the wellhead, instead of being removed with the drilling rig, if the rig moves off the well near the end of the drilling season. The SSID, which could be actuated remotely, and the casing design together were capable of safe full well shut-in, diminishing the risk related to a loss of well control event occurring in late season and continuing over the winter season. The NPC 2019 Report observed that this design approach could eliminate the need for an SSRW. (id. at C–28). Ultimately, the NPC recommended that the use of an SSID, in conjunction with capping stacks, be accepted in place of the existing requirement for SSRW capability. (id. at 2). The NPC 2019 Report also included additional data regarding the geologic characteristics of the formations targeted during exploratory drilling operations in the Chukchi Sea and Beaufort Sea. The NPC 2019 Report provides an illustrative comparison of the geologic depths encountered in the Arctic OCS and the Gulf of Mexico OCS. (NPC 2019 Report at 11). The shallower targeted geologic formations in the Arctic OCS make drilling less complex and lower risk. This is different from current water depths encountered by operators in the Gulf of Mexico. In the Arctic OCS, exploratory drilling operations conducted from MODUs have taken place in waters less than 200 feet. In the Gulf Mexico, drilling activities are continually taking place in waters deeper than 9,000 feet. The Arctic OCS’s distinct challenges are driven by the region’s extreme environmental conditions, geographic remoteness, and a relative lack of fixed infrastructure and existing operations. In comparison to the Gulf of Mexico, the Arctic OCS lacks extensive operations and infrastructure from which resources could be drawn to respond to a well control incident. In addition, the open water season for drilling from a MODU is limited, allowing operators to perform drilling operations only during the summer and early fall. A late-season well-control event could challenge an operator’s ability to perform well intervention operations prior to freeze up. • Suitability of Source Control and Containment Equipment versus SSRW in the Alaska Outer Continental Shelf Region (Bratslavsky and SolstenXP, 2018) In addition to the NPC 2019 Report, BSEE received information about SSIDs through the Bratslavsky and SolstenXP study, discussed in the previous section in connection with the proposed VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 changes to the current Arctic OCS source control and containment requirements in § 250.471. As previously mentioned, the Bratslavsky and SolstenXP study entailed a comprehensive review and gap analysis of U.S. and international regulations, standards, recommended practices (RP), specifications, technical reports, and common industry methods regarding the safe deployment of SCCE as compared to the effectiveness of drilling an SSRW in Arctic conditions. BSEE notes that the Bratslavsky and SolstenXP study refers to the SSID as a ‘‘subsea intervention device’’ and considers the device to be SCCE, which is used to mitigate the consequences of a well control event. However, consistent with the findings in the NPC 2019 Report that categorizes SSIDs as preventative measures (instead of a response and recovery measure), BSEE considers SSIDs to be a barrier intended to prevent or minimize the impacts of a well control event. (id. at 16). The Bratslavsky and SolstenXP study noted that an SSID was installed and field tested on a submersible drilling vessel (i.e., a steel drilling caisson) for a 2005/2006 drilling project in the Canadian Beaufort Sea. However, the system was not completed in time to meet the approval process timelines and shipping deadlines required for timely implementation of the unit. (Bratslavsky & SolstenXP at A–36). According to the study, the use of a preinstalled SSID could provide a faster and safer additional line of defense for a response to a blowout than an SSRW or deployment of a capping stack or containment dome, resulting in smaller discharges to the environment. The report also mentions that the ability to remotely function the SSID ensures that it can be used in instances where other types of SCCE cannot be deployed due to site hazards that make it unsafe or inaccessible. These instances may include: A blowout with pressurized fluids coming up solely through the wellbore (forming a gas boil on the surface), a rig catching fire or collapsing on top of the well, or an incident in an area where response operations are limited, such as in shallow waters (id. at 35). The report also stated that if the well is designed to accommodate a full shut-in of the last casing string interval, the SSID can temporarily cap and control a well and facilitate its plugging and abandonment. This finding is consistent with the information from the NPC 2019 Report discussed previously. In 2008, Chevron initiated a technology venture with its partners on an R&D project to develop an SSID that would PO 00000 Frm 00027 Fmt 4701 Sfmt 4702 79291 advance the best BOP technologies available at the time and would meet or exceed Canada’s SSRW Arctic offshore regulations. The SSID was known as the Alternative Well Kill System (AWKS), which had two shear rams that were capable of simultaneously shearing and sealing heavier wall, larger diameter tubulars, and casings than was possible at that time. According to the NPC 2015 Report, Chevron successfully completed its testing of the AWKS in 2014 and is ready for deployment. (NPC 2015 Report at 4–18). Although the Bratslavsky and SolstenXP study points out that SSIDs could provide a faster and safer response to a blowout than capping stacks or containment domes, BSEE does not conclude from this observation that SSIDs should also replace the SCCE requirements in existing and proposed § 250.471. In the Arctic, it is critical for the operator to have redundant protective measures in place, as there is no guarantee that a single measure could control or contain a WCD. (see 81 FR 46487). In addition to these redundant protective measures, the SSID, well design, and BOPs serve as controls and barriers that prevent or minimize the likelihood of loss of well control. Other pertinent information from the Bratslavsky and SolstenXP study includes the statistical analysis of recent OCS drilling seasons in the Beaufort and Chukchi Seas. The analysis identified the metocean and operational conditions that would support the safe drilling of a relief well. The study noted that the hazards of sea ice to drilling vessels and associated support vessels are primarily determined by the concentration and thickness of the sea ice. A vessel’s ice classification, which are determined by various marine classification societies, such as the American Bureau of Shipping (ABS) and Det Norske Veritas and Germanischer Lloyd (DNV GL), indicates the vessel’s capabilities. As ice concentrations increase, a vessel’s efficiency decreases. (Bratslavsky & SolstenXP at 23). The study notes that the currently available open water operating season in the Chukchi Sea ranges from approximately 60 to 90 days in the historically active exploration area. (id. at 143). However, the results of the study showed that there is a high probability (90 percent) that drilling can be conducted safely in sea ice conditions in a majority of the historically active exploration area of the Chukchi Sea for 70 to 160 days if an ice class MODU and associated support vessels are used as part of the drilling E:\FR\FM\09DEP2.SGM 09DEP2 79292 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules jbell on DSKJLSW7X2PROD with PROPOSALS2 operation. (id. at 108 and 145). Moreover, the NPC 2019 Report notes that ‘‘vessels and equipment that are positioned in the theater ‘just in case’ they are needed to minimize environmental impact, can actually impede personnel safety and source control objectives, because they distract operations personnel, add congestion, and can impede surface access to the well location.’’ (NPC 2019 Report at 19). In the Beaufort Sea, the available open water operating season is limited to approximately 50 to 60 days across the historically active exploration area. (id. at 143). The study’s analysis showed there is a high probability (90 percent) that drilling can be conducted safely for 70 days, from mid-August through October, in a majority of the historically active exploration area of the Beaufort Sea. (id. at 146). In light of the information from the NPC reports and the Bratslavsky and SolstenXP study, and BSEE’s consideration of that information, BSEE proposes to revise § 250.472 in the following manner: • Proposed Paragraph (a)— Complying with § 250.472 by Using an SSID The use of an SSID is not a new concept and was discussed in the 2016 Arctic Exploratory Drilling Rule.47 Through the 2016 rulemaking comment process, stakeholders informed the Bureau that use of an SSID could help significantly reduce the risk of a release of hydrocarbons if the BOP system fails. At that time, BSEE focused more on permanent remediation to resolve a WCD event in the Arctic. Nonetheless, the Bureau agreed that an operator could request to use an SSID as an alternate procedure or equipment to the relief rig (80 FR 9940). Stopping short of requiring the use of an SSID, BSEE, instead, stated in the 2016 rule that it would consider the use of an SSID as an alternate procedure or equipment, under appropriate circumstances, if proposed for use with a jack-up (when surface BOPs are used). At that time, BSEE determined that, in the case where subsea BOPs are used in conjunction with floating drilling units, SSIDs would only be marginally effective or redundant (81 FR 46531). Since the 47 See, e.g., 80 FR 9940 (‘‘[BSEE] requests comments on alternative compliance approaches and specifically requests data on the performance of SIDs, including operational issues (such as timeframes needed to activate such alternatives). In particular, BSEE requests comments on appropriate staging requirements for a relief rig assuming that an SID has been installed at the exploration well. Comments are also requested on the need for an operator to have an in- season relief well drilling capability if an SID is used at a location that is not subject to ice scouring.’’) VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 publication of the 2016 rule, BSEE has reevaluated the use of SSIDs and the overall improved technology for similar components (BOPs). In this proposed rule, BSEE would allow operators the option to use an SSID based on BSEE’s assessment of improved SSID design and operating requirements, including the ability to shut in a well over the winter ice season with a well cap. Additionally, BSEE would make this revision to potentially minimize environmental damage due to a prolonged ongoing well control event. An SSID is not a permanent solution for well remediation. However, it can provide a significantly quicker response time to address a well control event compared to drilling a relief well. Consistent with the policy in E.O. 13783 to review existing regulations that potentially burden the development or use of domestically produced energy resources, BSEE re-considered the SSID more closely, in light of the SSID information from the NPC reports and the Bratzlavsky and SolstenXP study, to determine whether the device could address the issues the Bureau identified when promulgating the 2016 rule. Drilling a relief well is a complex, time-consuming process. After setting up the drill rig and drilling begins, the process to intercept the original wellbore may take several weeks or more because the operator needs to drill deep enough at great precision to ensure interception of the original well. This delay increases the length of the time oil and other fluids within the original well could be flowing uncontrollably into the marine environment. There is no delay for operational use of an SSID compared to the process of using the relief rig or capping stack. In this proposed rule, BSEE developed its proposed SSID requirements based on existing BOP equipment/technology whose performance and reliability has been tested, proven in a manner that is repeatable and reproducible, and has improved since promulgation of the 2016 rule. BSEE also proposes to require an SSID used in the Arctic OCS to operate independently from the BOP. This would be accomplished by requiring the SSID to have a redundant control system, independent from the BOP control system, and independent, dedicated subsea accumulators to operate the SSID. By having two independent, redundant components (i.e., the BOP and the SSID) as part of the well control system, the overall reliability and effectiveness of the entire system increases. The following paragraphs describe BSEE’s proposed requirements associated with the SSID, PO 00000 Frm 00028 Fmt 4701 Sfmt 4702 including the SSID’s redundant control system (i.e., under proposed § 250.472(a)(2)(ii)) and subsea accumulators (i.e., under proposed § 250.472(a)(2)(iii)). Although the NPC 2019 Report recommended that the use of an SSID and capping stacks replace the requirement for an SSRW capability, BSEE is not proposing to eliminate the relief rig and SSRW requirements. Rather, BSEE is proposing to maintain the relief rig and SSRW requirement as an option for the operator to meet the regulatory requirements of § 250.472. BSEE has determined that its regulations should provide options and flexibility to the operator (i.e., an SSID or a relief rig) to fit its needs and plans to develop its Arctic OCS leases. There could be cases where the operator’s drilling schedule may not align with the availability of an SSID. In such a case, the operator should have the option to elect to proceed by complying with the relief rig and SSRW requirements. If an operator does not complete its exploratory drilling operations during that open water operating season, the operator could come back during a subsequent open water operating season and use an SSID, if one has become available in time. There could also be cases where two or more operators may plan to perform exploratory drilling operations during the same open water season. In such a case, each operator’s drilling rig could serve as the other’s relief rig. Under the existing regulations, BSEE would consider this type of a scenario to be in compliance with the relief rig and SSRW requirements. BSEE would not change that interpretation as part of this rulemaking. In a scenario like this, none of the operators would need to install an SSID, so long as there is an agreement among the operators that their drilling rigs will serve as a relief rig, if necessary. While it is not possible to identify every conceivable scenario, BSEE recognizes there could be other scenarios that are reasonably possible. Thus, it is appropriate to provide regulatory flexibility in order to accommodate an operator’s drilling program. BSEE also retains its regulatory authority to approve alternate procedures or equipment if the proposed procedures or equipment either meet or exceed the level of safety and environmental protection required. The term SSID is a broadly used industry term, and there is not a single, all-encompassing definition that establishes the scope and function of an SSID. In some cases, different terms are used to describe the device. For example, as stated earlier, the E:\FR\FM\09DEP2.SGM 09DEP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules Bratslavsky and SolstenXP study refers to the device as a ‘‘subsea intervention device,’’ while some in the industry also refer to the SSID as a ‘‘mudline closure device.’’ Irrespective of these synonymous titles, BSEE uses the term SSID to refer to a fit-for-purpose device that may be used for different types of situations, including for well intervention applications, and can be used in different locations, including outside of the Arctic. However, for the purposes of Arctic OCS exploratory drilling from a MODU, BSEE is proposing to define the minimum acceptable capabilities and functions of an SSID. BSEE notes that, outside of the Arctic OCS, operators are contemplating using SSIDs for future projects, and SSIDs have already been approved for use in other parts of the OCS. The NPC 2019 Report notes that the requirement to drill an SSRW to mitigate the risk of a late season well control event continuing over the winter season is ‘‘outdated.’’ The 2019 report concludes that SSIDs and capping stacks are superior solutions that could stop the flow of oil and allow intervention through the original borehole before a relief well could be completed. (NPC 2109 Report at 19). The SSID requirements BSEE is proposing to establish in this proposed rule would not apply to projects outside of the Arctic OCS. The design requirements for those SSIDs would be based on the needs of a particular project and may or may not be similar to what BSEE is proposing in this proposed rule. BSEE requests comments on these SSID requirements as outlined in the proposed rule. Under proposed paragraph (a) of § 250.472, if the operator elects to satisfy the requirements of this section by using an SSID, BSEE would require the operator to ensure that the SSID and well design (including the casing and cementing program) are designed to achieve a full shut-in, without causing an underground blowout or having reservoir fluids broach to the seafloor. Currently, BSEE’s regulations for SCCE under § 250.462 do not require all wells to be designed to achieve a full shut-in (e.g., partial shut-in is acceptable) as there are methods to control the residual fluid flow into a surface production and storage system when a well is designed for partial shutin. However, because BSEE is proposing that the SSID be designed to achieve full wellbore shut-in until kill operations are completed, it is important that the well design assures that the well will be able to withstand the associated loads for the entire time the SSID is closed (e.g., prevents gas migration in the shut-in VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 wellbore). If the wellbore is compromised during or after a full shutin, an underground blowout or broach to the seafloor may occur. BSEE reviewed available incident data on loss of well control events,48 and determined that, on average, five loss of well control events occurred each year on the OCS between 2007 and 2017. The well design language in proposed paragraph (a) would also require the operator to account for the stresses and loads placed on the well from the equipment that may be required to regain control after a loss of well control event. This includes the SSID, BOP stack, and capping stack. It is imperative that all well components are designed to withstand all potential loads and stresses placed on the well, including those that may be required during well control situations and deployment of SCCE (i.e., the well must be able to support a capping stack in addition to the other equipment required for normal operations). The need for the operator to account for all potential loads placed on the well also includes consideration of conditions where a well would be shutin over the ice season. For example, in typical well control operations, a BOP is used to stop the uncontrolled flow and shut-in the well. It remains shut-in for a relatively short period of time while well kill operations are implemented and, if needed, materials and personnel are mobilized to the rig. For wells that may be shut-in for extended periods, the operator must consider the potential effects of gas expansion within the well. For example, in reservoirs containing gas, which is less dense than the liquids in the wellbore (e.g., drilling mud, completion fluid, brine), the gas will migrate upward in the wellbore until it reaches the closed BOP. This gas exerts a lower hydrostatic pressure than the column of oil or drilling fluids in the wellbore, and more of the reservoir pressure is transmitted to the top of the wellbore as a result. As the hydrostatic pressure acting on the bubbles decreases, the bubbles expand. As these bubbles continue to migrate and expand over time, the wellbore pressure profile increases. What was once a low pressure at the top of the well, with a hydrostatic pressure gradient below it, will eventually increase to reservoir pressure, increasing the downhole pressure. As the pressures in the wellbore increase, some of the liquid may bleed into the open formation(s). Eventually, the 48 See, BSEE’s website at https://www.bsee.gov/ stats-facts/offshore-incident-statistics. PO 00000 Frm 00029 Fmt 4701 Sfmt 4702 79293 pressure may exceed the strength of the formation (fracture pressure) in the wellbore, potentially resulting in a fracture of the formation and an underground blowout. Because proposed paragraph (a) of § 250.472 contemplates allowing the operator to leave a well shut-in from one openwater season to the next (i.e., in the case of a late season well control event), wells need to be designed to withstand this potential loading condition. In a new paragraph (a)(1), BSEE proposes to establish performance-based design requirements for the SSID. BSEE would require the operator to ensure that the SSID is designed to: (1) Close and seal the wellbore, independent of the BOP; (2) Perform under the maximum environmental and operational conditions anticipated to occur at the well; (3) Be left on the wellhead in the event the drilling rig is moved off location (e.g., due to storms, ice incursions, or emergency situations); (4) Preserve isolation through the winter season without relying on the elastomer elements of the rams (e.g., by using a well cap) and allow re-entry during the following open-water season; and (5) In the event of a loss of well control, preserve isolation until other methods of well intervention may be completed, including the need to drill a relief well. BSEE’s analysis of loss of well control events data indicates that the most common methods employed to regain control of a well include pumping mud or cement into the uncontrolled well or activating mechanical well control equipment (e.g., blowout preventer). These SSID design requirements would help ensure the device is capable of shutting in and containing all fluids within the wellbore for an entire ice season (in the case of a loss of well control event too late in the open-water season to provide enough time for the operator to perform well kill or plug and abandonment operations). BSEE is basing the proposed design requirement for the SSID to be capable of preserving isolation through the winter season without relying on the elastomer elements of the rams (e.g., by using a well cap) on information it gained from the Kara Sea project. BSEE understands that the SSID used in the Kara Sea project was capable of preserving isolation over an entire ice season because it was designed to have a metalto-metal cap installed on top of the SSID, after the BOP is detached and all equipment is moved off of the drill site. BSEE understands that isolation could E:\FR\FM\09DEP2.SGM 09DEP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 79294 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules not be achieved over the ice season if the shut-in relied solely on the elastomer elements of the rams. The design requirements would also ensure the SSID will allow for re-entry to perform well recovery operations during the following open water season. In a new paragraph (a)(2), BSEE proposes to require that the operator’s SSID include the following equipment: (1) Dual shear rams, including ram locks; one ram must be a blind shear ram; (2) A redundant control system, independent from the BOP control system, that includes ROV (remotely operated vehicle) capabilities and a control station on the rig; (3) Independent, dedicated subsea accumulators with the capacity to function all components of the SSID; and, (4) Two side inlets for intervention, one of which must be located below the lowest ram on the SSID. The dual shear ram requirement in proposed paragraph (a)(2)(i) would ensure that the SSID is capable of shearing through drill pipe, sealing the wellbore, and containing the fluids before they can escape during a loss of well control event. BSEE notes that the NPC 2019 Report describes the SSID as having shearing/sealing rams. In fact, when describing the SSID used in the Kara Sea Project, the report explains that the device utilized dual blind shear rams. While proposed paragraph (a)(2)(i) would require only one of the rams to be a blind shear ram, BSEE is seeking comment on the advisability of requiring dual blind shear rams on the SSID. As described in the bow-tie diagram of the NPC 2019 Report, the SSID is the last line of prevention to minimize the impacts of an event. (NPC 2019 Report at 14). The redundant control system requirements in proposed paragraph (a)(2)(ii) would ensure there is reliability in the system and that the SSID will function when needed in an emergency situation. This proposed requirement is intended to align with the existing requirement in existing § 250.734(a)(2), which requires subsea BOPs to have a redundant control system to ensure proper and independent operation of the BOP system. With respect to the requirement that an SSID have a separate control station on the rig that is independent from the BOP control system located on the rig, it is important for the SSID functions to be controlled by personnel directly involved in the drilling process to allow for an appropriate response from a ‘‘situationally aware’’ individual. Therefore, while BSEE is proposing to VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 require the SSID control system to remain independent of the BOP control system, it would not require those systems to be located in separate locations. BSEE is seeking comment on whether the proposed requirement in paragraph (a)(2)(ii) is appropriate for the SSID or whether there are additional ways to enhance the system’s reliability. For example, BSEE is contemplating whether it may be more appropriate to require the SSID’s redundant control system capabilities to be separate from the ROV’s capabilities. BSEE is also considering, as part of the final rule, requiring the SSID control systems to be consistent with the fully redundant control system requirements described in American Petroleum Institute (API) Specification (Spec.) 16D (e.g., yellow pod and blue pod). More specifically, BSEE is further considering whether there should be an additional manual method (separate from the redundant control system) to close the SSID’s rams with the ROV and whether it may be appropriate to require a standby or tending vessel with an ROV. These measures could address cases where the SSID’s control system on the drilling rig is not available (e.g., due to failure or an evacuation of the rig). The requirement in proposed paragraph (a)(2)(iii) for SSIDs to have independent, dedicated subsea accumulators with capacity to function all components of the SSID would help ensure that, if the BOP system fails, the SSID will have the capabilities to function as needed, independent of the BOP’s accumulator system. The requirement in proposed paragraph (a)(2)(iv) for SSIDs to have two side inlets, with one of the inlets located below the lowest ram on the SSID, would allow for re-entry through the SSID to perform well intervention operations. Side inlets allow the operator to pump fluids into the well to kill the well, before opening the blind shear ram to perform additional well intervention operations. In proposed paragraph (a)(3), BSEE would require the SSID to include ROV intervention equipment and capabilities to function the SSID. BSEE regulations currently include requirements for ROV intervention capabilities in relation to a BOP’s functionality. BSEE is proposing similar requirements for the SSID because the SSID functions similarly to a BOP. Under proposed paragraph (a)(3), the ROV equipment and capabilities must: (1) Be able to close each shear ram under the Maximum Anticipated Surface Pressures (MASP), as defined for the operation; PO 00000 Frm 00030 Fmt 4701 Sfmt 4702 (2) Include an ROV panel that is compliant with API RP 17H (as incorporated by reference in § 250.198); (3) Meet the ROV requirements in existing § 250.734(a)(5); and, (4) Have the ability to function the SSID in any environment (e.g., when in a mudline cellar). The requirement in proposed paragraph (a)(3)(i) for the ROV to be able to close each shear ram under the operation’s defined MASP would ensure that the operator is able to remotely close (through the ROV) each shear ram on the SSID and seal the well, which are the most critical functions during a well control event. The requirement in proposed paragraph § 250.472 (a)(3)(ii) for the ROV to have panels that are compliant with API RP 17H would ensure that the operator’s ROV capabilities for the SSID follow BSEE’s existing ROV panel requirements for BOP systems. API RP 17H provides recommendations and overall guidance for the design and operation of ROV tooling used on offshore subsea systems (e.g., provision for high flow Type D hot stabs). This guidance is critical to ensuring safe and reliable ROV operations. In conjunction with the proposal in paragraph (a)(3)(ii) to require the operator’s ROV panels to be compliant with API RP 17H, BSEE proposes to add the citation for proposed § 250.472(a)(3) to § 250.198(e)(73). Section 250.198(e)(73) documents the locations in the regulations where API RP 17H is incorporated by reference as a regulatory requirement, which would include § 250.472(a)(3) under this proposed rule. Adding the citation for § 250.472(a)(3) to § 250.198(e)(73) would clarify that API RP 17H is a regulatory requirement when complying with § 250.472 and is subject to BSEE oversight and enforcement in the same manner as other regulatory requirements. The requirement in proposed paragraph (a)(3)(iii) for the operator to meet the requirements in existing § 250.734(a)(5) would ensure that the operator has a trained ROV crew on each rig unit. The crew must ensure that the ROV is maintained and capable of carrying out the necessary tasks during emergency operations and be trained in operating the ROV, including stabbing into the ROV intervention panel on the SSID. The crew must also have the capability to communicate with designated rig personnel, who are knowledgeable about the SSID’s capabilities. The requirement in proposed paragraph (a)(3)(iv) for the ROV to be capable of functioning the SSID in any E:\FR\FM\09DEP2.SGM 09DEP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules environment is meant to address those cases where it may be necessary to place the SSID in an enclosed or restricted environment. For example, if the SSID is used in an area with ice scouring or with deep ice keels, the SSID would be placed in a mudline cellar. If the ROV panels are attached to the SSID, the ROV may not be able to access the panels if there is not enough space in the cellar. The operator must ensure that the ROV has the capabilities to address these types of scenarios. BSEE is aware of current projects that are evaluating positioning the ROV panels away from the SSID. The ROV would function the SSID from the remote panel, which would be hardwired to the SSID. In addition, it is possible for a mudline cellar to be constructed via a dragline. In such a case, the mudline cellar could be constructed wide enough to provide adequate space for the ROV to access the panel if the panel was attached to the SSID. BSEE proposes to make the requirement in proposed paragraph (a)(3)(iv) flexible, recognizing that there are multiple ways an operator could address this type of concern. In general, however, BSEE is seeking comment on the feasibility of installing an SSID below a subsea BOP in cases where the SSID would also be installed in a mudline cellar. BSEE’s current regulations at §§ 250.734(a)(13) and 250.738(h) require placement of subsea BOP systems in mudline cellars when drilling occurs in areas subject to icescouring. In addition, proposed § 250.720(c)(2) requires placement of the wellhead in a mudline cellar in areas subject to ice-scouring. BSEE is requesting more information about whether there are any other operational or installation challenges that the operator may encounter when attempting to effectively operate the SSID in this environment. If so, what are those challenges, and how could they be addressed? BSEE understands that the SSID used in the Kara Sea could be manually activated using acoustic technologies. While such technologies are available to function the SSID from a remote location, BSEE is proposing to require use of an ROV, as described in proposed paragraph (a)(3). BSEE understands that ROVs are more reliable for this type of application. However, BSEE requests that commenters provide any information that demonstrates the reliability of acoustic (or other) technologies to actuate an SSID from a remote location. Furthermore, although BSEE is not proposing to require the SSID to have a self-actuating function, the Bureau is contemplating whether one may be VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 necessary for certain emergency situations. BSEE is aware that in the Arctic OCS, it is possible for a drilling vessel to sink and allide with (i.e., strike against) the top of a wellhead during a loss of well control event (Bratslavsky and SolstenXP at 17). As discussed in the previous section, all exploratory drilling in the Beaufort Sea and the Chukchi Sea has taken place in waters less than 167 feet deep, and as recent as April 2020,49 there were active leases in the Beaufort Sea where an SSID could have been deployed. These leases were located in water depths less than approximately 170 feet deep. In these water depths, during an emergency, a vessel could sink before the BOP or SSID can be activated. A self-actuating system incorporated into the SSID could potentially address this problem. One option BSEE is considering is whether it may be appropriate to establish an autoshear and deadman system requirement for the SSID. The intent would be to address those emergency situations, such as when a sunken MODU allides with the wellhead, where the SSID could no longer be functioned via the ROV (due to lack of access) or a control station on the drill ship. BSEE’s regulations already address autoshear and deadman systems for subsea BOPs. Existing § 250.734(a)(6)(i) requires subsea BOPs to have an autoshear system that is designed to automatically shut-in the wellbore in the event of a disconnect of the lower marine riser package (LMRP). Also, existing § 250.734(a)(6)(ii) requires a deadman system, that is designed to automatically shut-in the wellbore in the event of a simultaneous absence of hydraulic supply and signal transmission capacity in the subsea control pods, respectively. However, BSEE did not propose this requirement for SSIDs in this rulemaking. The SSID is meant to be a backup to the BOP, and it is not necessary for the SSID to have the same automatic emergency functions as the BOP. There could potentially be negative consequences if both systems were to automatically function. For example, there could be a situation where the BOP’s autoshear or deadman systems function, but they are not able to shutin the well because a non-shearable drill string is positioned across the rams. If the subsea BOP rams are experiencing 49 In April 2020, the only leases with potential projects that would be subject to the Arctic OCS’s SSID or SSRW requirements were relinquished. However, there are other active leases in the Beaufort Sea located nearer to the shore in shallower waters where exploration and development projects are actively being pursued (primarily through man-made gravel islands). PO 00000 Frm 00031 Fmt 4701 Sfmt 4702 79295 this issue, then the SSID may also encounter the same problem, depending on the part of the drill string that is across the rams at that time. In this scenario, it would be more appropriate to assess the situation to determine whether other well intervention operations could be performed to address the position of the drill string, before activating the SSID. Regardless of these challenges, BSEE is seeking comment on what fail-safe mechanism(s) may be appropriate to address cases where the BOP fails and the SSID is inaccessible by an ROV or a control station. If an autoshear system or a deadman system are appropriate fail-safe mechanisms to add to the SSID, BSEE is seeking input on what criteria should be used to function these systems, to ensure the system does not function at the wrong time or interferes with or impacts the BOP’s autoshear and deadman systems. BSEE is also seeking comment on how to ensure that the SSID will be able to preserve isolation over the winter season in the event of a late-season emergency incident, such as a sunken drillship. As previously mentioned, BSEE understands that prior SSIDs have planned for long-term isolation through installation of a metal-to-metal cap (i.e., a well cap) on the SSID before leaving the device on the seafloor over the winter season. In the case of a lateseason emergency situation that prevents access to the SSID to install a metal-to-metal cap, how would isolation be preserved through the winter season? In addition, BSEE is soliciting comment on whether the regulations should require use of an autoshear or deadman system in cases where these systems are not built into the BOP’s system. As previously mentioned, BSEE’s autoshear and deadman system requirements currently apply to subsea BOPs. There is no current requirement to use an autoshear or deadman system when surface BOPs are used. BSEE would expect that if an operator uses a surface BOP, the operator would still install the SSID on the seafloor. BSEE seeks comment on whether it would be appropriate in such a case to require use of an autoshear or deadman system on the SSID. If so, what criteria should BSEE apply to the functioning of the autoshear or deadman systems in an environment where a surface BOP is used? Furthermore, BSEE welcomes any other comments, unrelated to autoshear or deadman systems, regarding use of a surface BOP. With respect to installation of the SSID, BSEE proposes in paragraph (a)(4) to require operators to install the SSID: (1) Below the BOP; E:\FR\FM\09DEP2.SGM 09DEP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 79296 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules (2) At or before the time they install their BOP; and (3) In a way that will provide protection from deep ice keels in the event it must remain in place over the winter season (e.g., installed in a mudline cellar). Installing the SSID below the BOP would allow for quick detachment of the BOP and other equipment above the SSID, which would be critical when moving off of a location for emergency purposes. With respect to timing of the SSID’s installation, the operator would be required to install the SSID at or before the time they install the BOP. The proposed requirement for the SSID to be installed in a way that will provide protection from deep ice keels would help ensure that the device is not damaged by ice in areas of ice scour. As previously discussed, this could be accomplished by placing the SSID in a mudline cellar. In complying with this proposed requirement, the operator must also consider situations where the drill site is not located in an ice scour area, but could experience ice floes with keels deep enough to clip and compromise the SSID if left on the seafloor over the winter season. In a new paragraph (a)(5), BSEE proposes to require the operator to test the SSID according to the BOP testing requirements in § 250.737, What are the BOP system testing requirements? The SSID’s testing requirements should align with the BOP testing requirements since, as previously mentioned, the SSID functions similarly, and in addition, to a BOP. This testing would aid in predicting future performance of the SSID to ensure that the device will function when needed during an emergency situation. While BSEE proposes to align the SSID testing requirements with the Bureau’s existing BOP testing requirements, BSEE welcomes input on whether there are more appropriate and reliable testing methods. For example, what testing procedures have been used in the past to test an SSID when it was deployed? For future operations, what testing procedures are being developed specifically for an SSID? What testing procedures should be applied to SSIDs, and why? Overall, BSEE intends for the SSID to provide time for the operator to marshal the equipment and materials necessary to permanently address a well control event, without the constraints of seasonal ice coverage, and to prevent the potential environmental impacts that could occur if an out of control well was allowed to flow over the season when the operator would not have access to the site due to ice. The SSID, VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 along with the proper well design, would allow the well to be shut in over the ice season without requiring additional vessels and the situation addressed permanently in the following open water season. It would also allow the operator the time necessary to complete the intervention, without the well flowing, if unforeseen problems are encountered. Collectively, the SSID’s design requirements; equipment specifications; ROV intervention capabilities; installation requirements; and testing requirements; together with the additional well design requirements, would help ensure that the device will function when needed during an emergency situation and will be capable of controlling the well over the ice season, if necessary, until the operator returns to perform well intervention operations during the following openwater season. In connection with that well intervention operation, BSEE may still exercise its existing authority to also require the operator to drill a relief well to permanently plug and abandon the out-of-control well, if needed. BSEE reviewed recent incident data from 2013 to 2017, which may be accessed on BSEE’s website at https://www.bsee.gov/ stats-facts/offshore-incident-statistics, to try to identify any past incidents involving the use of a BSEE directed relief well to remedy the loss of well control. Aside from the Macondo well incident in 2010, one incident in 2013 required the drilling of a relief well (see https://www.bsee.gov/newsroom/latestnews/statements-and-releases/pressreleases/drilling-of-relief-well-begins-atsouth). Other loss of well control events during that timeframe were successfully remedied with conventional well control methods. These incidents occurred in the Gulf of Mexico and were controlled by either circulating heavier weighted muds into the well or closing the BOP (or both), to control pressures within the well. BSEE would evaluate the individual circumstances associated with each case to make this determination. For these reasons, BSEE’s proposed changes to § 250.472 would maintain safety and environmental protection, though BSEE invites comment on the technical feasibility of such requirements. BSEE is seeking comment on whether the use of an SSID, particularly in a case where a subsea BOP is deployed, could present operational or installation challenges. For example, if the well is not located in an ice scour area and the BOP system, including the LMRP, and the SSID are placed on the seafloor, then these pieces of equipment could get as tall as 88 feet when installed (BOP PO 00000 Frm 00032 Fmt 4701 Sfmt 4702 approximately 70 feet + SSID approximately 18 feet). In addition, the bottom of a ship’s hull, in the case where a drillship is used, may extend as much as 40 feet into the water from the sea surface. Historically, drilling in the Beaufort Sea and the Chukchi Sea has occurred in waters less than 167 feet deep. With as much as 128 feet of water column taken up by the BOP system, SSID, and ship’s hull, very little space remains for operations between the bottom of the ship and the top of the well control system. BSEE seeks comment on what sorts of challenges operators have faced or would anticipate facing in the scenario just described. BSEE would also like to know how operators addressed those challenges in the past or could address them for future operations, taking into account the unique characteristics and extreme conditions of the Arctic OCS. BSEE is also generally seeking comment on its proposed changes to § 250.472. For example, BSEE is seeking comments on how well design could be better addressed in this rulemaking to enhance overall safety of operations on the Arctic OCS. Is the well design requirement proposed in paragraph (a) adequate to address the situations that may be encountered if a well is shut-in with an SSID over a winter season? As previously described, there could be cases where the wellbore pressure profile may increase to reservoir pressures at the top of the well over the course of a winter season. What other scenarios should BSEE consider that could occur in the well over the ice season that could be addressed in proposed paragraph (a)? • Proposed Paragraph (b)— Complying with § 250.472 by Having Access to a Relief Rig As discussed earlier, BSEE proposes to combine existing paragraphs (a) and (b) into a single, new paragraph (b), Relief Rig, for organizational purposes because both existing paragraphs cover relief rigs. Combining existing paragraph (a) into proposed paragraph (b) would not be a substantive modification to BSEE’s regulations because the specific requirements from existing paragraph (a) would remain unchanged. More specifically, the provision in existing paragraph (a) that requires the operator’s relief rig to comply with all other requirements of 30 CFR part 250 that pertain to drill rig characteristics and capabilities, and requires the relief rig to be able to drill a relief well under anticipated Arctic OCS conditions, would be relocated to proposed paragraph (b)(1). The provision in existing paragraph (a) that provides that the Regional Supervisor E:\FR\FM\09DEP2.SGM 09DEP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules may direct the operator to drill a relief well in the event of a loss of well control would be relocated to proposed paragraph (b)(2). Æ Last Casing Point Prior to Penetrating a Zone Capable of Flowing Hydrocarbons in Measurable Quantities Substantively, BSEE proposes to revise the requirements in existing paragraph (b) that prescribe the availability of the relief rig. BSEE would maintain the requirement for the operator to have access to a relief rig, different from its primary drilling rig, when drilling or working below the surface casing. However, BSEE proposes to add a new provision to the newly rearranged proposed paragraph (b) stating ‘‘However, the Regional Supervisor will approve delaying access to your relief rig until your operations have reached the last casing point prior to penetrating a zone capable of flowing hydrocarbons in measurable quantities, provided that you submit adequate documentation (such as, but not limited to, risk modeling data, off-set well data, analog data, seismic data), with your APD, demonstrating that you will not encounter any abnormally highpressured zones or other geological hazards. The Regional Supervisor will base the determination on any documentation you provide as well as any other available data and information.’’ BSEE would also add new language at the beginning of existing paragraph (b) that says ‘‘Relief Rig. If you choose to satisfy this requirement by having access to a relief rig, you must have access to your relief rig at all times when you are drilling below or working below the surface casing during Arctic OCS exploratory drilling operations.’’ This language would simply clarify that if the operator chooses to use a relief rig to comply with proposed § 250.472, it must have access to its relief rig at all times when drilling below or working below the surface casing. The changes described in this paragraph would be shown as a general requirement in proposed paragraph (b). BSEE’s proposed revisions to paragraph (b) would potentially provide an opportunity for the operator to adjust the point in time during its operations when it must stage its relief rig. If the operator is able to demonstrate to BSEE that the operations it plans to conduct below the surface casing would not encounter any abnormally highpressured or other geologic hazards before reaching the last casing point prior to penetrating a zone capable of flowing hydrocarbons in measurable quantities, then BSEE would allow the VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 operator to delay staging of its relief rig until reaching that point. The changes BSEE is proposing would make proposed paragraph (b) of § 250.472 and proposed paragraph (a) of § 250.471 consistent, with respect to providing a potential opportunity to the operator to delay access to its SCCE (as described in § 250.471(a)(1) and proposed § 250.471(a)(2) and (3)) until its operations have reached the last casing point prior to penetrating a zone capable of flowing hydrocarbons in measurable quantities, so long as the operator submits adequate documentation, with its APD, demonstrating that it will not encounter any abnormally high-pressured zones or other geologic hazards before that casing point. The existing requirement in § 250.472(b) pertaining to the availability of a relief rig does not take into consideration that the operator may demonstrate, based on geologic and engineering analyses, that there could be zones below the surface casing that are not hydrocarbon-bearing or that have minimal or no potential to flow hydrocarbons in measurable quantities during drilling operations. In many cases, operators do not anticipate or encounter flowable hydrocarbons in measurable quantities until the target productive formation is reached. For example, a surface casing shoe setting depth for an Arctic OCS exploration well could be only 1,500 feet deep, but the hydrocarbon bearing formation may be thousands of feet deeper below that point. The existing regulations require the operator to stage its relief rig when drilling or working below the surface casing, even though geologic and engineering risk analyses the operator must submit as part of their APD may indicate that there is little or no potential for hydrocarbons to escape the formation and flow into the well prior to reaching the targeted productive formation. In such circumstances, the operator could safely drill for thousands of feet below the surface casing without any identifiable need for a relief rig. This proposed change would, when appropriate, eliminate the need for the operator to stage its relief rig while drilling through low risk, nonproductive sections of the well below the surface casing. Arctic regional pore pressure modeling conducted by BOEM for an area in the Beaufort Sea identifies a general uniformity following an average pressure gradient (i.e., normally pressured) up to approximately 7,500 feet to 8,500 feet, subsea. The typical reservoirs targeted for exploration in the Arctic are usually located at less than 8,000 feet. In the GOM, there are many PO 00000 Frm 00033 Fmt 4701 Sfmt 4702 79297 different geological features that can affect the pressure profiles and potentially create abnormal pressures (e.g., salt domes, and shallow water flow areas). An extensive amount of geophysical data already exists for certain areas of both the Beaufort and Chukchi Sea Planning Areas, and there has been extensive drilling in certain areas of the Beaufort Sea Planning Area. In the known geologic conditions of the U.S. Arctic, operators have a good understanding of the locations of reservoirs that they will encounter, which can be relatively shallow and normally pressured to certain depths. Therefore, it may not be necessary to have a relief rig immediately available when drilling through zones below the surface casing that do not have abnormally high formation pressures or contain other geological hazards, and do not have the potential to flow hydrocarbons in measurable quantities as they are penetrated. However, because geologic conditions are not uniformly normally pressured throughout the Arctic OCS, BSEE is maintaining the existing requirement to have the relief rig staged when drilling or working below the surface casing. At the same time, BSEE does not want to discount the possibility that future projects would not need to have the relief rig staged until reaching the last casing point prior to penetrating a zone capable of flowing hydrocarbons. The criteria BSEE proposes to rely on—that the operator can demonstrate to BSEE that it will not encounter ‘‘abnormally high-pressured zones or other geologic hazards’’—to determine whether to grant an exception accounts for those downhole risks that could lead to a blowout and may require the use of a relief rig. With respect to abnormally high-pressured zones, BSEE is concerned that there could be a case where a kick (an influx, or flow, of formation fluid from the high-pressured zone entering into the wellbore) is not controlled and could lead to a blowout. While there are means of mitigating the risk of a kick, (i.e., overbalanced drilling), the relief rig needs to be readily available if heavier weight drilling muds, the BOP and SSID, if applicable, fail to control the well. There could be other geologic hazards, such as fractured or high permeability zones, that may also pose a risk, particularly if those zones contain hydrocarbons. It is possible that normally pressured zones may be highly permeable or contain fractures, in which lost circulation can occur. This could cause a dynamic effect where drilling mud flows into the permeable formation E:\FR\FM\09DEP2.SGM 09DEP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 79298 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules and causing the circulating pressure to decrease below the zone’s pore pressure resulting in formation fluids flowing into the well bore. This may lead to a loss of well control. The relief rig needs to be readily available if heavier weight drilling muds, the BOP, and the capping stack, fail to control the well. However, if the operator is able to demonstrate that a highly permeable or fractured zone is predicted to only contain water, BSEE would consider allowing the operator to delay the staging of its relief rig. Under this scenario, the operator would be able to use the diverter system in conjunction with the BOP system to maintain safety and environmental protection because it would be unlikely for hydrocarbons to be released into the environment. The diverter system consists of a mechanical device similar to a BOP annular preventer. The diverter system is used to divert gases, fluids, and other materials flowing from the well, away from facilities and personnel. Also, an operator would pump fluid loss materials into the well to bridge the formation to reduce its permeability and allow drilling muds to isolate the formation from the well. To permanently address the incident, the operator could also install a liner or set a new casing point at the interval where that highly permeable or fractured zone is located. As requested in the sectionby-section discussion of § 250.471, BSEE would like to know whether there are more appropriate criteria, other than ‘‘abnormally high-pressured zones or other geologic hazards,’’ the Bureau should use to determine whether to allow the operator to delay its staging of the relief rig. BSEE’s proposed regulatory language describing the types of documentation it would consider adequate to demonstrate that abnormally high-pressured zones or other geologic hazards would not be encountered before reaching the last casing point prior to penetrating a zone capable of flowing hydrocarbons in measurable quantities— ‘‘such as, but not limited to, risk modeling data, offset well data, analog data, seismic data’’—is not meant to be an exhaustive list. BSEE would accept any other types of documentation the operator may provide that will help its demonstration. BSEE does not anticipate this submission requirement would lead to a significant information collection burden on the operator because it is normal practice for operators to gather these types of information in order to develop and design an offshore exploration drilling project in the Arctic OCS. BSEE is requesting comment on what other types of information could VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 be used to demonstrate the absence of abnormally pressured zones or other geologic hazards, and how burden on the operator could change—increase or decrease—if BSEE were to require its submission. At the APD stage, BSEE would evaluate the operator’s documentation along with other accompanying geologic and engineering information/analyses that must be submitted as part of their APD. BSEE would also take into consideration any other available G&G information, such as information gathered from prior drilling operations in the area (e.g., well log and pressure testing information), and any other applicable geophysical information (e.g., seismic data). BSEE makes clear in its proposed regulatory language that the Regional Supervisor will base the determination for whether to allow the operator to delay staging of its relief rig on the documentation the operator submits as well as any other available data and information. BSEE is also considering an alternative regulatory approach whereby the Bureau would instead revise existing paragraph (b) by replacing ‘‘surface casing’’ with ‘‘last casing point prior to penetrating a zone capable of flowing hydrocarbons in measurable quantities.’’ This option would adjust the point in time during operations when the operator must stage its relief rig. This alternative regulatory change would, instead, require the operator to stage its relief rig before drilling below or working below the last casing point prior to penetrating a zone capable of flowing hydrocarbons in measurable quantities. Under this regulatory option, BSEE would evaluate the geologic and engineering information/analysis the operator must submit as part of its APD, while also taking into consideration any other available G&G information the Bureau may have (e.g., off-set well data, such as well logs and pressure testing information, or geophysical information, such as seismic data). Based on these different sources of information, BSEE would determine whether there may be a need for the operator to position the capping stack at an interval earlier than last casing point prior to penetrating a zone capable of flowing hydrocarbons in measurable quantities. There may be cases where the operator or BSEE may not have sufficient G&G or analogous well data during the permit review process on a proposed project to provide an adequate level of certainty regarding anticipated formations that may be encountered prior to reaching the targeted productive formation. Therefore, BSEE is also PO 00000 Frm 00034 Fmt 4701 Sfmt 4702 contemplating, as part of this regulatory option, a clarification that the Regional Supervisor may require the operator to stage its relief rig prior to drilling below or working below the last casing point prior to penetrating a zone capable of flowing hydrocarbons in measurable quantities if BSEE determines there is insufficient G&G or analogous well data. For example, there may be insufficient G&G or analogous well data in cases where there have been a limited number of wells drilled within proximity to the planned well. In most cases, G&G and analogous well data are gathered from multiple sources. However, the same sets and amounts of data and information may not be available for each area, well, or project. There is no single set of criteria for determining the sufficiency of G&G or analogous well data. The more data that are available from sources near to the proposed drilling location, the greater confidence BSEE will have in the G&G interpretations. BSEE wants to ensure the operator has the most accurate data to make determinations about where the zones capable of flowing hydrocarbons in measurable quantities are located. This alternative regulatory option would maintain the same level of safety and environmental protection in comparison to BSEE’s proposed regulatory change. The decision on whether it is appropriate to delay positioning of the capping stack below the surface casing resides with BSEE. BSEE, ultimately, may not allow the operator to delay staging of the relief rig if there are potential risks below the surface casing that may require immediate relief rig deployment. However, the distinction under this regulatory option is that the operator would not need to specifically demonstrate that abnormally highpressured zones or other geologic hazards would be encountered above last casing point prior to penetrating a zone capable of flowing hydrocarbons in measurable quantities. BSEE would be responsible for making that determination. BSEE is specifically soliciting comments about its views of the benefits or disadvantages of this regulatory option and the need for the operator to verify on a case-by-case basis which zones are incapable of flowing hydrocarbons in measurable quantities. Æ Expected Seasonal Ice Encroachment at the Drill Site In the 2015 proposed Arctic Exploratory Drilling Rule, BSEE determined that, because Arctic OCS exploratory drilling operations from a MODU take place only during the open water season (i.e., that period of time in E:\FR\FM\09DEP2.SGM 09DEP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules the summer and early fall when ice hazards can be physically managed and there is no continuous ice layer over the water), it was critical to ensure that drilling (including relief well drilling) and other operations affected by sea ice are concluded before ice encroachment. Ice encroachment may complicate or prevent drilling, transit, and oil spill response operations. However, the analysis from the Bratslavsky and SolstenXP study shows that the sea ice capabilities of an ice class MODU and its support vessels can extend the currently available open-water operating seasons in the Chukchi and Beaufort Seas, depending on the drilling location within each planning area (id. at 143). Therefore, BSEE proposes to eliminate the reference to ‘‘expected seasonal ice encroachment’’ at the drill site in existing paragraph (b). BSEE, however, would retain the requirement clarifying that the relief rig must be different than the operator’s primary drilling rig and that the relief rig must be staged in a location such that it can arrive on site, drill a relief well, kill and abandon the original well, and abandon the relief well no later than 45 days after the loss of well control. This proposed regulatory change would effectively extend the drilling season in those cases where the operator’s MODU and associated support vessels are capable of safely operating beyond the period when seasonal sea ice begins to encroach at a drill site. The operator would no longer need to plan for their well operations to end in time to complete a relief well prior to the date when sea ice is expected to encroach on the drill site. The operator would, instead, have to plan to end its operations with sufficient time to complete its relief well prior to the anticipated date when sea ice conditions at the drill site are approaching the ice classification capability and rating limits of the operator’s vessels. BSEE and BOEM would evaluate the ice classification capabilities and limitations of the operator’s MODU and associated support vessels using existing permitting and review processes. For example, through BOEM’s EP review process, the operator is required under existing § 550.220(c)(6) to specify when it anticipates completing onsite operations and when it anticipates terminating drilling operations. In addition, § 550.220(c)(1) requires the operator to describe how it will design and conduct its exploratory drilling activities in a manner that accounts for Arctic OCS conditions. Furthermore, in the EP VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 regulations at proposed § 550.220(c)(1), BOEM would require the operator to submit a description of how all vessels and equipment will be designed, built, and/or modified to account for Arctic OCS conditions and how such activities will be managed and overseen as an integrated endeavor. This preamble discusses this proposed regulatory change in more detail later. Collectively, this information provided in an EP would allow BOEM (in conjunction with BSEE) to evaluate the capability of the operator’s equipment, including its vessels and procedures to manage and mitigate risks associated with Arctic OCS conditions. At the APD stage, BSEE would also review the capabilities of the operator’s MODU and associated supporting vessels. Existing paragraph (a)(2) of § 250.470, What additional information must I submit with my APD for Arctic OCS exploratory drilling operations? requires the operator to describe how it plans to prepare its equipment, materials, and drilling unit for service in the environmental, meteorological, and oceanic conditions it expects to encounter at the well site and how its drilling unit will be in compliance with the requirements of existing § 250.713, What must I provide if I plan to use a Mobile Offshore Drilling Unit (MODU) for well operations. Paragraph (d) of § 250.713 requires the operator, when using a MODU for well operations, to provide the current Certificate of Inspection (for U.S.-flag vessels) or Certificate of Compliance (for foreignflag vessels) from the USCG, as well as a Certificate of Classification. The operator must also provide current documentation of any operational limitations imposed by an appropriate classification society. As discussed earlier in this section, the Bratslavsky and SolstenXP study notes that a vessel’s capabilities are identified by the ice classification for the vessel, which is provided by marine classification societies such as ABS and DNV GL. BSEE would evaluate the information required under existing §§ 250.470(a)(2) and 250.713(d), together with BOEM’s approval of the operator’s end-of-season date(s) in the EP, to verify whether the vessels’ capabilities and limitations can support extending operations beyond when seasonal ice is expected to arrive at the drill site. However, in no case will BSEE approve a permit that proposes to use a vessel that does not meet the existing requirements of § 250.713, including providing a current certificate of inspection or compliance from the USCG. Finally, while BSEE is proposing these revisions to § 250.472, BSEE is PO 00000 Frm 00035 Fmt 4701 Sfmt 4702 79299 seeking comment on whether there are other appropriate approaches to well control operations in the Arctic, including alternative equipment/ technology or performance standards. For example, although the NPC 2019 Report recommends accepting the use of an SSID in place of the requirement for SSRW capability, it also recommends replacing the relief rig and SSRW requirements with requirements that specify the desired outcome (i.e., to stop the flow of a well and allow the operator to propose equivalent technology and demonstrate its capabilities). (NPC 2019 Report at 30). BSEE assumes that the NPC recommends specifying a desired performance-based outcome in the regulations that would allow the operator to propose and demonstrate technologies capable of meeting that standard at the permitting stage, rather than prescribing a particular technology, such as a relief rig. Subpart G—Well Operations and Equipment When and how must I secure a well? (§ 250.720) BSEE proposes to delete the last sentence in existing paragraph (c)(2) that states ‘‘BSEE may approve an equivalent means that will meet or exceed the level of safety and environmental protection provided by a mudline cellar if the operator can show that utilizing a mudline cellar would compromise the stability of the rig, impede access to the well head during a well control event, or otherwise create operational risks.’’ In its place, BSEE proposes to insert a new sentence that states ‘‘You may request, and the Regional Supervisor may approve, an alternate procedure or equipment in accordance with §§ 250.141 and 250.408.’’ BSEE, however, would preserve the basic requirement in in paragraph (c)(2) for the operator to use a mudline cellar or an equivalent means if there is indication of ice scour. The regulatory change BSEE is proposing in this section would make clear that BSEE could approve the equivalent means of doing so in accordance with §§ 250.141, May I ever use alternate procedures or equipment? and 250.408, May I use alternate procedures or equipment during drilling operations? The new language that BSEE proposes to insert reiterates longstanding regulatory provisions contained in §§ 250.141 and 250.408 that describe what procedures the operator must follow and standards it must meet to receive BSEE’s approval of a request to use alternate procedures or equipment to those required by regulation. Section E:\FR\FM\09DEP2.SGM 09DEP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 79300 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules 250.141 allows the BSEE District Manager or Regional Supervisor to approve the use of any alternate procedures or equipment that the operator may propose if the proposal provides a level of safety and environmental protection that equals or surpasses BSEE’s current requirements. It also describes the types of information the operator must submit or present to BSEE when requesting to use alternate procedures or equipment. Section 250.408 requires the operator to identify and discuss their proposed alternate procedures or equipment in their APD. Since the issuance of the 2016 Arctic Exploratory Drilling Rule, BSEE learned that there is an industry misconception that the last sentence in existing paragraph (c)(2) means that the operator would be required to use a mudline cellar in all cases, except when the operator can prove that the mudline cellar would present an operational risk—effectively narrowing the scope of §§ 250.141 and 250.408 in this context. However, BSEE did not intend that language to constrain the contexts in which operators could seek approval of alternatives to the mudline cellar requirement. Rather, in response to commenters expressing concern that use of a mudline cellar may create operational risks in certain contexts, BSEE introduced that language to make clear that alternate approaches were available in those contexts, while at the same time highlighting the general flexibility available under § 250.141, May I ever use alternate procedures or equipment? (see 81 FR 46507 and 46510). The last sentence in existing paragraph (c)(2) was not intended to, and did not, restrict or preclude use of the longstanding options for seeking approval of alternate procedures or equipment under §§ 250.141 and 250.408, which do not necessarily require a demonstration of operational risk. Thus, this proposed change would clarify that the operator has more flexibility to propose alternate solutions to the mudline cellar requirement under a broader range of circumstances than those described in the last sentence of existing § 250.720(c)(2). An operator could still base such a request on the same grounds that BSEE described in the language that we propose to delete (i.e., that installation of a mudline cellar in a specific case would cause operational risks). VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 B. Key Revisions Proposed by BOEM Title 30, Chapter V, Subchapter B, Part 550, Subpart B—Plans and Information Definitions. (§ 550.200) BOEM is proposing to eliminate the definition of the term ‘‘Integrated Operations Plan,’’ consistent with the proposal to eliminate the requirement for the operator to submit an IOP for the reasons listed immediately below. Removal of the IOP Requirement (§ 550.204) The 2016 Arctic Exploratory Drilling Rule discussed how commenters generally criticized the IOP provision as being duplicative or redundant of existing requirements (see 81 FR at 46492–46493). In 2016, when the rule was adopted, BOEM disagreed with these commenters and published responses to the commenters in the preamble. In its responses, BOEM discussed how the IOP was distinct from existing regulations, the importance of contractor management as it related to the IOP provisions, and the BOEM Regional Director’s ability to waive submission of required information in the EP that was already provided in the IOP. Circumstances have changed since the IOP requirement was originally adopted. The various Federal agencies have improved their coordination to such an extent that BOEM believes there is no need for operators to create and submit a separate IOP for that purpose. Much of the required content of the two documents overlaps, and in the 2016 rulemaking itself BOEM added requirements that the EP include additional information that made this overlap even greater. BOEM is now proposing to keep two important provisions from the IOP and incorporate them into the requirements for EPs. The first provision would reinforce BOEM’s commitment to operational safety, while the second provision would require the operator to provide details of how its operations would conform to the unique circumstances of the Arctic OCS. Taken together, the enhancements to BOEM’s regulations made in connection with the 2016 Arctic Exploratory Drilling Rule and the retention of these key provisions from the IOP make the IOP unnecessary and redundant. For these reasons, BOEM proposes to eliminate the requirement for preparing and submitting the IOP. In doing so, BOEM would delete all of § 550.204, and remove corresponding references to the IOP from §§ 550.200 and 550.206. Currently, BOEM requires the operator to submit an IOP at least 90 days before filing an EP with BOEM. The IOP is not PO 00000 Frm 00036 Fmt 4701 Sfmt 4702 subject to agency approval. BOEM developed the IOP requirement based on the Report to the Secretary of the Interior, Review of Shell’s 2012 Alaska Offshore Oil and Gas Exploration Program, prepared by DOI (60-Day Report), March 2013,50 which included 51 the following recommendation: All phases of an offshore Arctic program— including preparations, drilling, maritime and emergency response operations—must be integrated and subject to strong operator management and government oversight. (60day report, p. 3). The information provided in the IOP was intended to facilitate the prompt sharing of information among the relevant Federal agencies (e.g., BOEM, BSEE, USFWS, USCG, NMFS, U.S. Army Corps of Engineers, and EPA). Standing BOEM practice (LP–SOP–06 Standard Operating Procedure for Exploration Plans) in the Anchorage, Alaska OCS Office is to inform other agencies about an operator’s EP, well in advance of the completeness review (i.e., the deemed submitted determination) for the EP. BOEM successfully did so prior to the 2016 implementation of the IOP requirement. The IOP requirement does not supersede or supplant the operator’s obligation to comply with all other applicable Federal agency requirements. As described in the 2016 Arctic Exploratory Drilling Rule, the IOP process does not provide a mechanism for agencies to approve or disapprove the operator’s proposed activities. BOEM has no authority under the IOP provision other than to make unenforceable suggestions to the operator. If BOEM or another agency determined that an operator was failing to engage in the needed integrated planning in advance of EP submission, BOEM could only compel an operator to do so through the EP review process. The 2016 Arctic Exploratory Drilling Rule added informational requirements for EPs to address key concerns that motivated the IOP, as shown in Table 1, ‘‘Crosswalk between the IOP provisions proposed for removal and existing EP regulations and review practices.’’ Because this information is required in the EP, operators should be aware that they must plan for how they will manage contractors to reduce 50 Available at: https://www.doi.gov/sites/doi.gov/ files/migrated/news/pressreleases/upload/Shellreport-3-8-13-Final.pdf. 51 Report to the Secretary of the Interior, Review of Shell’s 2012 Alaska Offshore Oil and Gas Exploration Program, prepared by DOI (60-Day Report), March 2013, available at: https:// www.doi.gov/sites/doi.gov/files/migrated/news/ pressreleases/upload/Shell-report-3-8-13-Final.pdf. E:\FR\FM\09DEP2.SGM 09DEP2 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules operational risks and address the challenges associated with operations on the Arctic OCS. The EP regulations are clear that the operator must plan to coordinate the work of a number of contractors to ensure that time pressure, or other contractor complications, do not undermine safe and environmentally responsible operations. In particular, proposed § 550.220(c)(1) would require the operator to describe in the EP how it will design and conduct its exploratory drilling activities, and how it will manage and oversee these activities as an integrated endeavor. BOEM does not need, and nothing in OCSLA requires, an operator to inform Federal agencies about its planning on these issues in advance of an EP. The EP, however, will make evident whether the operator has done so, and if the EP does not address the operators’ planning on all the required elements, BOEM will return the EP to the operator to include the requisite information in accordance with existing § 550.231(b). As part of the 2016 Arctic Exploratory Drilling Rule, BOEM expanded the regulatory criteria for EPs to include information important for planning Arctic exploratory drilling. Specifically, BOEM expanded requirements for: Emergency plans at existing § 550.220(a), the EP’s suitability for Arctic OCS conditions at proposed § 550.220(c)(1), ice and weather management at existing § 550.220(c)(2), SCCE capabilities at existing § 550.220(c)(3), deployment for a relief rig at proposed § 550.220(c)(4), resourcesharing at existing § 550.220(c)(5), and anticipated end of seasonal operation dates at existing § 550.220(c)(6). BOEM’s EP and environmental impact analysis (EIA) requirements at existing § 550.202, What criteria must the Exploration Plan (EP), Development and Production Plan (DPP), or Development Operations Coordination Document (DOCD) meet?, existing paragraphs (a) and (c) of § 550.211, What must the EP include?, existing paragraph (c) of § 550.216, What biological, physical, 79301 and socioeconomic information must accompany the EP?, existing paragraphs (a) and (b) of § 550.219, What oil and hazardous substance spills information must accompany the EP?, existing paragraphs (b), (c)(2) and (5) of § 550.220, If I propose activities in the Alaska OCS Region, what planning information must accompany the EP?, proposed paragraph (c)(1) of § 550.220, existing paragraph (a) of § 550.224, What information on support vessels, offshore vehicles, and aircraft you will use must accompany the EP?, and existing paragraph (b)(7) of § 550.227, What environmental impact analysis (EIA) information must accompany the EP? require the operator to address issues that the operator also needs to consider in preparing the IOP. The following table provides a detailed analysis of how the key operational provisions of the IOP are addressed in BOEM’s existing regulations, and why the key safety provisions of the IOP will continue to be fully addressed by other provisions within BOEM’s regulations: TABLE 1—CROSSWALK BETWEEN THE IOP PROVISIONS PROPOSED FOR REMOVAL AND EXISTING EP REGULATIONS AND REVIEW PRACTICES IOP provision Coverage in BOEM’s continuing regulations, operator EPs, and review practices § 550.204(a)—The operator describes how vessels and equipment were designed for Arctic OCS conditions; § 550.204(b)—The operator includes a schedule of the exploratory program; § 550.204(c)—The operator describes how its plans account for Arctic OCS conditions; § 550.220 (c)(1)—The operator describes how drilling activities account for Arctic OCS conditions. § 550.211(a)—The operator includes a schedule and discussion of objectives for its exploration program. § 550.220 (c)(1)—The operator describes how drilling activities account for Arctic OCS conditions. § 550.220(c)(2)—The operator describes weather and ice forecasting and management plans. § 550.224(a)—The operator describes vessels and aircraft it would use during exploration, including storage capacity of fuels. § 550.202—BOEM must review plans to ensure they are safe and do not cause undue or serious harm or damage to the human, marine, or coastal environment. § 550.211(a)—The operator includes a schedule and discussion of objectives for its exploration program. § 550.220 (c)(1)—The operator describes how drilling activities account for Arctic OCS conditions. § 550.220(c)(2)—The operator describes weather and ice forecasting and management plans. § 550.220(c)(6)(ii) (proposed)—The operator would describe the termination of drilling operations consistent with the well control planning requirements under § 250.472 of this title. § 550.220(c)(2)—The operator describes weather and ice forecasting and management plans. § 550.220(b)—The operator would describe critical operations and curtailment procedures. § 550.220 (c)(1)—The operator describes how drilling activities account for Arctic OCS conditions. § 550.220(c)(2)—The operator describes weather and ice forecasting and management plans. § 550.202—BOEM must review plans to ensure they are safe and do not cause undue or serious harm or damage to the human, marine, or coastal environment. § 550.211(c)—The operator would describe the drilling unit, associated equipment, safety features, and storage of fuels and oils. § 550.220 (c)(1)—The operator describes how drilling activities account for Arctic OCS conditions. § 550.204(d)—The operator describes general abandonment plans for wells; § 550.204(e)—The operator describes its plans for responding and managing ice hazards and weather events; jbell on DSKJLSW7X2PROD with PROPOSALS2 § 550.204(f)—The operator describes work to be performed by contractors; § 550.204(g)—The operator describes how it will ensure operational safety; VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 PO 00000 Frm 00037 Fmt 4701 Sfmt 4702 E:\FR\FM\09DEP2.SGM 09DEP2 79302 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules TABLE 1—CROSSWALK BETWEEN THE IOP PROVISIONS PROPOSED FOR REMOVAL AND EXISTING EP REGULATIONS AND REVIEW PRACTICES—Continued Coverage in BOEM’s continuing regulations, operator EPs, and review practices IOP provision § 550.204(h)—The operator describes oil spill response plans; § 550.204(i)—The operator describes efforts to minimize impacts to local community infrastructure; § 550.204(j)—The operator describes how it could rely on local communities for parts of its exploratory drilling program. The following information that was previously required as part of the IOP submission, but not included in the EP requirements, is proposed to be added to the relevant sections of the EP: Existing regulation text New provision § 550.204(a)—The operator describes how vessels and equipment were designed for Arctic OCS conditions; § 550.220(c)(1)—The operator describes how the exploratory drilling (including vessels and equipment) would account for Arctic OCS conditions, including any allowances or limitations its vessels have from a classification society and/or the USCG. § 550.211(b)—the operator describes how it will ensure operational safety. § 550.204(g)—The operator describes how it will ensure operational safety; jbell on DSKJLSW7X2PROD with PROPOSALS2 § 550.219 (a) and § 550.219 (b)—The operator would describe its oil spill response plan and associated spill modeling report. § 550.216 (c)—the operator must analyze socioeconomic resources associated with its exploratory program. § 550.227 (b)(7)—The operator must describe socioeconomic resources including employment and subsistence resources and harvest practices. § 550.220 (c)(5)—The operator describes agreements it has with third parties in the event of an oil spill or emergency. § 550.219 (a) and § 550.219 (b)—The operator would describe its oil spill response plan and associated spill modeling report. § 550.227 (b)(7)—The operator must describe socioeconomic resources including employment and subsistence resources and harvest practices. To the extent that there is not an exact correlation between the information required in the IOP and that required in the EP, BOEM and BSEE believe that the additional information required in the IOP that is not in the EP is not necessary and certainly not necessary in advance of the EP. Furthermore, the BOEM Anchorage, Alaska OCS Office meets with members of the Interagency Working Group on Alaska Energy Permitting and other relevant agencies, before an EP is submitted or deemed submitted. Although BOEM previously argued that the IOP would not delay, but in fact, speed development by encouraging earlier review and coordination between regulatory agencies, BOEM no longer believes that is the case. While it is true that the IOP might speed up BOEM’s review and approval of an EP, by encouraging earlier review and coordination among agencies, such acceleration would not shorten the overall planning process undertaken by the operator to prepare and submit an EP. The operator should conduct the same degree of planning with or without an IOP, because such planning is necessitated by the EP requirements. The IOP merely shifts some of the agency review to earlier in the process. With or without a prescriptive requirement for an IOP, the operator’s thorough advance planning and VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 coordination between BOEM, the operator, and other agencies prior to submission, will result in fewer unexpected issues overall. In practice, the entire planning process from initial concept to actual drilling should be the same, with or without an IOP. What is more important in terms of timeline, is the detailed work the operator would conduct in preparing and submitting a well-crafted EP. How do I submit the EP, DPP, or DOCD? (§ 550.206) BOEM proposes to delete all references to the IOP in this section. The substantive provisions of this section that relate to EPs, DPPs, and DOCDs would remain unchanged. What must the EP include? (§ 550.211) BOEM proposes to move existing § 550.204(g) to § 550.211 as a new paragraph (b). All other provisions of § 550.211 would remain unchanged. The addition of the provision from § 550.204 into § 550.211 is designed to describe operational safety procedures that the operator has developed specific to conditions relevant on the Arctic OCS. These requirements were previously included in the IOP and not specifically enumerated as part of the requirements for an EP, although similar, more general requirements are already part of paragraphs (a), PO 00000 Frm 00038 Fmt 4701 Sfmt 4702 Description, objectives, and schedule, and (c), Drilling unit of this section. Paragraph (c) requires the operator to describe the drilling unit, associated equipment, safety features, and storage of fuels and oils. Without the current IOP provisions, the applicant would already need to have the information required by this paragraph in order to comply with BSEE’s regulations that currently require operators to develop, implement, and maintain a safety and environmental management system (SEMS) program (Subpart S, §§ 250.1900 to 250.1933), and as a result, moving this requirement from §§ 550.204 to 550.211 does not add any burden. Retaining this important provision as part of the requirements for exploratory drilling on the Arctic OCS ensures consistency with the goals of this rulemaking and to better align BOEM’s rules with those of BSEE. The following is a description of the provision that is being retained. The section describes how an operator will ensure operational safety while working in Arctic OCS conditions, including but not limited to: (1) The safety principles that it intends to apply to itself and its contractors; (2) The accountability structure within its organization for implementing such principles; E:\FR\FM\09DEP2.SGM 09DEP2 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules jbell on DSKJLSW7X2PROD with PROPOSALS2 (3) How it will communicate such principles to its employees and contractors; and (4) How it will determine successful implementation of such principles. The text of this transferred regulation provision is identical to what it was in § 550.204(g). As such, this addition to § 550.211 will not impose any new burden on lessees or operators. BOEM believes that retaining this important safety and environmental protection is a necessary part of ensuring that energy exploration and development activity is safe and environmentally responsible. If I propose activities in the Arctic OCS Region, what planning information must accompany the EP? (§ 550.220) BOEM proposes to revise paragraphs (c)(1) and (4), and (c)(6)(ii) of § 550.220 to conform to BSEE’s proposed changes to § 250.472, What are the additional well control equipment or relief rig requirements for the Arctic OCS? Existing paragraph (c)(1) of § 550.220 would be revised to add text to account for the text in existing § 550.204(a), which would be removed. With the elimination of § 550.204, BOEM proposes to combine the requirements of these two sections into a revised § 550.220(c)(1) that would require the operator to describe how its exploratory drilling (including vessels and equipment) would account for Arctic OCS conditions, including any allowances or limitations its vessels have from a classification society and/ or the USCG. BOEM is proposing to add a new informational requirement for modified vessels. BOEM is seeking to confirm that the operator meets the requirements of other entities with authority over vessels, not to impose requirements on those vessels. Although this revised paragraph would appear to add new requirements, in fact this revision would simply clarify and formalize the existing arrangements between BOEM and these other entities. This provision is proposed in order to avoid any potential confusion that might otherwise arise regarding the incorporation of the existing IOP requirements into the EP and how they may relate to the regulations and jurisdiction of the United States Coast Guard, or the flag state of the vessel. According to this proposed revision, for vessel modifications, the operator would describe any approvals from the flag state and vessel classification society and include in that description any allowances or limitations placed upon the vessel by the classification society and/or USCG. Vessel modifications may include the VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 suitability of vessels for Arctic conditions. These vessels may have or acquire classification from a ‘‘recognized organization’’ under the USCG’s Alternative Compliance Program (ACP).52 This specification provides the operator with guidance on what information the EP should contain to show that its vessels would be able to operate safely in the Arctic OCS. The specification would also show that BOEM is not duplicating regulations from USCG by acknowledging that the flag state, USCG, and/or the classification society have authority for approvals, allowances, and limitations placed upon modified vessels. For these reasons, this change would impose no material additional burden on lessee or operators beyond that which already exists and which has already been accounted for in the information collection burden for this section. To ensure consistency with BSEE’s proposed regulatory changes, BOEM is proposing to revise paragraphs (c)(4) and (c)(6)(ii) by requiring the operator to provide a general description of how they will comply with § 250.472, including a description of the termination of their operations. BSEE is proposing to revise § 250.472 to provide the operator with the option to either use an SSID or have access to a relief rig, as an additional means to secure the well in the event of a loss of well control, if the operator will be conducting exploratory drilling operations from a MODU. III. Additional Comments Solicited To assist BSEE and BOEM in these revisions, we are requesting public comments on specific issues discussed in the preamble. We will consider these comments while developing final regulations. To provide necessary context, we included the requests for public comments in appropriate locations throughout the preamble. For ease of commenting, we consolidated the requests for comments in this section of the preamble. While BSEE and BOEM are soliciting comment on specific topics associated with the proposed rule, the bureaus welcome the public to submit information or comment on any other topics relevant to this rulemaking that may not necessarily pertain to the bureaus’ specific solicitation. At this stage, the bureaus are open to considering any option that would improve the regulatory changes proposed, including maintaining the original requirement as part of the final rule. In all cases, please provide 52 33 U.S.C. 3316 and 46 CFR part 8 implement the USCG’s ACP. PO 00000 Frm 00039 Fmt 4701 Sfmt 4702 79303 supporting reasons and data for your responses. (i) Well Design When Using an SSID (§ 250.472(a))—BSEE is seeking comments on how well design could be better addressed in this rulemaking to enhance the overall safety of operations on the Arctic OCS. More specifically, BSEE would like to know whether the well design requirement in proposed § 250.472(a) is adequate to address situations the operator may encounter if a well is shut-in with an SSID over an entire winter season (e.g., six to nine months). These situations could include cases where the wellbore pressure profile may increase to reservoir pressures at the top of the well over the course of the winter season. BSEE would also like to know whether there are other scenarios that may occur in a shut-in well over the ice season. (ii) SSID Efficacy Relative to the Relief Rig and SSRW—BSEE is proposing to revise the relief rig and SSRW requirement with the intent to minimize environmental damage due to a prolonged ongoing well control event. When drilling a relief well, there is a delay in stopping the uncontrolled flow of oil and other fluid into the marine environment while relief well drilling operations are taking place. When properly functioning as designed, there is usually no delay for operational use of an SSID compared to the process of utilizing the relief rig or capping stack. If the SSID does not initially function, the SSID may still be activated through the ROV intervention equipment and capabilities that BSEE is proposing as a SSID design requirement. The SSID would operate independently from the BOP. By having two independent, redundant components, as part of the well control system, the overall reliability and effectiveness of the entire system increases. BSEE would like to know of any cases or data, in addition to what we have already discussed in the preamble, regarding the performance and reliability of the SSID and its effectiveness compared to drilling a relief well. (iii) NPC Report and Bratslavsky and SolstenXP Study—The NPC 2019 Report and the Bratslavsky and SolstenXP study have been valuable tools that were not available when promulgating the 2016 Arctic Exploratory Drilling Rule. BSEE requests the public to provide additional information or clarification related to those portions of these reports that the Bureau relied upon in this rulemaking. (iv) SSID Capability to Preserve Isolation Over the Winter Season (§ 250.472(a)(1)(iv))—BSEE proposes to require that the SSID must be capable of E:\FR\FM\09DEP2.SGM 09DEP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 79304 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules preserving isolation through the winter season without solely relying on the elastomer elements of the rams (e.g., by using a well cap) and allow re-entry during the following open-water season. BSEE understands that the operator is able to achieve long-term isolation by installing a well cap (i.e., a metal-tometal cap) on the SSID before leaving the device on the seafloor over the winter season. BSEE would like to know if there are means by which isolation would be preserved through the winter season in cases where a late-season emergency situation may not provide adequate time or ability to access the SSID to install a well cap. (v) SSID Dual Shear Requirement in Proposed § 250.472(a)(2)(i)—The NPC 2019 Report describes the SSID used in the Kara Sea Project as having dual blind shear rams. BSEE does not propose requiring the SSID to be equipped with dual blind shear rams. However, BSEE is seeking comment on the advantages or disadvantages between dual blind shear rams and using dual shear rams, with ram locks, with one ram being a blind shear ram. (vi) SSID Redundant Control System Capabilities (§ 250.472(a)(2)(ii))—BSEE proposes to require the SSID to use a redundant control system that includes ROV capabilities and a control station on the rig that is independent from the BOP control system. BSEE is contemplating whether it may be more appropriate to require the SSID’s redundant control system capabilities to be separate from its ROV’s capabilities, and to be consistent with the fully redundant control system requirements described in API Spec. 16D, Specification for Control Systems for Drilling Well Control Equipment and Control Systems for Diverter Equipment, Second Edition, July 2004, reaffirmed August 2013; incorporated by reference at § 250.198(e)(90); (e.g., yellow pod and blue pod). In addition to meeting the ROV requirements in existing § 250.734(a)(5), BSEE is also considering whether there should be an additional manual method (separate from the redundant control system) to close the SSID’s rams with the ROV and whether it may be appropriate to require a standby or tending vessel with an ROV. There could be cases where the SSID’s control system on the drilling rig is not available (e.g., due to failure or an evacuation of the rig). (vii) SSID Testing Requirements (§ 250.472(a)(5))—BSEE is seeking comment on whether it is appropriate to align the SSID’s proposed testing requirements with BSEE’s existing BOP testing requirements in § 250.737, What are the BOP system testing VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 requirements?, or whether there are more appropriate and reliable testing methods for SSIDs. BSEE would like to receive information on what testing procedures have been used in the past to test an SSID when it was deployed, or what testing procedures are being developed for future projects. (viii) Relief Rig Staging and Capping Stack Positioning Requirements—BSEE proposes to revise the staging and positioning requirement for the relief rig and capping stack, respectively, by providing an opportunity to the operator to adjust the point in time during its operations when it must stage or position these pieces of equipment, from ‘‘when drilling below or working below the surface casing’’ to ‘‘when drilling below or working below the last casing point prior to penetrating a zone capable of flowing hydrocarbons in measurable quantities.’’ If the operator is able to demonstrate to BSEE that the operations it plans to conduct below the surface casing would not encounter any abnormally high-pressured or other geologic hazards before reaching the last casing point prior to penetrating a zone capable of flowing hydrocarbons in measurable quantities, then BSEE would allow the operator to delay staging of its relief rig or positioning of its SCCE until reaching that point. BSEE would like to know whether there are more appropriate criteria, other than ‘‘abnormally high-pressured zones or other geologic hazards,’’ that should be used to determine whether to allow the operator to delay positioning of the capping stack and relief rig. BSEE is also requesting comment on what types of information, other than what is listed in proposed § 250.471(a) and § 250.472 (b)—risk modeling data, off-set well data, analog data, and seismic data, could be used to demonstrate the absence of abnormally pressured zones or other geologic hazards, and how burden on the operator could change— increase or decrease—if BSEE were to require submission of that information in its APD. (ix) Alternative Regulatory Approach to the Relief Rig and Capping Stack Positioning Requirements—BSEE is considering an alternative regulatory approach in which BSEE would revise the staging and positioning requirement for the relief rig and capping stack, respectively, by adjusting the point in time during its operations when it must stage or position these pieces of equipment, from ‘‘when drilling below or working below the surface casing’’ to ‘‘when drilling below or working below the last casing point prior to penetrating a zone capable of flowing hydrocarbons in measurable quantities.’’ However, PO 00000 Frm 00040 Fmt 4701 Sfmt 4702 there could be cases where the operator or BSEE may not have sufficient G&G or analogous well data on a proposed project to confidently identify the location of the first formation that the operator may encounter that is capable of flowing hydrocarbons in measurable quantities. BSEE is soliciting the public’s comments about this regulatory approach. BSEE is also soliciting comment about the need for the operator to verify, on a case-by-case basis, zones not capable of flowing hydrocarbons in measurable quantities. (x) Installing and Operating an SSID in a Mudline Cellar—BSEE is requesting more information about whether there are any operational or installation challenges the operator may encounter in attempting to operate the SSID when it is installed in a mudline cellar. In areas of ice scour, BSEE’s current regulations at §§ 250.734(a)(13) and 250.738(h) require placement of subsea BOP systems in mudline cellars. In addition, proposed § 250.720(c)(2) requires placement of the wellhead in a mudline cellar in areas of ice scour. Proposed § 250.472(a)(4)(i) would require installation of the SSID below the BOP. (xi) Operating an SSID with a Subsea BOP Installed on the Seafloor— Historically, drilling in the Beaufort Sea and the Chukchi Sea has occurred in waters less than 167 feet deep, and as recent as April 2020,53 there were active leases in the Beaufort Sea where an SSID could have been deployed. If the operator installs all well control systems on the seafloor (subsea BOP systems and SSIDs), there could be as much as 128 feet of water column taken up by these systems and a ship’s hull (if a drillship is used). BSEE would like to know what challenges operators could face in cases where there is little room to operate. BSEE would also like to know how operators addressed those challenges in the past, or how such challenges could be addressed in future operations. (xii) Fail-Safe Mechanisms Used on an SSID—BSEE is seeking comment on what fail-safe mechanisms exist that could be applied to an SSID in cases where a subsea BOP system is used. BSEE is contemplating whether it may be necessary to require mechanisms, such as autoshear or deadman for the SSID, to address emergency situations, such as a sunken MODU, where the 53 In April of 2020, the only leases with potential projects that would be subject to the Arctic OCS’s SSID requirements were relinquished. However, there are other active leases in the Beaufort Sea located nearer to shore in shallower waters where exploration and development projects are actively being pursued (primarily through man-made gravel islands). E:\FR\FM\09DEP2.SGM 09DEP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules subsea BOP system may have failed and the SSID could no longer be functioned via the rig or ROV (due to lack of access). BSEE currently has fail-safe requirements for subsea BOP systems (autoshear and deadman systems), which could be applied to SSIDs. However, there could be unintended consequences from applying these failsafe systems on an SSID when a subsea BOP system is used. BSEE is seeking comment on what fail-safe mechanisms could be deployed to address cases where the BOP fails and the SSID is inaccessible by an ROV or a MODU control station. If an autoshear system or a deadman system are appropriate failsafe mechanisms, BSEE is seeking input on what criteria should be used to function these systems, to ensure they do not function at the wrong time or interfere with or impact the subsea BOP’s autoshear and deadman systems. (xiii) Autoshear and Deadman System Requirements for Surface BOPs—BSEE is contemplating establishing autoshear and deadman system requirements in cases where operators use a surface BOP. BSEE does not currently require the use of an autoshear or deadman system with surface BOPs. BSEE is seeking comment on what criteria should be established to function the autoshear or deadman systems in connection with a surface BOP. BSEE welcomes any other comments, unrelated to autoshear or deadman systems, which require additional consideration in those cases where a surface BOP is used. (xiv) Outcome-based Well Control System Requirements—BSEE is seeking comment on other appropriate approaches to well-control operations in the Arctic. The NPC 2019 Report recommends accepting the use of an SSID in place of the requirement for SSRW capability. However, it also recommends replacing the relief rig and SSRW requirements with requirements that specify desired outcomes (i.e., to stop the flow of a well and allow the operator to propose equivalent technology and demonstrate its capabilities). BSEE assumes that the NPC recommendation would entail a performance-based approach to the regulations, in which the operator could propose and demonstrate new technologies to meet a stated objective, rather than being required to use certain technologies, such as a relief rig. (xv) Suspension of Operations—BSEE is considering the option of limiting the period during which a suspension would remain in effect to the period between one drilling season and the next when the operator is prevented from continuing its drilling or other VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 leaseholding activities due to seasonal conditions. BSEE is seeking comment on this regulatory option for the new SOO provision it is proposing in a new paragraph (d) of § 250.175, or any other option that could avoid or minimize the additional burdens associated with making requests on an annual basis (if the duration of the suspension needs to be longer), but still assure diligent lease exploration and development. (xvi) Other Solicited Comments— BSEE is also requesting comments on the specific costs and operational implications of each of the regulatory changes included in this proposed rule. IV. Procedural Matters A. Regulatory Planning and Review (Executive Orders (E.O.) 12866, 13563, and 13771) Executive Order 12866 provides that the Office of Information and Regulatory Affairs (OIRA) within OMB will review all significant rules. This proposed action is an economically significant regulatory action that was submitted to OMB for review, as it would have an annual effect on the economy of $100 million or more. BSEE and BOEM developed an economic analysis to assess the anticipated costs and potential benefits of the proposed rule. Due to uncertainty surrounding the outcome of ongoing litigation regarding the availability of Arctic OCS planning areas for future leasing and energy development, BSEE and BOEM developed two baseline activity level forecasts: (1) Activity levels expected if the full Beaufort and Chukchi Sea planning areas are reopened (i.e., the Full Arctic baseline), and (2) reduced activity levels if these areas remain withdrawn from leasing (i.e., the Restricted Beaufort baseline). Under either scenario, the proposed action would be economically significant as a result of the estimated cost savings of this proposed rule. BSEE and BOEM estimate the amendments proposed in this rulemaking would provide annualized net benefits of $142 million under the Full Arctic baseline, or $121 million under the Restricted Beaufort baseline, discounted at 7 percent. Details on the estimated cost savings of this proposed rule can be found in the rule’s Initial Regulatory Impact Analysis (IRIA). The net quantified benefits for this proposed rule are based on cost savings less forgone benefits. The cost savings to both government and industry result from removing regulatory redundancies, reduction in paperwork burdens, provision for alternative methods of compliance, and adoption of improved industry PO 00000 Frm 00041 Fmt 4701 Sfmt 4702 79305 technology. Forgone benefits result from slight increases in the risks to subsistence hunters and fishermen and wildlife stemming from an increased probability of small or catastrophic oil spills. The cost savings exceed the forgone benefits, leading to the net benefits summarized in the following paragraphs. This proposed rule would revise regulatory provisions in 30 CFR part 250, subparts A, C, D, and G, and 30 CFR part 550, subpart B. BSEE and BOEM have reassessed a number of the provisions promulgated through the 2016 Arctic Exploratory Drilling Rule and are proposing to revise some provisions to reflect performance-based standards rather than prescriptive requirements. Other revisions remove redundant regulatory oversight provisions and provide regional flexibility in the administration of suspensions and associated lease term extensions, without significantly impacting the current levels of safety and environmental protection. The bureaus sought the best available data and information to analyze the economic impact of these changes. The IRIA for this rulemaking can be found in the https://www.regulations.gov/ docket (Docket ID: BSEE–2019–0008). BSEE and BOEM are proposing to revise certain regulations promulgated through the 2016 Arctic Exploratory Drilling Rule based on new information generated since the 2016 rule was finalized, and to support the goals of the Administration’s regulatory reform initiatives, while ensuring safety and environmental protection. This proposed rule would revise certain existing regulations—§§ 250.105; 250.175; 250.198; 250.300(b); 250.470(b), (f), and (h); 250.471(a) and (b); 250.472(a), (b), and (c); 250.720(c); 550.200; 550.204; 550.206; 550.211; and 550.220(c). The bulk of the net benefits are derived from cost savings driven by a proposed revision to existing § 250.472(b) and (c), which is discussed below. The analysis suggests forgone benefits are small compared to the cost savings, and the primary forgone benefits are from possible impacts on the environment and subsistence hunting and whaling communities, that could be caused by an oil spill of greater duration and higher discharge volumes in the event the BOP, SSID, and capping stack were to fail in sequence, and a containment dome and flow system would be needed to capture oil flowing from the well while relief-well drilling operations are underway. These, and the other provisions, are discussed in greater detail within the IRIA. E:\FR\FM\09DEP2.SGM 09DEP2 79306 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules The largest contributor to net benefits attributable to the proposed rule is the proposed revision to existing § 250.472 paragraphs (a), (b), and (c). As promulgated under the 2016 Arctic Exploratory Drilling Rule, this provision currently requires the use of a ‘relief rig’ and adoption of a 45-day shoulder season. The relief rig is a secondary drilling vessel that is available and capable of drilling an SSRW in the event of a loss of well control. The 45-day ‘‘shoulder season’’ was the maximum time permitted by the regulations to mobilize the relief rig to an incident, drill a relief well, kill and abandon the original well, and abandon the relief well prior to expected seasonal ice encroachment at the drill site. This shoulder season necessarily compresses the already short Arctic drilling timeframe and also limits the ability of operators to drill and complete a well in one season. The proposed revisions to § 250.472 would provide the operator with the option to either use an SSID or have access to a relief rig, as an additional means to secure the well in the event of a loss of well control, if the operator will be conducting exploratory drilling operations from a MODU. The two features of this flexibility driving the cost savings are the removal of the shoulder season and removal of the requirement for the secondary drilling vessel, if the operator elects to install an SSID to comply with § 250.472. Because of the relative cost effectiveness of procuring, and potential well control advantages of installing an SSID versus mobilizing a relief rig and the necessary support vessels and personnel, BSEE assumes operators will prefer this option when using MODUs. This proposed change would produce an annualized cost savings of $142 million under the Full Arctic baseline, or $121 million under the Restricted Beaufort baseline, discounted at 7%. This proposed rule would reduce the burden imposed on industry, while maintaining safety and environmental protection. The forgone benefits of adopting the proposed rule include possible impacts on the environment, subsistence hunting and whaling communities, and an oil spill of greater duration with higher discharge volumes in the event a BOP and SSID were to fail. As discussed earlier in the preamble, BSEE proposes to require operators to operate an SSID independently from the BOP. By having two independent, redundant components (i.e., the BOP and the SSID) as part of the well control system, the overall reliability and effectiveness of the entire system increases. In the event both devices were to fail, the capping stack would still be used as required in the permitted timeframe. When a capping stack is used to contain a well, the relief well can be drilled without an ongoing active spill event. If the capping stack were to fail, the containment dome and flow system would be used to capture the oil flowing from the well while relief-well drilling operations are underway. Given that the proposed rule would remove the arrival timing requirement for these pieces of equipment, there may be a delay in their arrival, in comparison to the existing regulations. The amount of oil flowing from the well during that delayed period, would be the contributing factor to the proposed rule’s forgone benefits. However, as discussed in the IRIA, the probability of a catastrophic spill event (as a result of the BOP and SSID systems experiencing total failures) is low. Coupled with a scenario in which a BOP, SSID, and capping stack were all to fail, the probability of realizing these forgone benefits may be even lower. Nonetheless, the possibility exists and if the BOP were to fail and the SSID were to function as designed, there would be no forgone benefits in comparison to the existing regulations (and there might be a gained benefit since the SSID would activate immediately). As part of the final rule, BSEE and BOEM are contemplating the preparation of a sensitivity analysis for the Final RIA and are soliciting comments on ways to make the analysis as accurate as possible. The information we receive through public input on this proposed rule regarding the SSID’s performance, reliability, and effectiveness may inform the preparation of a sensitivity analysis. The timeframe of the present analysis is 24 years, composed of an initial 4 years with no activity followed by 20 years of activities beginning in 2024. The two tables below summarize BSEE’s and BOEM’s estimates of the total and annual net benefits derived from all proposed revisions and additions. Additional information on the time horizon, compliance costs, savings, benefits, and forgone benefits may be found in the IRIA published in the rule docket. 20-YEAR ESTIMATED ANNUALIZED NET BENEFITS ASSOCIATED WITH PROPOSED AMENDMENTS TO 30 CFR PART 250 SUBPARTS A, C, D, AND G, AND 30 CFR PART 550, SUBPART B UNDER FULL-ARCTIC BASELINE ASSUMPTIONS Year (2024–2043) Annualized (millions) ................................................................................................................................................ Discounted to 2019 at 3% Discounted to 2019 at 7% $149.8 $142.2 20-YEAR ESTIMATED ANNUALIZED NET BENEFITS ASSOCIATED WITH PROPOSED AMENDMENTS TO 30 CFR PART 250 SUBPARTS A, C, D, AND G, AND 30 CFR PART 550, SUBPART B UNDER RESTRICTED BEAUFORT BASELINE ASSUMPTIONS Year (2024–2043) jbell on DSKJLSW7X2PROD with PROPOSALS2 Annualized (millions) ................................................................................................................................................ This proposed rule would revise multiple provisions in the current regulations to implement performancebased provisions based upon reasonably obtainable information on safety, technical, economic, and other issues. Redundant or unnecessary reporting requirements are also being eliminated. VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 BSEE and BOEM are providing industry flexibility, when practical, to meet the safety or equipment standards, rather than specifying the compliance method. Based on a consideration of the qualitative and quantitative safety and environmental factors related to the rule, BSEE and BOEM determined that PO 00000 Frm 00042 Fmt 4701 Sfmt 4702 Discounted to 2019 at 3% Discounted to 2019 at 7% $126.0 $120.9 the proposed revisions would be consistent with the policies of the applicable E.O.s and the OCSLA. Executive Order 13563 reaffirms the principles of E.O. 12866 while calling for improvements in the Nation’s regulatory system to promote predictability, to reduce uncertainty, E:\FR\FM\09DEP2.SGM 09DEP2 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules jbell on DSKJLSW7X2PROD with PROPOSALS2 and to use the best, most innovative, and least burdensome tools for achieving regulatory ends. The E.O. directs agencies to consider regulatory approaches that reduce burdens and maintain flexibility and freedom of choice for the public where these approaches are relevant, feasible, and consistent with regulatory objectives. E.O. 13563 emphasizes that regulations must be based on the best available science and that the rulemaking process must allow for public participation and an open exchange of ideas. Furthermore, it promotes retrospective review of existing regulations that may be outmoded, ineffective, insufficient, or excessively burdensome. BSEE and BOEM have reviewed the existing regulations as amended by the 2016 Rule and have developed this proposed rule in a manner consistent with E.O. 13563. Executive Order 13771 requires Federal agencies to take proactive measures to reduce the costs associated with complying with Federal regulations. This proposed rule is an E.O. 13771 deregulatory action. B. Regulatory Flexibility Act and Small Business Regulatory Enforcement Fairness Act The Regulatory Flexibility Act (RFA), 5 U.S.C. 601–612, requires agencies to analyze the economic impact of regulations when there is likely to be a significant economic impact on a substantial number of small entities and to consider regulatory alternatives that will achieve the agency’s goals while minimizing the burden on small entities. The proposed rule would affect operators and Federal oil and gas lessees that could conduct exploratory drilling on the Arctic OCS. The RFA defines small entities as small businesses, small nonprofits, and small governmental jurisdictions. No small nonprofits or small governmental jurisdictions have been identified that would be impacted by this rule. Businesses subject to this proposed rule fall under North American Industry Classification System (NAICS) codes 211111 (Crude Petroleum and Natural Gas Extraction) and 213111 (Drilling Oil and Gas Wells). For these classifications, a small business is defined as one with fewer than 1,250 employees (NAICS code 211111) and fewer than 1,000 employees (NAICS code 213111), respectively. A small entity is one that is ‘‘independently owned and operated and which is not dominant in its field of operation.’’ According to BOEM’s list of Arctic OCS leaseholders, four businesses currently hold lease interests on the VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 Arctic OCS. This proposed rule would directly affect all four Arctic lessees. Based on the small entity criterion, none of the four businesses are considered a small entity. No small companies hold leases on the Arctic OCS. Previously, a single small company with only one lease held acreage on the Arctic OCS. This company relinquished its lease in March 2016. BSEE and BOEM prepared an Initial Regulatory Flexibility Analysis (IRFA), which can be found in Section VII of the IRIA. Given the challenging environment and associated costs of drilling in the Arctic OCS planning areas, no small entities are expected to operate in these areas for the foreseeable future. Therefore, BSEE and BOEM preliminarily conclude that no small entities would be affected by these proposed amendments, however the agency has prepared an IRFA and is seeking public comment on any small business impacts from the proposed amendments. This proposed rule would meet the E.O. 12866 criteria for an economically significant rule because it would likely have an annual effect on the economy of $100 million or more in at least one year of the 20-year period analyzed, and BSEE/BOEM comply with the RFA and the Small Business Regulatory Enforcement Fairness Act by providing a regulatory flexibility analysis. The requirements would apply to all entities operating on the Arctic OCS regardless of company designation as a small business. For more information on the small business impacts, see the IRFA section in the IRIA. Small businesses may send comments on the actions of Federal employees who enforce, or otherwise determine compliance with, Federal regulations to the Small Business and Agriculture Regulatory Enforcement Ombudsman, and to the Regional Small Business Regulatory Fairness Board. The Ombudsman evaluates these actions annually and rates each agency’s responsiveness to small business. If you wish to comment on actions by employees of BSEE or BOEM, call 1–888–REG–FAIR (1–888– 734–3247). C. Unfunded Mandates Reform Act of 1995 (UMRA) This proposed rule would not impose an unfunded Federal mandate on State, local, or tribal governments and would not have a significant or unique effect on State, local, or tribal governments. The requirements in this proposed rule would apply to Arctic OCS oil and gas lessees and operators, not to State, local, and tribal governments. Thus, the proposed rule would not have PO 00000 Frm 00043 Fmt 4701 Sfmt 4702 79307 disproportionate budgetary effects on these governments. BSEE and BOEM have determined the proposed changes in this rulemaking would result in cost savings annually to regulated entities. Therefore, a written statement under the Unfunded Mandates Reform Act (2 U.S.C. 1531 et seq.) is not required. D. Takings Implication Assessment Under the criteria in E.O. 12630, this proposed rule would not have significant takings implications. The proposed rule is not a governmental action capable of interference with constitutionally protected property rights. A Takings Implication Assessment is not required. E. Federalism (E.O. 13132) Under the criteria in E.O. 13132, this proposed rule would not have federalism implications. This proposed rule would not substantially and directly affect the relationship between the Federal and State Governments. To the extent that State and local governments have a role in OCS activities, this proposed rule would not affect that role. A Federalism Assessment is not required. F. Civil Justice Reform (E.O. 12988) This proposed rule complies with the requirements of E.O. 12988. Specifically, this rule: 1. Meets the criteria of section 3(a) requiring that all regulations be reviewed to eliminate errors and ambiguity and be written to minimize litigation; and 2. Meets the criteria of section 3(b)(2) requiring that all regulations be written in clear language and contain clear legal standards. G. Consultation With Indian Tribes (E.O. 13175) Under the criteria in E.O. 13175, Consultation and Coordination with Indian Tribal Governments (dated November 6, 2000), DOI’s Policy on Consultation with Indian Tribes and Alaska Native Corporations (512 Departmental Manual 4, dated November 9, 2015), and DOI’s Procedures for Consultation with Indian Tribes (512 Departmental Manual 5, dated November 9, 2015), we evaluated the subject matter of this rulemaking and determined that it would have tribal implications for Alaska Natives. As described earlier, future Arctic OCS exploratory drilling activities conducted pursuant to this proposed rule could affect Alaska Natives, particularly their ability to engage in subsistence and cultural activities. However, as discussed earlier in Section I. E:\FR\FM\09DEP2.SGM 09DEP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 79308 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules Background, Subsection E. Partner Engagement in Preparation for This Proposed Rule, Item 2. Summary of Comments Received, BOEM’s environmental studies program has provided nearly $500 million over the last 46 years to scientific research on the Alaska OCS, which includes the Arctic OCS. Since July 2016, BOEM has completed 35 environmental studies and has 23 ongoing studies that cover the Arctic, totaling nearly $72 million. While this proposed rule would change how operators could explore for OCS resources in the Arctic, there are ample opportunities to permit these activities consistent with ESA, MMPA, NEPA, and consultation with Alaska Native communities. BOEM’s environmental studies program provides the information that is used to evaluate the potential environmental effects of leasing OCS lands for exploration and development and helps ensure BOEM and BSEE have the best science available for the public, industry, and federal permitting decisions. In addition, Alaska Natives may also be beneficiaries of the proposed rule, to the extent they are partners in any exploratory activities. There are additional unquantified benefits in situations where a SSID is available to immediately shut-in a flowing well rather than waiting for a relief well to be drilled. BSEE and BOEM are committed to regular and meaningful consultation and collaboration with Alaska Native Tribes and ANCSA Corporations on policy decisions that have tribal implications, including, as an initial step, through complete and consistent implementation of E.O. 13175, together with related orders, directives, and guidance. Therefore, BSEE and BOEM engaged in Government-to-Government tribal consultations, Government-toANCSA Corporations consultations, and meetings with municipal leaders (i.e., mayors or their respective representatives), to discuss the subject matter of the proposed rule and solicit input in the development of the proposed rule. Tribal entity name Type of entity Meeting date Native Village of Utqiagvik ............................... Native Village of Wainwright ............................ Olgoonik Native Corporation ............................ Doyon Limited .................................................. Arctic Slope Regional Corporation ................... Native Village of Kotzebue ............................... Northwest Arctic Borough Mayor ..................... Native Village of Point Hope ............................ Tikigaq Native Corporation ............................... Point Hope Mayor ............................................ Alaska Eskimo Whaling Commission ............... Cully Corporation .............................................. North Slope Borough Mayor ............................ City of Utqiagvik Mayor .................................... Native Village of Nuiqsut .................................. Kuukpik Corporation ......................................... Nuiqsut Mayor .................................................. Inupiat Community of the Arctic Slope ............ Native Village of Kaktovik ................................ Kaktovik Inupiat Corporation ............................ Kaktovik Mayor ................................................. Tanana Chiefs Conference .............................. Native Village of Point Lay ............................... Tribal Government .......................................... Tribal Government. Native Corporation. Native Corporation. Native Corporation .......................................... Tribal Government .......................................... Municipal Government. Tribal Government .......................................... Native Corporation. Municipal Government. Non-tribe that consults on tribe’s behalf ......... Native Corporation .......................................... Municipal Government .................................... Municipal Government. Tribal Government .......................................... Native Corporation. Municipal Government. Non-tribe that consults on tribe’s behalf. Tribal Government .......................................... Native Corporation. Municipal Government. Tribal Government .......................................... Tribal Government .......................................... November 29, 2018 ... Anchorage. December 7, 2018. December 10, 2018 ... Kotzebue. December 11, 2018 ... Point Hope. December 13, 2018 ... December 14, 2018. December 17, 2018 ... Anchorage. Utqiagvik. December 18, 2018 ... Nuiqsut. December 19, 2018 ... Kaktovik. December 20, 2018 ... January 30, 2019 ....... Fairbanks. Conference Call. Kikiktagruk Corporation .................................... Native Corporation .......................................... NANA Regional Corporation ............................ Native Corporation. All Alaska Native input provided during the meetings was subsequently provided to DOI in writing and has been included in the administrative record for this proposed rule. As previously discussed in part E of the background section in this preamble, BSEE and BOEM heard a variety of perspectives during their meetings with Alaska Natives. The most common comment received was a concern over food security. Subsistence resources, including bowhead and beluga whales, other marine mammals, fish, and birds, are a key food source for many people’s diets in the native villages. Another common comment recommended inclusion of a requirement for an oil and gas operator to establish an agreement with those VerDate Sep<11>2014 17:45 Dec 08, 2020 Jkt 253001 PO 00000 Frm 00044 Fmt 4701 Sfmt 4702 On September 20, 2018, BSEE and BOEM began reaching out to leaders from Alaska Native Tribes, ANCSA Corporations, and municipalities to determine which partners were interested in having conversations with BSEE and BOEM about the rulemaking. Consultations entailed meetings in Alaska, at locations and times convenient to the Alaska Native communities and corporations, to ensure they can have proper representation during the meetings. Accordingly, the timing of these meetings was critical. BSEE and BOEM scheduled the meetings around important traditional subsistence and cultural activities, such as whaling, that take place during specific times of the year, particularly in the early fall. Between November 29, 2018 and January 30, 2019, BSEE and BOEM met with a majority of the tribal entities (23 of 25) originally invited to consult. The following table lists all 25 invited tribal entities, and the dates and locations of the meetings with the 23 entities. Location BSEE and BOEM made multiple attempts to contact these corporations. However, the bureaus did not receive a response from either organization. whaling communities potentially affected by a planned drilling project. Certain tribal representatives and most ANCSA corporations were supportive of this proposed rulemaking because it could help attract more economic opportunities to their villages. Other comments provided during the consultation meetings included a recommendation to provide broader E:\FR\FM\09DEP2.SGM 09DEP2 79309 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules outreach by presenting this rulemaking to the tribal assemblies and to citizens within the communities. One of the ANCSA corporations also recommended that this rulemaking take into account the NPC 2019 Report. Please refer to the discussions above in Part E (Partner Engagement in Preparation for This Proposed Rule) of the background section of this preamble for a description of how BSEE and BOEM are addressing this input during the rulemaking process. BSEE and BOEM intend to continue consultation with affected tribes and ANCSA Corporations following publication of this proposed rule. H. Effects on Environmental Justice for Minority and Low-Income Populations (E.O. 12898) E.O. 12898 requires Federal agencies to make achieving environmental justice part of their mission by identifying and addressing disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority and low-income populations. DOI has determined that this proposed rule would not have a disproportionately high or adverse the following OMB control numbers to the current ICs: • 1014–0025 (BSEE), 30 CFR part 250, Applications for Permit to Drill (APD and revised APD) (expires 06/30/2023), and in accordance with 5 CFR 1320.10, an agency may continue to conduct or sponsor this collection of information while the renewal submission is pending at OMB. • 1010–0151 (BOEM), 30 CFR part 550, subpart B Plans and Information (exp. 06/30/2021), and in accordance with 5 CFR 1320.10, an agency may continue to conduct or sponsor this collection of information while the renewal submission is pending at OMB. The IC aspects affecting each bureau are discussed separately. Additionally, BOEM is seeking to renew these information collections for three years with this rulemaking. Instructions on how to comment follow those discussions. The following table details proposed changes to the annual estimated hour burdens and non-hour costs; as well as associated wage cost changes for both BSEE and BOEM information submission activities described below: human health or environmental effect on native, minority, or low-income communities because its provisions are designed to maintain environmental protection and minimize any impact of exploration drilling on subsistence activities and Alaska Native community resources and infrastructure. I. Paperwork Reduction Act (PRA) This proposed rule contains existing and new information collection (IC) requirements for both BSEE and BOEM regulations, and a submission to OMB for review under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.) is required. Therefore, each bureau will submit an IC request to OMB for review and approval. We may not conduct, or sponsor, and you are not required to respond to a collection of information unless it displays a currently valid OMB control number. OMB has previously reviewed and approved the existing information collection requirements associated with Outer Continental Shelf drilling permits, plans, and related information collection, which would be altered by this proposed rule. OMB has assigned BSEE Existing regulations Requirement Number of responses Submit signed SSID and Well Design certification § 250.470(h) ................ Submit request to delay access to your SCCE—§ 250.471(a) and § 250.472(b) .................................... Proposed rule Number of burden hours Number of responses Total changes Number of burden hours Change of responses Change of burden hours Changes in wage cost 0 0 2 6 +2 +6 +$848 0 0 2 2 +2 +2 +$286 There are no changes to non-hour costs for BSEE requirements. BOEM Existing regulations Requirement Number of responses jbell on DSKJLSW7X2PROD with PROPOSALS2 Submit IOP, including all required information § 550.204 ........................ Submit required Arctic-specific information with EP § 550.220 .............. There are no changes to non-hour costs for BOEM requirements. BSEE Information Collection—30 CFR Part 250 The proposed regulations would establish new and/or revise current requirements and the submission of information for safe and VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 Proposed rule Number of burden hours Number of responses Total changes Number of burden hours Change of responses Change of burden hours Changes in wage cost 1 2,880 0 0 (1) (2,880) ($316,800) 1 350 1 400 .................... +50 +5,500 environmentally responsible Arctic OCS oil and gas exploration in an APD. BSEE would use the information in our efforts to protect life and the environment, conserve natural resources, and prevent waste. The following provides a breakdown of the paperwork and non-hour cost burdens for this proposed rule. For the PO 00000 Frm 00045 Fmt 4701 Sfmt 4702 current requirements retained in the proposed rule, we used OMB’s approved estimated hour and non-hour cost burdens. As discussed in the Preamble Sectionby-Section above, and in the supporting statement available at RegInfo.gov, this proposed rule would modify language in §§ 250.175(d), 250.300(b), E:\FR\FM\09DEP2.SGM 09DEP2 79310 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules 250.470(f)(3), and 250.720(c)(2); however, there would be no change in hour burden or non-hour costs associated with these revisions. In § 250.470(h), we would add a requirement to submit with an APD a certification signed by a registered professional engineer that your SSID and well design (including casing and cementing program) meet the design requirements in § 250.472 (+ 2 responses and 6 hours for PE Certification). In §§ 250.471(a) and 250.472(b), we would add a requirement for operators to submit, with an APD, documentation demonstrating that having access to SCCE and the relief rig can be safely delayed until the last casing point prior to penetrating a zone capable of flowing hydrocarbons in measurable quantities. BSEE will grant this approval if the operator adequately demonstrates to the Bureau that it will not encounter any abnormally high-pressured zones or other geological hazards before that casing point (+ 2 responses and 2 hours per request). Because not all APDs submitted to BSEE would involve Arctic OCS exploration drilling, we are separating the Arctic-specific requirements and burdens from the national APD requirements. The burden table below outlines the revised requirements and burdens associated with this proposed rulemaking. Title of Collection: Revisions to the Requirements for Exploratory Drilling on the Arctic Outer Continental Shelf— Application for Permit to Drill (APD, Revised APD). OMB Control Number: 1014–0025. Form Number: BSEE–0123 (APD) and BSEE–0123S (Supplemental APD). Type of Review: Revision of a currently approved collection. Respondents/Affected Public: Potential respondents comprise Federal OCS oil, gas, and sulfur lessees/ operators and holders of pipeline rightsof-way. Total Estimated Number of Annual Respondents: Currently there are approximately 60 Oil and Gas Drilling and Production Operators in the OCS. Not all the potential respondents would submit information at any given time, and some may submit multiple times. Total Estimated Number of Annual Responses: 11,331. Estimated Completion Time per Response: Varies from 1 hour to 2,800 hours depending on activity. Total Estimated Number of Annual Burden Hours: 77,945. Respondent’s Obligation: Most responses are mandatory, while others are required to obtain or retain benefits. Frequency of Collection: Generally, on occasion and as required in the regulations. Total Estimated Annual Nonhour Burden Cost: $4,400,470. BURDEN TABLE [Changes due to the proposed rule shown in bold] Citation 30 CFR 250; application for permit to drill (APD) Reporting or recordkeeping requirement * Average number of responses Hour burden Annual burden hours (rounded) Non-hour cost burden Subparts A, C, D, E, G, H, P .... Apply for permit to drill, sidetrack, bypass, or deepen a well submitted via Forms BSEE– 0123 (APD) and BSEE–0123S (Supplemental APD). (This burden represents only the filling out of the forms, the requirements are listed separately below.). 1 190 applications ............ 190 $2,113 fee × 190 = $401,470 Subparts D, E, G ....................... Obtain approval to revise your drilling plan or change major drilling equipment by submitting a Revised APD and Supplemental APD [no cost recovery fee for Revised APDs]. (This burden represents only the filling out of the forms, the requirements are listed separately below.). 1 730 submittals ............... 730 Subtotal ............................................................................................................................................. 920 responses .............. 920 $401,470 non-hour cost burdens Subpart A 125 ............................................ Submit evidence of your fee for services receipt Exempt under 5 CFR 1320.3(h)(1) 0 197 ............................................ Written confidentiality agreement ......................... Exempt under 5 CFR 1320.5(d)(2) 0 jbell on DSKJLSW7X2PROD with PROPOSALS2 Subpart C 300(b)(1), (2) ............................. 150 1 request ....................... 150 Subpart C subtotal ............................................................................................................................ 1 response .................... 150 VerDate Sep<11>2014 16:49 Dec 08, 2020 Obtain approval to add petroleum-based substance to drilling mud system or approval for method of disposal of drill cuttings, sand, & other well solids, including those containing Naturally Occurring Radioactive Material (NORM). Jkt 253001 PO 00000 Frm 00046 Fmt 4701 Sfmt 4702 E:\FR\FM\09DEP2.SGM 09DEP2 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules 79311 BURDEN TABLE—Continued [Changes due to the proposed rule shown in bold] Citation 30 CFR 250; application for permit to drill (APD) Reporting or recordkeeping requirement * Average number of responses Hour burden Annual burden hours (rounded) jbell on DSKJLSW7X2PROD with PROPOSALS2 Subpart D 408; 414(h) ................................ Request approval of alternate procedures or equipment during drilling operations. 409 ............................................ Request departure approval from the drilling requirements specified in this subpart; identify and discuss. 1 370 approvals ............... 370 410(b); 417(b); 713 ................... Reference well and site-specific information in case it is not approved in your Exploration Plan, Development and Production Plan, Development Operations Coordination Document. Burdens pertaining to EPs, DPPs, DOCDs are covered under BOEM 1010–0151. 8 1 submittal .................... 8 410(d) ........................................ Submit to the District Manager: An original and two complete copies of APD and Supplemental APD; separate public information copy of forms per § 250.186. 0.5 R–0.5 380 submittals ............... 380 submittals ............... 190 190 411; 412 .................................... Submit plat showing location of the proposed well and all the plat requirements associated with this section. 2 380 submittals ............... 760 411; 413; 414; 415; 420 ............ Submit design criteria used and all description requirements; drilling prognosis with description of the procedures you will follow; and casing and cementing program requirements. 15 707 submittals ............... 10,605 411; 416; 731 ............................ Submit diverter and BOP systems descriptions and all the regulatory requirements associated with this section. 11 380 submittals ............... 4,180 411; 713 .................................... Provide information for using a MODU and all the regulatory requirements associated with this section. 10 682 submittals ............... 6,820 411; 418 .................................... Additional information required when providing an APD include, but not limited to, rated capacities of drilling rig and equipment if not already on file; drilling fluids program, including weight materials; directional plot; H2S contingency plan; welding plan; and information we may require per requirements, etc. 20 380 submittals ............... 7,600 414(c) ........................................ Request preapproval to use alternative equivalent downhole mud weight prior to submitting APD. 1 15 requests ................... 15 420(a)(7) .................................... Include signed registered professional engineer certification and related information. 3 1,034 certifications ........ 3,102 423(c) ........................................ Submit for approval casing pressure test procedures and criteria. On casing seal assembly ensure proper installation of casing or liner (subsea BOP’s only). 3 527 procedures & criteria. 1,581 428(b) ........................................ Submit to District Manager for approval revised casing setting depths or hole interval drilling depth; include certification by PE. 125 1 submittal .................... 125 428(k) ........................................ Submit a description of the plan to use a valve(s) on the drive pipe during cementing operations for the conductor casing, surface casing, or liner. 125 1 submittal .................... 125 VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 PO 00000 Frm 00047 Fmt 4701 Sfmt 4702 Burden covered under subpart A, 1014– 0022 E:\FR\FM\09DEP2.SGM 09DEP2 0 79312 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules BURDEN TABLE—Continued [Changes due to the proposed rule shown in bold] Citation 30 CFR 250; application for permit to drill (APD) Reporting or recordkeeping requirement * Average number of responses Hour burden Annual burden hours (rounded) 432 ............................................ Request departure from diverter requirements; with discussion and receive approval. 8 53 requests ................... 424 460(a) ........................................ Include your projected plans if well testing along with the required information. 17 2 plans .......................... 34 462(c) ........................................ Submit a description of your source control and containment capabilities to the Regional Supervisor and receive approval; all required information. 125 1 submittal .................... 125 470(h) ........................................ Submit certification signed by PE that SSID and well design meet requirements of § 250.472. (Alaska only). 3 2 certs. ......................... 6 471(a); 472(b) ........................... Submit, to Regional Supervisor, a request to delay access to your SCCE and relief rig, if applicable, including adequate documentation (such as, but not limited to, risk modeling data, off-set well data, analog data, seismic data). Demonstrate you will not encounter any abnormally high-pressured zones or other geologic hazards. (Alaska only). 1 2 requests .................... 2 490(c) ........................................ Request to classify an area for the presence of H2S. 3 91 requests ................... 273 Support request with available information such as G&G data, well logs, formation tests, cores and analysis of formation fluids. 3 73 submittals ................. 219 Submit a request for reclassification of a zone when a different classification is needed. 1 4 requests ..................... 4 Due to the difficulties of drilling in Alaska, along with the shortened time window allowed for drilling, Alaska hours are done here as standalone requirements. Also, note that these specific hours are based on the first APD in Alaska in more than 10 years. 2,800 1 request ....................... 2,800 Subpart D subtotal ............................................................................................................................ 5,467 responses ........... 39,558 Alaska Region: 410; 412 thru 418; 420; 442; 444; 449; 456; 470; 471; 472. Subpart E 513 ............................................ Obtain written approval to begin well completion operations. If completion is planned and the data are available you may submit on forms. 3 R–3 288 requests ................. 1 request ....................... 864 3 Submit description of well-completion, schematics, logs, any H2S.. 18.5 R–26 295 submittals ............... 1 submittal .................... 5,458 26 Subpart E subtotal ............................................................................................................................ 585 responses .............. 6,351 jbell on DSKJLSW7X2PROD with PROPOSALS2 Subpart G 701; 720 .................................... Identify and discuss your proposed alternate procedures or equipment. Burden covered under subpart A, 1014– 0022 0 702 ............................................ Identify and discuss departure requests. ............. Burden covered under subpart A, 1014– 0022 0 713(b) ........................................ Submit plat of the rig’s anchor pattern for a moored rig approved in your EP, DPP, or DOCD. VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 PO 00000 Frm 00048 Fmt 4701 Sfmt 4702 125 1 submittal .................... E:\FR\FM\09DEP2.SGM 09DEP2 125 79313 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules BURDEN TABLE—Continued [Changes due to the proposed rule shown in bold] Citation 30 CFR 250; application for permit to drill (APD) Reporting or recordkeeping requirement * Average number of responses Hour burden Annual burden hours (rounded) 713(e) ........................................ Provide contingency plan for using dynamically positioned MODU and all the regulatory requirements associated with this section. 10 682 submittals ............... 6,820 713(g) ........................................ Describe specific current speeds when implementing rig shutdown and/or move-off procedures for water depths > 400 meters; discussion of specific measures you will take to curtail rig operations/move-off location. 45 1 submittal .................... 45 720(b) ........................................ Request approval to displace kill-weight fluid; include reasons why along with step-by-step procedures. 5 518 approval requests .. 2,590 721(g)(4) .................................... Submit test procedures and criteria for a successful negative pressure test for approval. If any change, submit changes for approval. 2.5 R–4 355 submittals, 1 change. 8,884 731 ............................................ Submit complete description of BOP system and components; schematic drawings; certification by ITP (additional I3P if BOP is subsea, in HPHT, or surface on floating facility); autoshear, deadman, EDS systems. 114 129 submittals ............... 14,706 jbell on DSKJLSW7X2PROD with PROPOSALS2 $31,000 × 129 submittal = $3,999,000 733(b) ........................................ Describe annulus monitoring plan; and how the well will be secured if leak is detected. 67 1 submittal .................... 67 734(b) ........................................ Submit verification report from ITP documenting repairs and that BOP is fit for service. R–64 1 report ......................... 64 734(c) ........................................ Submit revision, including all verifications required, before drilling out surface casing. R–66 1 submittal .................... 66 737(a) ........................................ Request approval from District Manager to omit BOP pressure test. Indicate which casing strings and liners meet the criteria for this request. 1 358 casing/liner info ...... 358 737(b)(2) .................................... Request approval of test pressures (RAM BOPs) 2 353 requests ................. 706 737(b)(3) .................................... Request approval of pressure test (annular BOPs). 2 380 requests ................. 760 737(d)(2) .................................... Submit test procedures for approval for surface BOP. 2.5 507 submittals ............... 1,268 737(d)(3); (d)(4) ......................... Submit test procedures, including how you will test each ROV intervention function, for approval (subsea BOPs only). 2 507 submittals ............... 1,014 737(d)(12) .................................. Submit test procedures (autoshear and deadman systems) for approval. Include documentation of the controls/circuitry system used for each test; describe how the ROV will be utilized during this operation. 2.5 507 submittals ............... 1,268 738(b) ........................................ Submit a revised permit with a written statement from an independent third party documenting the repairs, replacement, or reconfiguration and certifying that the previous certification in § 250.731(c) remains valid. .5 50 submittals ................. 25 738(m) ....................................... Request approval to use additional well control equipment, including BAVO report; as well as other information required by District Manager. 66 1 request ....................... 66 VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 PO 00000 Frm 00049 Fmt 4701 Sfmt 4702 E:\FR\FM\09DEP2.SGM 09DEP2 79314 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules BURDEN TABLE—Continued [Changes due to the proposed rule shown in bold] Citation 30 CFR 250; application for permit to drill (APD) 738(n) ........................................ Reporting or recordkeeping requirement * Average number of responses Hour burden Submit which pipe/variable bore rams have no current utility or well control purposes. Annual burden hours (rounded) 64 1 submittal .................... 64 Subpart G subtotal ............................................................................................................................ 4,177 response ............. 16,396 13 1 submittal .................... 13 Subpart H subtotal ............................................................................................................................ 1 response .................... 13 Subpart H 807(a) ........................................ Submit detailed information that demonstrates the SSSVs and related equipment are capable of performing in HPHT. Subpart P Note that for Sulfur Operations, while there may be 49 burden hours listed, we have not had any sulfur leases for numerous years, therefore, we have submitted minimal burden. 1605(b)(3) .................................. Submit information on the fitness of the drilling unit. 6 1 submittal .................... 6 1617 .......................................... Submit fully completed application (Form BSEE– 0123) include rated capacities of the proposed drilling unit and of major drilling equipment; as well as all required information listed in this section. 40 1 submittal .................... 40 1622(b) ...................................... Submit description of well-completion or workover procedures, schematic, and if H2S is present. 3 1 submittal .................... 3 Subpart P subtotal ............................................................................................................................ 3 responses .................. 49 Total Burden for APD .............................................................................................................. 11,331 Responses ....... 77,945 $4,400,470 Non Hour Cost Burden jbell on DSKJLSW7X2PROD with PROPOSALS2 * In the future, BSEE may require electronic filing of some submissions. In addition, the PRA requires agencies to estimate the total annual reporting and recordkeeping non-hour cost burden resulting from the collection of information, and we solicit your comments on this item. For reporting and recordkeeping only, your response should split the cost estimate into two components: (1) Total capital and startup cost component and (2) annual operation, maintenance, and purchase of service component. Your estimates should consider the cost to generate, maintain, and disclose or provide the information. You should describe the methods you use to estimate major cost factors, including system and technology acquisition, expected useful life of capital equipment, discount rate(s), and the period over which you incur costs. Generally, your estimates should not include equipment or services purchased: (1) Before October 1, 1995; (2) to comply with requirements not associated with the information collection; (3) for reasons VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 other than to provide information or keep records for the Government; or (4) as part of customary and usual business or private practices. As part of our continuing effort to reduce paperwork and respondent burdens, we invite the public and other Federal agencies to comment on any aspect of this information collection, including: (1) Whether the collection of information is necessary, including whether the information will have practical utility; (2) The accuracy of our estimate of the burden for this collection of information; (3) Ways to enhance the quality, utility, and clarity of the information to be collected; and (4) Ways to minimize the burden of the collection of information on respondents. Send your comments and suggestions on this information collection by the date indicated in the DATES section to the Desk Officer for the Department of PO 00000 Frm 00050 Fmt 4701 Sfmt 4702 the Interior at OMB–OIRA at (202) 395– 5806 (fax) or via the RegInfo.gov portal (online). You may view the information collection request(s) at https:// www.reginfo.gov/public/do/PRAMain. Please provide a copy of your comments to the BSEE Information Collection Clearance Officer (see the ADDRESSES section). You may contact Kye Mason, BSEE Information Collection Clearance Officer at (703) 787–1607 with any questions. Please reference Revisions to the Requirements for Exploratory Drilling on the Arctic Outer Continental Shelf (OMB Control No. 1014–0025), in your comments. BOEM Information Collection—30 CFR Part 550 This proposed rule would add and remove requirements related to submitting exploration plans and other information before conducting oil and gas exploration drilling activities on the Arctic OCS. If final regulations become effective, the information collection burdens for this rulemaking would be E:\FR\FM\09DEP2.SGM 09DEP2 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules consolidated into the existing collection for Subpart B, Control Number 1010– 0151, and will be adjusted as necessary. BOEM is requesting OMB approve the modified collections of information for OMB Control Number 1010–0151 with the final rule publication. Pertaining to this proposed rulemaking, BOEM would collect the information to ensure that planned operations will be safe; will not adversely affect the marine, coastal, or human environments; will respond to the special conditions on the Arctic OCS; and will conserve the resources of the Arctic OCS. BOEM would use the information to ensure, through advanced planning, that operators are capable of safely operating in the unique environmental conditions of the Arctic and to make informed decisions on whether to approve EPs as submitted or whether modifications are necessary. BOEM proposes to remove the Integrated Operations Plan (IOP) regulations by deleting § 550.204 and removing the corresponding references to the IOP from §§ 550.200 and 550.206. BOEM’s existing requirement to submit the IOP at least 90 days before the lessee or operator files an EP would be eliminated. The data and information requested in the IOP is largely unnecessary in light of the information already collected in the EP. The current approval for OMB Control Number 1010–0151 counts the similar burdens associated with IOPs and EPs in both. Therefore, BOEM would remove the burdens attributed to the IOPs, and keep the burdens attributed to EPs. Removing the IOP provision would decrease the annual burden hours by 1 response and 2,880 hours (- 1 response and 2,880 annual burden hours). The proposed rule would add a requirement to § 550.211(b) to describe operational safety procedures that the operator has developed specific to conditions relevant on the Arctic OCS in the EP. These requirements were previously included in the IOP requirements that are removed from this rulemaking. Retaining this provision would lessen the 2,880-burden hour decrease by 50 annual burden hours (i.e., by retaining 50 annual burden hours). BOEM proposes to revise § 550.220(c)(1) to require a description of how exploratory drilling will be designed and conducted, including how all vessels and equipment will be designed, built, and/or modified, to account for Arctic OCS conditions and how such activities will be managed and overseen as an integrated endeavor, and in the description of vessel modifications, a description of any approvals from the flag state and the vessel classification society, including any allowances or limitations placed upon the vessel by the classification society and/or the USCG. Vessel modifications may include the suitability of vessels for Arctic conditions. These vessels may have or acquire classification from a ‘‘recognized organization’’ under the USCG’s Alternative Compliance Program (ACP).54 BOEM is seeking to confirm that the operator meets the requirements of other entities with authority over vessels, not to impose requirements on those vessels. BOEM believes that this change would not impose any material additional burdens on the lessees or operators. BOEM is also proposing to revise § 550.220(c)(4) and (6) by requiring the operator to provide a general description of how they will comply with § 250.472, including a description of the termination of their operations. BOEM estimates that the proposed revisions would remove 2,880 annual burden hours that correlate to the removal of the existing IOP requirement. 79315 These changes would result in a net decrease of 2,830 annual burden hours. Because not all EPs submitted to BOEM would involve Arctic OCS exploration drilling, we are separating the burden associated with the Arcticspecific requirements and burdens from the national EP requirements. The burden table that follows this paragraph outlines the revised requirements and burdens associated with this rulemaking. BOEM has not identified any non-hour cost burdens associated with these proposed requirements. Title of Collection: Revisions to the Requirements for Exploratory Drilling on the Arctic Outer Continental Shelf— 30 CFR part 550, subpart B, Plans and Information. OMB Control Number: 1010–0151. Form Number: • BOEM–0137, OCS Plan Information Form • BOEM–0138, EP Air Quality Screening Checklist • BOEM–0139, DOCD/DPP Air Quality Screening Checklist. • BOEM–0141, ROV Survey Report. • BOEM–0142, Environmental Impact Analysis Worksheet. Type of Review: Revision of a currently approved collection. Respondents/Affected Public: Respondents are Federal oil and gas or sulfur lessees or operators. Total Estimated Number of Annual Response: 4,265 respondents. Total Estimated Number of Annual Burden Hours: 433,608 hours. Respondent’s Obligation: Some responses to the information collection are required to obtain or retain a benefit, and some are mandatory. Frequency of Collection: The frequency of the response varies, but primarily responses are required only on occasion. Total Estimated Annual Nonhour Burden Cost: $3,939,435. BURDEN BREAKDOWN [Current requirements in regular font; proposed expanded requirements shown in italic font] Citation 30 CFR 550 subpart B and NTLs Reporting & recordkeeping requirement Average number of annual responses Hour burden Burden hours jbell on DSKJLSW7X2PROD with PROPOSALS2 Non-hour costs 200 thru 206 ...................... General requirements for plans and information; fees/refunds, etc. Burden included with specific requirements below. 0 201 thru 206; 211 thru 228: 241 thru 262. BOEM posts EPs/DPPs/DOCDs on FDMS and receives public comments in preparation of EAs. Not considered IC as defined in 5 CFR 1320.3(h)(4). 0 Subtotal .......................................................................................................................................... 0 ....................................... 54 33 U.S.C. 3316 and 46 CFR part 8 implement the USCG’s ACP. VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 PO 00000 Frm 00051 Fmt 4701 Sfmt 4702 E:\FR\FM\09DEP2.SGM 09DEP2 0 79316 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules BURDEN BREAKDOWN—Continued [Current requirements in regular font; proposed expanded requirements shown in italic font] Citation 30 CFR 550 subpart B and NTLs Reporting & recordkeeping requirement Average number of annual responses Hour burden Burden hours Non-hour costs Ancillary Activities 208; NTL 2009–G34 * ....... Notify BOEM in writing, and if required by the Regional Supervisor notify other users of the OCS before conducting ancillary activities. 11 61 notices ........................ 671 208; 210(a) ........................ Submit report summarizing & analyzing data/information obtained or derived from ancillary activities. 2 61 reports ........................ 122 208; 210(b) ........................ Retain ancillary activities data/information; upon request, submit to BOEM. 2 61 records ........................ 122 Subtotal .......................................................................................................................................... 183 responses ................. 91 Contents of Exploration Plans (EP) 209; 231(b); 232(d); 234; 235; 281; 283; 284; 285; NTL 2015–N01. Submit new, amended, modified, revised, or supplemental EP, or resubmit disapproved EP, including required information; withdraw an EP. 150 345 changed plans3 ........ 51,750 209; 211 thru 228; NTL 2015–N01. Submit EP and all required information (including, but not limited to, submissions required by BOEM Forms 0137, 0138, 0142; lease stipulations; reports, including shallow hazards surveys, H2S, G&G, archaeological surveys & reports (§ 550.194) ***, in specified formats. Provide notifications. 600 163 ................................... 97,800 $3,673 × 163 EP surface locations = $598,699 210; 220(a)–(c); 291; 292 For existing Arctic OCS exploration activities: revise and resubmit Arctic-specific information, as required. 700 1 ....................................... 700 202; 211; 216; 219, 220(a)–(c); 224, 227;. For new Arctic OCS exploration activities: submit required Arctic-specific information with EP. 400 1 ....................................... 400 Subtotal .......................................................................................................................................... 510 responses ................. 150,650 $598,699 Non-hour costs Review and Decision Process for the EP 235(b); 272(b); .................. 281(d)(3)(ii) ....................... Appeal State’s objection ............................................ Burden exempt as defined in 5 CFR 1320.4(a)(2), (c). 0 jbell on DSKJLSW7X2PROD with PROPOSALS2 Contents of Development and Production Plans (DPP) and Development Operations Coordination Documents (DOCD) 209; 266(b); 267(d); 272(a); 273; 281; 283; 284; 285; NTL 2015– N01. Submit amended, modified, revised, or supplemental DPP or DOCD, including required information, or resubmit disapproved DPP or DOCD. 235 353 changed plans .......... 82,955 241 thru 262; 209; NTL 2015–N01. Submit DPP/DOCD and required/supporting information (including, but not limited to, submissions required by BOEM Forms 0137, 0139, 0142; lease stipulations; reports, including shallow hazards surveys, archaeological surveys & reports (§ 550.194)), in specified formats. Provide notification. 700 268 ................................... 187,600 $4,238 × 268 DPP/DOCD wells = $1,135,784. Subtotal .......................................................................................................................................... 621 responses ................. $1,135,784 Non-hour costs VerDate Sep<11>2014 17:34 Dec 08, 2020 Jkt 253001 PO 00000 Frm 00052 Fmt 4701 Sfmt 4702 E:\FR\FM\09DEP2.SGM 09DEP2 270,555 79317 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules BURDEN BREAKDOWN—Continued [Current requirements in regular font; proposed expanded requirements shown in italic font] Citation 30 CFR 550 subpart B and NTLs Reporting & recordkeeping requirement Average number of annual responses Hour burden Burden hours Non-hour costs Review and Decision Process for the DPP or DOCD 267(a) ................................ Once BOEM deemed DPP/DOCD submitted; Governor of each affected State, local government official; etc., submit comments/recommendations. Not considered IC as defined in 5 CFR 1320.3(h)(4). 0 267(b) ................................ General public comments/recommendations submitted to BOEM regarding DPPs or DOCDs. Not considered IC as defined in 5 CFR 1320.3(h)(4). 0 269(b) ................................ For leases or units in vicinity of proposed development and production activities RD may require those lessees and operators to submit information on preliminary plans for their leases and units. 3 1 response ....................... 3 Subtotal .......................................................................................................................................... 1 response ....................... 3 Post-Approval Requirements for the EP, DPP, and DOCD 280(b) ................................ In an emergency, request departure from your approved EP, DPP, or DOCD. Burden included under 1010–0114. 0 281(a) ................................ Submit various BSEE applications for approval and submit permits. Burdens included under appropriate subpart or form (1014–0003; 1014–0011; 1014–0016; 1014–0018). 0 282 .................................... Retain monitoring data/information; upon request, make available to BOEM. 4 150 records ...................... 600 Prepare and submit monitoring plan for approval ..... 2 6 plans ............................. 12 282(b) ................................ Prepare and submit monitoring reports and data (including BOEM Form 0141 used in GOMR). 3 12 reports ........................ 36 284(a) ................................ Submit updated info on activities conducted under approved EP/DPP/DOCD. 4 56 updates ....................... 224 Subtotal .......................................................................................................................................... 224 responses ................. 872 14 documents .................. 5,250 Submit CIDs 296(a); 297 ........................ Submit CID and required/supporting information; submit CID for supplemental DOCD or DPP. 375 $27,348 × 14 = $382,872 296(b); 297 ........................ Submit a revised CID for approval ............................ 100 13 revisions ..................... 1,300 Subtotal .......................................................................................................................................... 27 responses ................... 6,550 $382,872 Non-hour costs Seismic Survey Mitigation Measures and Protected Species Observer Program NTL jbell on DSKJLSW7X2PROD with PROPOSALS2 NTL 2016–G02; 211 thru 228; 241 thru 262. VerDate Sep<11>2014 Submit to BOEM observer training requirement materials and information. 1.5 hours 2 sets of material ............. 3 Training certification and recordkeeping ................... 1 hour 1 new trainee ................... 1 During seismic acquisition operations, submit daily observer reports semi-monthly. 1.5 hours 344 reports ...................... 516 If used, submit to BOEM information on any passive acoustic monitoring system prior to placing it in service. 2 hours 6 submittals ..................... 12 16:49 Dec 08, 2020 Jkt 253001 PO 00000 Frm 00053 Fmt 4701 Sfmt 4702 E:\FR\FM\09DEP2.SGM 09DEP2 79318 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules BURDEN BREAKDOWN—Continued [Current requirements in regular font; proposed expanded requirements shown in italic font] Citation 30 CFR 550 subpart B and NTLs Reporting & recordkeeping requirement Average number of annual responses Hour burden Burden hours Non-hour costs During seismic acquisition operations, submit to BOEM marine mammal observation report(s) semi-monthly or within 24 hours if air gun operations were shut down. 1.5 hours 1,976 reports ................... 2,964 During seismic acquisition operations, when air guns are being discharged, submit daily observer reports semi-monthly. 1.5 hours 344 reports ...................... 516 Observation Duty (3 observers fulfilling an 8-hour shift each for 365 calendar days × 4 vessels = 35,040 man-hours). This requirement is contracted out; hence the non-hour cost burden. 3 observers × 8 hrs × 365 days = 8,760 hours × 4 vessels observing = 35,040 man-hours × $52/hr = $1,822,080. Subtotal .......................................................................................................................................... 2,673 responses .............. 4,012 $1,822,080 Non-hour costs Vessel Strike Avoidance and Injured/Protected Species Reporting NTL NTL 2016–G01; 211 thru 228; 241 thru 262. Notify BOEM within 24 hours of strike, when your vessel injures/kills a protected species (marine mammal/sea turtle). 1 hour 1 notice ............................ 1 Subtotal .......................................................................................................................................... 1 response ....................... 1 2 25 requests ...................... 50 Subtotal .......................................................................................................................................... 25 responses ................... 50 Total Burden ............................................................................................................................ 4,265 responses .............. 433,608 General Departure 200 thru 299 ...................... General departure and alternative compliance requests not specifically covered elsewhere in Subpart B regulations. $3,939,435 Non-hour costs jbell on DSKJLSW7X2PROD with PROPOSALS2 * The identification number of NTLs may change when NTLs are reissued periodically to update information. In addition, the PRA requires agencies to estimate the total annual reporting and recordkeeping non-hour cost burden resulting from the collection of information, and we solicit your comments on this item. For reporting and recordkeeping only, your response should split the cost estimate into two components: (1) Total capital and startup cost component and (2) annual operation, maintenance, and purchase of service component. Your estimates should consider the cost to generate, maintain, and disclose or provide the information. You should describe the methods you use to estimate major cost factors, including system and technology acquisition, expected useful life of capital equipment, discount rate(s), and the period over which you incur costs. Generally, your estimates should not include equipment or services purchased: (1) Before October 1, 1995; (2) to comply with VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 requirements not associated with the information collection; (3) for reasons other than to provide information or keep records for the Government; or (4) as part of customary and usual business or private practices. As part of our continuing effort to reduce paperwork and respondent burdens, we invite the public and other Federal agencies to comment on any aspect of this information collection, including: (1) Whether the collection of information is necessary, including whether the information will have practical utility; (2) The accuracy of our estimate of the burden for this collection of information; (3) Ways to enhance the quality, utility, and clarity of the information to be collected; and (4) Ways to minimize the burden of the collection of information on respondents. PO 00000 Frm 00054 Fmt 4701 Sfmt 4702 Send your comments and suggestions on this information collection by the date indicated in the DATES section to the Desk Officer for the Department of the Interior at OMB–OIRA at (202) 395– 5806 (fax) or via the portal at RegInfo.gov (online). You may view the information collection request(s) at https://www.reginfo.gov/public/do/ PRAMain. Please provide a copy of your comments to the BOEM Information Collection Clearance Officer (see the ADDRESSES section). You may contact Anna Atkinson, BOEM Information Collection Clearance Officer at (703) 787–1025 with any questions. Please reference Revisions to the Requirements for Exploratory Drilling on the Arctic Outer Continental Shelf (OMB Control No. 1014–0151), in your comments. J. National Environmental Policy Act of 1969 (NEPA) BSEE and BOEM developed a draft Environmental Assessment (EA) to E:\FR\FM\09DEP2.SGM 09DEP2 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules determine whether this proposed rule would have a significant impact on the quality of the human environment under the NEPA. The draft EA is available for review in conjunction with this proposed rule at www.regulations.gov (in the Search box, enter BSEE–2019–0008). K. Data Quality Act In developing this proposed rule, we did not conduct or use a study, experiment, or survey requiring peer review under the Data Quality Act (44 U.S.C. 3516 note). L. Effects on the Nation’s Energy Supply (E.O. 13211) Although this proposed rule is a significant regulatory action under E.O. 12866, it is not a significant energy action under the definition of that term in E.O. 13211 because: 1. It is not likely to have a significant adverse effect on the supply, distribution or use of energy; and 2. It has not been designated as a significant energy action by the Administrator of OIRA. Thus, a Statement of Energy Effects is not required. While offshore Arctic OCS oil and gas studies indicate the potential of vast resources, there is currently little exploration activity and very little production of oil and gas on the Arctic OCS, largely due to the inherent practical difficulties of exploration and production in the area. The only existing oil production from the Arctic OCS is through the Northstar Island facility. jbell on DSKJLSW7X2PROD with PROPOSALS2 We are required by E.O. 12866, E.O. 12988, and by the Presidential Memorandum of June 1, 1998, to write all rules in plain language. This means that each rule we publish must: 1. Be logically organized; 2. Use the active voice to address readers directly; 3. Use clear language rather than jargon; 4. Be divided into short sections and sentences; and 5. Use lists and tables wherever possible. If you believe we have not met these requirements, send us comments by one of the methods listed in the ADDRESSES section. To better help us revise the rule, your comments should be as specific as possible. For example, you should tell us the numbers of the sections or paragraphs that you find unclear, which sections or sentences are too long, or the sections where you believe lists or tables would be useful. 16:49 Dec 08, 2020 30 CFR Part 250 Administrative practice and procedure, Continental shelf, Environmental impact statements, Environmental protection, Government contracts, Incorporation by reference, Investigations, Oil and gas exploration, Penalties, Pipelines, Public lands– mineral resources, Public lands—rights of-way, Reporting and recordkeeping requirements, Sulphur. 30 CFR Part 550 Administrative practice and procedure, Continental shelf, Environmental impact statements, Environmental protection, Mineral resources, Oil and gas exploration, Pipelines, Reporting and recordkeeping requirements, Sulfur. Katharine MacGregor, Deputy Secretary, U.S. Department of the Interior. For the reasons stated in the preamble, BSEE and BOEM amend 30 CFR parts 250 and 550 as follows: Title 30—Mineral Resources CHAPTER II—BUREAU OF SAFETY AND ENVIRONMENTAL ENFORCEMENT, DEPARTMENT OF THE INTERIOR SUBCHAPTER B—OFFSHORE PART 250—OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL SHELF 1. The authority citation for 30 CFR part 250 continues to read as follows: ■ Authority: 30 U.S.C. 1751, 31 U.S.C. 9701, 33 U.S.C. 1321(j)(1)(C), 43 U.S.C. 1334. M. Clarity of Regulations VerDate Sep<11>2014 List of Subjects Jkt 253001 2. Amend § 250.105 by revising the definition of ‘‘Capping stack’’ to read as follows: ■ § 250.105 Definitions. * * * * * Capping stack means a mechanical device that can be installed on top of a subsea or surface wellhead or blowout preventer to stop the uncontrolled flow of fluids into the environment. * * * * * ■ 3. Amend § 250.175 by adding paragraph (d) to read as follows: § 250.175 When may the Regional Supervisor grant an SOO? * * * * * (d) For leases or units on the Arctic OCS, you may request, and the Regional Supervisor may grant, an SOO when you have conducted leaseholding operations during the drilling season immediately preceding the period for which you are seeking a suspension, PO 00000 Frm 00055 Fmt 4701 Sfmt 4702 79319 and you satisfy one of the following conditions: (1) You are conducting drilling operations from a Mobile Offshore Drilling Unit (MODU), but you are not able to safely continue leaseholding operations due to the presence of seasonal ice; (2) You are conducting drilling operations from an artificial gravel island or a gravity-based structure, but you are not able to safely continue leaseholding operations due to temporary seasonal restrictions in your approved oil spill response plan; or (3) You are conducting drilling operations from an artificial ice island, but you are not able to safely continue leaseholding operations due to seasonal temperature changes. ■ 4. Amend § 250.198 by revising paragraph (e)(73) to read as follows: § 250.198 Documents incorporated by reference. * * * * * (e) * * * (73) API RP 17H, Remotely Operated Tools and Interfaces on Subsea Production Systems, Second Edition, June 2013; Errata, January 2014; incorporated by reference at §§ 250.472(a) and 250.734(a); * * * * * ■ 5. Amend § 250.300 by revising paragraphs (b)(1) and (2) to read as follows: § 250.300 Pollution prevention. * * * * * (b)(1) The District Manager may restrict the rate of drilling fluid discharges or prescribe alternative discharge methods. The District Manager may also restrict the use of components that could cause unreasonable degradation to the marine environment. No petroleum-based substances, including diesel fuel, may be added to the drilling mud system without prior approval of the District Manager. For Arctic OCS exploratory drilling, you must capture all petroleum-based mud to prevent its discharge into the marine environment. (2) You must obtain approval from the District Manager of the method you plan to use to dispose of drill cuttings, sand, and other well solids. For Arctic OCS exploratory drilling, you must capture all cuttings from operations that use petroleum-based mud to prevent their discharge into the marine environment. * * * * * ■ 6. Amend § 250.470 by: ■ a. Revising paragraphs (b)(11) and (12); ■ b. Adding paragraph (b)(13); ■ c. Revising paragraph (f)(3); and E:\FR\FM\09DEP2.SGM 09DEP2 79320 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules d. Adding paragraph (h). The revisions and additions read as follows: ■ § 250.470 What additional information must I submit with my APD for Arctic OCS exploratory drilling operations? * * * * * (b) * * * (11) Pick up the oil spill prevention booms and equipment; (12) Offload the drilling crew; and (13) Recover the subsea isolation device (SSID), where applicable. * * * * * (f) * * * (3) Where applicable, proof of contracts or membership agreements with cooperatives, service providers, or other contractors who will provide you with the necessary SCCE or related supplies and services if you do not possess them. The contract or membership agreement must include provisions for ensuring the availability of the personnel and/or equipment on a 24-hour per day basis while you are drilling below or working below the surface casing, or before the last casing point prior to penetrating a zone capable of flowing hydrocarbons in measurable quantities, as approved by the Regional Supervisor. * * * * * (h) If you plan to install a subsea isolation device (SSID) on your well in accordance with § 250.472(a), a certification signed by a registered professional engineer that your SSID and well design (including casing and cementing program) meet the design requirements in § 250.472 and the design is appropriate for the purpose for which it is intended under expected wellbore conditions. ■ 7. Amend § 250.471 by revising paragraph (a) introductory text, and paragraphs (a)(2) and (3) and (b) to read as follows: § 250.471 What are the requirements for Arctic OCS source control and containment? * * * * * (a) If you use a MODU, you must have access to the SCCE as described in paragraphs (a)(1) through (3) of this section capable of controlling and containing the flow from an out-ofcontrol well when drilling below or working below the surface casing. However, the Regional Supervisor will approve delaying access to your SCCE until your operations have reached the last casing point prior to penetrating a zone capable of flowing hydrocarbons in measurable quantities, provided that you submit adequate documentation (such as, but not limited to, risk modeling data, off-set well data, analog data, seismic data), with your APD, demonstrating that you will not encounter any abnormally highpressured zones or other geologic hazards. The Regional Supervisor will base the determination on any documentation you provide as well as any other available data and information. * * * * * (2) A cap and flow system that can be deployed as directed by the Regional Supervisor pursuant to paragraph (h) of this section. The cap and flow system must be designed to capture at least the amount of hydrocarbons equivalent to the calculated worst case discharge rate referenced in your BOEM-approved EP; and (3) A containment dome that can be deployed as directed by the Regional Supervisor pursuant to paragraph (h) of this section. The containment dome must have the capacity to pump fluids without relying on buoyancy. (b) You must conduct a monthly stump test of dry-stored capping stacks. * * * * * ■ 8. Revise § 250.472 to read as follows: § 250.472 What are the additional well control equipment or relief rig requirements for the Arctic OCS? If you will be conducting exploratory drilling operations from a Mobile Offshore Drilling Unit (MODU), you must either use a Subsea Isolation Device (SSID) or have access to a relief rig as an additional means to secure the well in the event of a loss of well control. If you satisfy this requirement through use of an SSID, you must meet the requirements in paragraph (a) in this section. If you satisfy this requirement through maintaining access to a relief rig, you must meet the requirements in paragraph (b) in this section. (a) Subsea Isolation Device (SSID). If you use an SSID to satisfy this requirement, your SSID and well (including the casing and cementing program) must be designed to achieve a full shut-in, without causing an underground blowout or having reservoir fluids broach to the seafloor. Your SSID must also meet the following requirements: TABLE 1 TO PARAGRAPH (a) Your SSID must (1) Be designed to: .............................................. jbell on DSKJLSW7X2PROD with PROPOSALS2 (2) Include the following equipment: (3) Include ROV intervention equipment and capabilities. Your ROV equipment and capabilities must: (i) Close and seal the wellbore, independent of the BOP; (ii) Perform under the maximum environmental and operational conditions anticipated to occur at the well; (iii) Be left on the wellhead in the event the drilling rig is moved off location (e.g., due to storms, ice incursions, or emergency situations); (iv) Preserve isolation through the winter season without relying on the elastomer elements of the rams (e.g., by using a well cap) and allow re-entry during the following open-water season; and (v) In the event of a loss of well control, preserve isolation until other methods of well intervention may be completed, including the need to drill a relief well. (i) Dual shear rams, including ram locks; one ram must be a blind shear ram; (ii) A redundant control system, independent from the BOP control system, that includes ROV capabilities and a control station on the rig; (iii) Independent, dedicated subsea accumulators with the capacity to function all components of the SSID; and (iv) Two side inlets for intervention; one inlet must be located below the lowest ram on the SSID. (i) Be able to close each shear ram under MASP conditions, as defined for the operation; (ii) Include an ROV panel that is compliant with API RP 17H (as incorporated by reference in § 250.198); (iii) Meet the ROV requirements in § 250.734(a)(5); and (iv) Have the ability to function the SSID in any environment (e.g., when in a mudline cellar). VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 PO 00000 Frm 00056 Fmt 4701 Sfmt 4702 E:\FR\FM\09DEP2.SGM 09DEP2 Federal Register / Vol. 85, No. 237 / Wednesday, December 9, 2020 / Proposed Rules 79321 TABLE 1 TO PARAGRAPH (a)—Continued Your SSID must (4) Be installed: ................................................... (i) Below the BOP; (ii) At or before the time that you first install your BOP; and (iii) To provide protection from deep ice keels, in the event it must remain in place over the winter season (e.g., installed in a mudline cellar). According to the BOP testing requirements in § 250.737. (5) Be tested: ...................................................... (b) Relief Rig. If you choose to satisfy this requirement by having access to a relief rig, you must have access to your relief rig at all times when you are drilling below or working below the surface casing during Arctic OCS exploratory drilling operations. However, the Regional Supervisor will approve delaying access to your relief rig until your operations have reached the last casing point prior to penetrating a zone capable of flowing hydrocarbons in measurable quantities, provided that you submit adequate documentation (such as, but not limited to, risk modeling data, off-set well data, analog data, seismic data), with your APD, demonstrating that you will not encounter any abnormally highpressured zones or other geologic hazards. The Regional Supervisor will base the determination on any documentation you provide as well as any other available data and information. Your relief rig must be different from your primary drilling rig, staged in a location, such that it would be available to arrive on site, drill a relief well, kill and abandon the original well, and abandon the relief well no later than 45 days after the loss of well control. (1) Your relief rig must comply with all other requirements of this part pertaining to drill rig characteristics and capabilities, and it must be able to drill a relief well under anticipated Arctic OCS conditions. (2) In the event of a loss of well control, the Regional Supervisor may direct you to drill a relief well using a relief rig that is able to kill and permanently plug an out-of-control well as described in your APD. ■ 9. Amend § 250.720 by revising paragraph (c)(2) to read as follows: jbell on DSKJLSW7X2PROD with PROPOSALS2 § 250.720 well? When and how must I secure a * * * * * (c) * * * (2) In areas of ice scour, you must use a well mudline cellar or an equivalent means of minimizing the risk of damage to the well head and wellbore. You may request, and the Regional Supervisor may approve, an alternate procedure or VerDate Sep<11>2014 16:49 Dec 08, 2020 Jkt 253001 equipment in accordance with §§ 250.141 and 250.408. * * * * * CHAPTER V—BUREAU OF OCEAN ENERGY MANAGEMENT, DEPARTMENT OF THE INTERIOR SUBCHAPTER B—OFFSHORE PART 550—OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL SHELF 10. The authority citation for 30 CFR part 550 continues to read as follows: ■ Authority: 30 U.S.C. 1751; 31 U.S.C. 9701; 43 U.S.C. 1334. § 550.220 [Amended] 11. Amend § 550.200 by removing the words ‘‘IOP means Integrated Operations Plan.’’ in paragraph (a). ■ 12. Remove and reserve § 550.204. ■ § 550.204 [Reserved] 13. Amend § 550.206 by revising the section heading, paragraph (a) introductory text, and paragraphs (a)(3), (b), and (c) to read as follows: ■ § 550.206 DOCD? How do I submit the EP, DPP, or (a) Number of copies. When you submit an EP, DPP, or DOCD to BOEM, you must provide: * * * * * (3) Any additional copies that may be necessary to facilitate review of the EP, DPP, or DOCD by certain affected States and other reviewing entities. (b) Electronic submission. You may submit part or all of your EP, DPP, or DOCD and its accompanying information electronically. If you prefer to submit your EP, DPP, or DOCD electronically, ask the Regional Supervisor for further guidance. (c) Withdrawal after submission. You may withdraw your proposed EP, DPP, or DOCD at any time for any reason. Notify the appropriate BOEM Regional Office if you do. ■ 14. Amend § 550.211 by redesignating paragraphs (b) through (d) as paragraphs (c) through (e), respectively, and adding new paragraph (b) to read as follows: § 550.211 * PO 00000 * What must the EP include? * Frm 00057 * Fmt 4701 * Sfmt 9990 (b) A description of how you will ensure operational safety while working in Arctic OCS conditions, including but not limited to: (1) The safety principles that you intend to apply to yourself and your contractors; (2) The accountability structure within your organization for implementing such principles; (3) How you will communicate such principles to your employees and contractors; and (4) How you will determine successful implementation of such principles. * * * * * ■ 15. Amend § 550.220 by revising the section heading, paragraphs (c)(1) and (4), and (c)(6)(ii) to read as follows: § 550.220 If I propose activities in the Arctic OCS Region, what planning information must accompany the EP? * * * * * (c) * * * (1) A description of how your exploratory drilling will be designed and conducted, (including how all vessels and equipment will be designed, built, and/or modified) to account for Arctic OCS conditions and how such activities will be managed and overseen as an integrated endeavor. In your description of vessel modifications, describe any approvals from the flag state and the vessel classification society, including any allowances or limitations placed upon the vessel by the classification society and/or the United States Coast Guard. * * * * * (4) Additional well control equipment requirements for the Arctic OCS. A general description of how you will comply with § 250.472 of this title. (6) * * * (ii) The termination of drilling operations consistent with the well control planning requirements under § 250.472 of this title. [FR Doc. 2020–25818 Filed 12–8–20; 8:45 am] BILLING CODE 4310–VH–P; 4310–MR–P E:\FR\FM\09DEP2.SGM 09DEP2

Agencies

DEPARTMENT OF THE INTERIOR
Bureau of Ocean Energy Management
Bureau of Safety and Environmental Enforcement

[Federal Register Volume 85, Number 237 (Wednesday, December 9, 2020)]
[Proposed Rules]
[Pages 79266-79321]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2020-25818]



[[Page 79265]]

Vol. 85

Wednesday,

No. 237

December 9, 2020

Part II





Department of the Interior





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Bureau of Safety and Environmental Enforcement





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30 CFR Part 250





Bureau of Ocean Energy Management





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30 CFR Part 550





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

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

[[Page 79266]]


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DEPARTMENT OF THE INTERIOR

Bureau of Safety and Environmental Enforcement

30 CFR Part 250

Bureau of Ocean Energy Management

30 CFR Part 550

[Docket ID: BSEE-2019-0008, EEEE500000, 21XE1700DX, EX1SF0000.EAQ000]
RIN 1082-AA01


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

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

ACTION: Proposed rule.

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SUMMARY: The Department of the Interior (DOI or Department), acting 
through BOEM and BSEE, has reviewed and is proposing to revise its 
existing regulations for exploratory drilling and related operations on 
the Arctic Outer Continental Shelf (OCS), to reduce unnecessary burdens 
on stakeholders while ensuring that energy exploration on the Arctic 
OCS is safe and environmentally responsible. In particular, this 
proposed rule would revise certain requirements promulgated through the 
rule entitled, Oil and Gas and Sulfur Operations on the Outer 
Continental Shelf-Requirements for Exploratory Drilling on the Arctic 
Outer Continental Shelf (``2016 Arctic Exploratory Drilling Rule''). 
This proposed rule would also add new provisions to BSEE's regulations 
pertaining to suspensions of operations (SOO), and BOEM's Exploration 
Plan (EP) and Development and Production Plan (DPP) regulations.

DATES: Submit comments by February 8, 2021. BSEE and BOEM may not fully 
consider comments received after this date. You may submit comments to 
the Office of Management and Budget (OMB) on the information collection 
burden in this proposed rule by January 8, 2021. The deadline for 
comments on the information collection burden does not affect the 
deadline for the public to comment to BSEE and BOEM on the proposed 
regulations.

ADDRESSES: You may submit comments on BSEE's or BOEM's sections of the 
rulemaking by any of the following methods. For comments on this 
proposed rule, please use the Regulation Identifier Number (RIN) 1082-
AA01 as an identifier in your message. For comments specifically 
related to the draft Environmental Assessment (EA) conducted under the 
National Environmental Policy Act of 1969 (NEPA), please refer to NEPA 
in the heading of your message. See also Public Availability of 
Comments under Procedural Matters.
     Federal eRulemaking Portal: https://www.regulations.gov. In 
the entry entitled, ``Enter Keyword or ID,'' enter BSEE-2019-0008, then 
click search. Follow the instructions to submit public comments and 
view supporting and related materials available for this rulemaking. 
BSEE and BOEM may post all submitted comments.
     Mail or hand-carry comments to the DOI, BSEE and BOEM: 
Attention: Regulations and Standards Branch, 45600 Woodland Road, VAE-
ORP, Sterling VA 20166. Please reference RIN 1082-AA01, ``Oil and Gas 
and Sulfur Operations on the Outer Continental Shelf--Revisions to the 
Requirements for Exploratory Drilling on the Arctic Outer Continental 
Shelf,'' in your comments, and include your name and return address.
     Send comments on the information collection in this rule 
to: Interior Desk Officer 1082-AA01, Office of Management and Budget; 
202-395-5806 (fax); or via the online portal at RegInfo.gov. Please 
also send a copy to BSEE and BOEM by one of the means previously 
described.
     Public Availability of Comments--Before including your 
address, phone number, email address, or other personal identifying 
information in your comment, you should be aware that your entire 
comment--including your personal identifying information--may be made 
publicly available at any time. For BSEE and BOEM to withhold from 
disclosure your personal identifying information, you must identify any 
information contained in the submittal of your comments that, if 
released, would constitute a clearly unwarranted invasion of your 
personal privacy. You must also briefly describe any possible harmful 
consequence(s) of the disclosure of information, such as embarrassment, 
injury, or other harm. While you can ask us in your comment to withhold 
your personal identifying information from public review, we cannot 
guarantee that we will be able to do so.

FOR FURTHER INFORMATION CONTACT: For technical questions related to 
regulatory changes BSEE is proposing in Part 250, contact Mark E. 
Fesmire, BSEE, Alaska Regional Office, [email protected], (907) 
334-5300. For technical questions related to regulatory changes BOEM is 
proposing in Part 550, contact Joel Immaraj, BOEM, Alaska Regional 
Office, [email protected], (907) 334-5238. For procedural questions 
contact Bryce Barlan, BSEE, Regulations and Standards Branch, 
[email protected], (703) 787-1126.

SUPPLEMENTARY INFORMATION:

Executive Summary

    In response to BSEE- and BOEM-initiated environmental and safety 
reviews of potential oil and gas operations on the Arctic OCS, 
experiences gained from Shell's 2012 and 2015 Arctic operations, and 
concerns expressed by environmental organizations and Alaska Natives, 
BSEE and BOEM published the 2016 Arctic Exploratory Drilling Rule (see 
81 FR 46478, July 15, 2016). The rule was narrowly focused, applying 
solely to exploratory drilling operations conducted during the Arctic 
OCS open-water drilling season by drilling vessels and ``jack-up rigs'' 
(collectively known as mobile offshore drilling units or MODU) in the 
Beaufort Sea and Chukchi Sea Planning Areas. The regulations were 
intended to ensure that Arctic OCS exploratory drilling operations are 
conducted in a safe and responsible manner, while taking into account 
the unique conditions of the Arctic OCS, as well as Alaska Natives' 
cultural traditions and their need for access to subsistence resources. 
BSEE and BOEM have since reviewed the 2016 Arctic Exploratory Drilling 
Rule taking into account a Congressional declaration of purposes in the 
Outer Continental Shelf Lands Act (OCSLA) to ``establish policies and 
procedures for managing the oil and natural gas resources of the Outer 
Continental Shelf which are intended to result in expedited exploration 
and development of the Outer Continental Shelf in order to achieve 
national economic and energy policy goals, assure national security, 
reduce dependence on foreign sources, and maintain a favorable balance 
of payments in world trade.'' \1\ The bureaus have also reviewed new 
information about technological developments in an ice environment. 
Based on that review, BSEE and BOEM are proposing revisions in this 
proposed rule that are consistent with OCSLA, and would reduce 
unnecessary burdens on stakeholders while still maintaining safety and 
environmental protection.
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    \1\ Outer Continental Shelf Lands Act, Public Law 95-372, sec. 
102 (Sept. 8, 1978), 43 U.S.C. 1802(1)).
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    Since publication of the 2016 Arctic Exploratory Drilling Rule, new

[[Page 79267]]

Executive Orders (E.O.) and Secretary's Orders (S.O.) called on Federal 
agencies to review existing regulations that potentially burden the 
development or use of domestically produced energy resources and 
appropriately begin processes to potentially suspend, revise, or 
rescind those regulations that are determined to unduly burden the 
development of domestic energy resources, beyond the degree necessary 
to protect the public interest or otherwise comply with the law. 
Executive Order 13795, Implementing an America-First Offshore Energy 
Strategy (82 FR 20815) and Secretary's Order 3350, America-First 
Offshore Energy Strategy, which are discussed in more detail below in 
Section I. Background, Subsection C. Executive and Secretary's Orders, 
specifically called for a review of the 2016 Arctic Exploratory 
Drilling Rule.\2\ In response to these E.O.s and S.O.s, BSEE and BOEM 
undertook a review of the regulations promulgated through the 2016 
Arctic Exploratory Drilling Rule with a view toward encouraging energy 
exploration and production on the Arctic OCS, as appropriate and 
consistent with applicable law, and reducing unnecessary regulatory 
burdens, while ensuring that any such activity is safe and 
environmentally responsible.
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    \2\ These Orders did no dictate outcomes; rather, they directed 
a review in accordance with applicable law.
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    BSEE's and BOEM's views about certain features of the existing 
regulations were also informed by new information that has become 
available since the 2016 rule was finalized. This new information 
includes a BSEE-commissioned Technology Assessment Program (TAP) study 
entitled, Suitability of Source Control and Containment Equipment 
versus Same Season Relief Well in the Alaska Outer Continental Shelf 
Region (Bratslavsky and SolstenXP, 2018) and a National Petroleum 
Council (NPC) report entitled, Supplemental Assessment to the 2015 
Report on Arctic Potential: Realizing the Promise of U.S. Arctic Oil 
and Gas Resources (NPC 2019 Report). BSEE also re-assessed the original 
NPC report entitled, Arctic Potential: Realizing the Promise of U.S. 
Arctic Oil and Gas Resources (NPC 2015 Report; together with the NPC 
2019 Report, the NPC reports). Both NPC reports include discussions 
about global Arctic operations. These global operations are discussed 
in further detail below in Subsection 5. Industry Interest in the 
Arctic OCS of Section I. Background, under the subheading entitled, 
Global Arctic Exploration Activities. The Bratslavsky and SolstenXP 
study was finalized in October 2018 and may be downloaded from BSEE's 
TAP website at: https://www.bsee.gov/research-record/suitability-of-source-control-containment-equipment-versus-same-season-relief-well. 
The NPC 2019 Report was finalized in April 2019 and may be downloaded 
from an NPC website at: https://www.npc.org/ARSA-FINAL-052219-LoRes.pdf. The NPC 2015 Report was finalized in March 2015 and may be 
downloaded from an NPC website at: https://www.npcarcticpotentialreport.org/.
    Based on the results of these reports, BSEE and BOEM are proposing 
to amend, revise, or remove certain current regulatory provisions 
promulgated through the 2016 Arctic Exploratory Drilling Rule, to 
reduce unnecessary burdens on stakeholders while still maintaining 
safety and environmental protection. This proposed rulemaking is 
consistent with OCSLA's Congressional declaration of purposes to 
``establish policies and procedures for managing the oil and natural 
gas resources of the Outer Continental Shelf which are intended to 
result in expedited exploration and development of the Outer 
Continental Shelf in order to achieve national economic and energy 
policy goals, assure national security, reduce dependence on foreign 
sources, and maintain a favorable balance of payments in world trade.'' 
43 U.S.C. 1802(1).
    BSEE and BOEM also considered another issue on the Arctic OCS in 
addition to those addressed in the 2016 Arctic Exploratory Drilling 
Rule, but is logical to address as part of this rulemaking to further 
encourage safe and environmentally responsible exploration of this 
region, where the areas known to have oil and gas have been explored or 
studied. This issue pertains to the effective means by which BSEE and 
the operator could address seasonal weather-related constraints in the 
Arctic OCS that severely impact the operator's ability to safely 
perform leaseholding operations for a significant portion of the term 
on a lease.
    Accordingly, this proposed rule would revise certain provisions in 
30 Code of Federal Regulations (CFR) Part 250, Subparts A, C, D, and G, 
and 30 CFR part 550, subpart B, that pertain to:
    1. The factors that the BSEE Regional Supervisor may evaluate in 
assessing whether to grant an SOO, to address unique and specific 
conditions relevant only to exploration and development activities on 
the Arctic OCS;
    2. Pollution prevention;
    3. Arctic OCS Source Control and Containment Equipment (SCCE);
    4. Relief rig capabilities for the Arctic OCS;
    5. Timing and submission requirements related to Integrated 
Operations Plans (IOP) for proposed Arctic exploratory drilling;
    6. What must be included in the IOP; and
    7. What data and information must accompany the EP and DPP.
    This proposed rule is designed to reflect the need to ensure the 
safe, effective, and responsible exploration of Arctic OCS oil and gas 
resources, while protecting the marine, coastal, and human 
environments, and preserving Alaska Natives' cultural traditions and 
their access to subsistence resources. This proposed rule is intended 
to revise the regulations promulgated through the 2016 Arctic 
Exploratory Drilling Rule by creating more flexible and less costly 
compliance options in BSEE's and BOEM's regulations that could achieve 
these objectives. While this proposed rule seeks to promulgate new 
provisions in addition to those addressed in the 2016 Arctic 
Exploratory Drilling Rule, these new provisions (i.e., provisions to 
address leaseholding operations impacted by seasonal weather-related 
constraints on the Arctic OCS) would further enhance BSEE's and BOEM's 
abilities to ensure the safe, effective, and responsible exploration of 
Arctic OCS oil and gas resources. They would do so while protecting the 
marine, coastal, and human environments, and preserving Alaska Natives' 
cultural traditions and access to subsistence resources. Through lease 
stipulations related to the Conflict Avoidance Agreements (CAA), BOEM 
currently requires operators to consult with affected subsistence 
communities and describe in exploration and development plans the 
mitigating practices the operator would undertake to avoid conflicts 
with the communities. Conflict Avoidance Agreements provide a framework 
for mitigating the adverse impacts a drilling project may have on 
subsistence activities, values, and uses.

Table of Contents

I. Background
    A. Overview of the Alaska Arctic Region
    B. BSEE and BOEM Statutory and Regulatory Authority and 
Responsibilities
    C. Executive and Secretary's Orders
    D. Purpose and Summary of the Rulemaking
    E. Partner Engagement in Preparation for This Proposed Rule
II. Section-by-Section Discussion of Proposed Changes
    A. Key Revisions Proposed by BSEE

[[Page 79268]]

    Subpart A--General
     Definitions. (Sec.  250.105)
     When may the Regional Supervisor grant an SOO? (Sec.  
250.175)
     Documents incorporated by reference. (Sec.  250.198)
    Subpart C--Pollution Prevention and Control
     Pollution prevention. (Sec.  250.300)
    Subpart D--Oil and Gas Drilling Operations
     What additional information must I submit with my APD 
for Arctic OCS exploratory drilling operations? (Sec.  250.470)
     What are the requirements for Arctic OCS source control 
and containment? (Sec.  250.471)
     What are the additional well control equipment or 
relief rig requirements for the Arctic OCS? (Sec.  250.472)
    Subpart G--Well Operations and Equipment
     When and how must I secure a well? (Sec.  250.720)
    B. Key Revisions Proposed by BOEM
    Subpart B--Plans and Information
     Definitions. (Sec.  550.200)
     Removal of Sec.  550.204, When must I submit my IOP for 
proposed Arctic exploratory drilling operations and what must the 
IOP include?
     How do I submit the EP, DPP, or DOCD? (Sec.  550.206)
     What must the EP include? (Sec.  550.211)
     If I propose activities in the Arctic OCS Region, what 
planning information must accompany the EP? (Sec.  550.220)
III. Additional Comments Solicited on the Same Season Relief Well 
and Relief Rig Requirement
IV. Procedural Matters
    A. Regulatory Planning and Review (Executive Orders (E.O.) 
12866, 13563, and 13771)
    B. Regulatory Flexibility Act and Small Business Regulatory 
Enforcement Fairness Act
    C. Unfunded Mandates Reform Act of 1995 (UMRA)
    D. Takings Implication Assessment
    E. Federalism (E.O. 13132)
    F. Civil Justice Reform (E.O. 12988)
    G. Consultation With Indian Tribes (E.O. 13175)
    H. Environmental Justice in Minority Populations and Low-Income 
Populations (E.O. 12898)
    E.O. 12898
    I. Paperwork Reduction Act (PRA)
    J. National Environmental Policy Act of 1969 (NEPA)
    K. Data Quality Act
    L. Effects on the Nation's Energy Supply (E.O. 13211)
    M. Clarity of Regulations

                                         List of Acronyms and References
----------------------------------------------------------------------------------------------------------------
                                                                 Report to the Secretary of the Interior, review
                         60-Day report                             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.
EA.............................................................  Environmental Assessment.
EIA............................................................  Environmental Impact Analysis.
EIS............................................................  Environmental Impact Statement.
E.O............................................................  Executive Order.
EP.............................................................  Exploration Plan.
EPA............................................................  Environmental Protection Agency.
ESA............................................................  Endangered Species Act.
G&G............................................................  Geological and geophysical.
IC.............................................................  Information Collection.
ICAS...........................................................  Inupiat Community of the Arctic Slope.
IOP............................................................  Integrated Operations Plan.
IRIA...........................................................  Initial Regulatory Impact Analysis.
IWC............................................................  International Whaling Commission.
LMRP...........................................................  Lower Marine Riser Package.
MASP...........................................................  Maximum Anticipated Surface Pressures.
MMPA...........................................................  Marine Mammal Protection Act.
MMS............................................................  Minerals Management Service.
MODU...........................................................  Mobile Offshore Drilling Unit.

[[Page 79269]]

 
NAICS..........................................................  North American Industry Classification System.
NEPA...........................................................  National Environmental Policy Act of 1969.
NMFS...........................................................  National Marine Fisheries Service.
NOAA...........................................................  National Oceanic and Atmospheric
                                                                  Administration.
NPC............................................................  National Petroleum Council.
NPC 2015 Report................................................  Arctic Potential: Realizing the Promise of U.S.
                                                                  Arctic Oil and Gas Resources.
NPC 2019 Report................................................  Supplemental Assessment to the 2015 Report on
                                                                  Arctic Potential: Realizing the Promise of
                                                                  U.S. Arctic Oil and Gas Resources.
NPDES..........................................................  National Pollutant Discharge Elimination
                                                                  System.
NPR-A..........................................................  National Petroleum Reserve--Alaska.
NSB............................................................  North Slope Borough.
NTL............................................................  Notice to Lessees and Operators.
OCS............................................................  Outer Continental Shelf.
OCSLA..........................................................  Outer Continental Shelf Lands Act.
ODCE...........................................................  Ocean Discharge Criteria Evaluations.
OIRA...........................................................  Office of Information and Regulatory Affairs.
OMB............................................................  Office of Management and Budget.
ONRR...........................................................  Office of Natural Resources Revenue.
OSRP...........................................................  Oil Spill Response Plan.
PFD............................................................  Permanent Fund Dividend.
PRA............................................................  Paperwork Reduction Act.
psi/ft.........................................................  pounds per square inch per foot.
RIN............................................................  Regulation Identifier Number.
ROV............................................................  Remotely Operated Vehicle.
RP.............................................................  Recommended Practice.
SCCE...........................................................  Source Control and Containment Equipment.
Secretary......................................................  Secretary of the Interior.
S.O............................................................  Secretary's Orders.
SEMS...........................................................  Safety and Environmental Management Systems.
SSID...........................................................  Subsea Isolation Device.
SSRW...........................................................  Same Season Relief Well.
SOO............................................................  Suspensions of Operations.
TAP............................................................  Technology Assessment Program.
TAPS...........................................................  Trans-Alaska Pipeline System.
TCF............................................................  Trillion Cubic Feet.
UMRA...........................................................  Unfunded Mandates Reform Act of 1995.
U.S............................................................  United States.
USCG...........................................................  U.S. Coast Guard.
USFWS..........................................................  U.S. Fish and Wildlife Service.
USGS...........................................................  United States Geological Survey.
Utquiavik......................................................  Barrow.
WCD............................................................  Worst Case Discharge.
----------------------------------------------------------------------------------------------------------------

I. Background

A. Overview of the Alaska Arctic Region

1. History of Arctic Oil and Gas Development
    Although Alaska's first oil production is attributable to the 1957 
Swanson River discovery on the Kenai Peninsula, oil and gas resources 
have been known to exist in the Arctic since as early as 1839. Early 
explorers had reported that Alaska Natives on the Arctic coast used 
oil-soaked tundra for fuel. The oil came from natural oil seeps on the 
ground. However, the extent of the resource, as well as the State's 
overall oil and gas endowment, would not be realized until the 
discovery of the Arctic's Prudhoe Bay oil field on the North Slope and 
completion of the Trans-Alaska Pipeline System (TAPS) in 1977.
    The Prudhoe Bay field was discovered on March 12, 1968, with the 
drilling of the Prudhoe Bay State #1 well. BP Exploration drilled a 
confirmation well the following year. However, production did not come 
online until June 20, 1977, after the TAPS was completed and other 
companies with lease holdings in the area undertook a host of 
activities to delineate the reservoir, resolve equity participation, 
and put together initial infrastructure for the field. After over 40 
years of production, Prudhoe Bay remains the largest oil field in North 
America and is the 18th largest field ever discovered worldwide.\3\ 
According to data maintained by the Alaska Oil and Gas Conservation 
Commission, Alaska's North Slope has produced over 17.3 billion barrels 
of oil, with Prudhoe Bay contributing approximately 68 percent of that 
amount.\4\ Currently, the only offshore Federal production in the 
Arctic OCS \5\ is Hilcorp's Northstar field, which includes both State 
and Federal acreage in the 8(g) Zone.\6\ Located in the Beaufort Sea 
about 12 miles northwest of Prudhoe Bay, this prospect has been 
producing since 2001. Over 150 million barrels of oil have been 
produced to date at Northstar. In 2019, the Federal Government received 
nearly $5 million in royalty payments from oil production on Federal 
leases at Northstar, and from 2003 to 2018, royalty payments ranged

[[Page 79270]]

from $3 million to over $20 million in any given year. In 2019, the 
Federal Government disbursed just over $1.5 million to the State of 
Alaska for Northstar Federal leases in the 8(g) Zone.\7\
---------------------------------------------------------------------------

    \3\ https://dec.alaska.gov/spar/ppr/response/sum_fy06/060302301/factsheets/060302301_factsheet_PB.pdf.
    \4\ https://aogweb.state.ak.us/DataMiner3/Forms/Production.aspx.
    \5\ There are Federal OCS leases that do not have ongoing 
production in the Cook Inlet, which is not considered part of the 
Arctic.
    \6\ Section 8(g) of the OCSLA requires the Federal Government to 
share with the State of Alaska 27% of revenue from leases in the 
8(g) Zone (the first three nautical miles of the Outer Continental 
Shelf). 43 U.S.C. 1337(g).
    \7\ https://revenuedata.doi.gov/downloads/disbursements/.
---------------------------------------------------------------------------

    The construction of TAPS enhanced the significance of the Arctic's 
production to the State of Alaska. TAPS is an 800-mile-long pipeline 
system that was designed to accommodate the transport of over 2 million 
barrels of oil per day. The pipeline begins at Prudhoe Bay and 
stretches south to Valdez in southern Alaska, which is the northernmost 
ice-free port in North America. TAPS is one of the world's largest 
pipeline systems, an engineering icon that was the biggest privately 
funded construction project when it was constructed in the 1970s. At 
peak flow in 1988, 11 pump stations helped to move 2.1 million barrels 
of oil a day.\8\
---------------------------------------------------------------------------

    \8\ 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.\9\ In 2012, as much 
as 93 percent of Alaska's unrestricted general funds were derived from 
oil and gas revenues and were also available to the State's budget.\10\ 
The reduced contribution of oil and gas-generated revenue to the 
State's budget since 2012 is due primarily to declining oil production 
in the North Slope, but also due to a general downward trend in oil 
prices.
---------------------------------------------------------------------------

    \9\ https://www.legfin.akleg.gov/, Budget History Data (Excel) 
(posted 1-15-2020), Row 59.
    \10\ https://www.legfin.akleg.gov/, Budget History Data (Excel) 
(posted 1-15-2020), Row 55.
---------------------------------------------------------------------------

    Aside from annual State operating and capital budgets, several 
Statewide government programs established for the benefit of the people 
of Alaska are largely dependent on oil and gas-related revenues, most 
notably the Alaska Permanent Fund. In 1976, Alaska's State constitution 
was amended to establish the Alaska Permanent Fund, which provides that 
at least 25 percent of all mineral lease rentals, royalties, royalty 
sale proceeds, Federal mineral revenue sharing payments, and bonuses 
received by the State are to be placed in a permanent fund, known as 
the Alaska Permanent Fund, the principal of which is used only for 
income-producing investments. All income generated from the permanent 
fund is available for distribution to all Alaskan residents--adults and 
children--on an annual basis through the State's Permanent Fund 
Dividend (PFD) program.\11\ Since 1978, this fund has grown to a total 
fund value of $60 billion as of March 2020.\12\ Individual 
distributions to Alaskans from the fund have ranged from $386 per 
person to as high as $2,072 per person.\13\ These annual payments are 
estimated to have lifted between 15,000 and 25,000 Alaskans above the 
Federal poverty line.\14\
---------------------------------------------------------------------------

    \11\ https://apfc.org/frequently-asked-questions/#why-did-alaskans-create-the-fund.
    \12\ https://apfc.org/our-performance/.
    \13\ https://pfd.alaska.gov/Division-Info/Summary-of-Applications-and-Payments.
    \14\ Berman, Matt., Random Reamy. ``Permanent Fund Dividends and 
Poverty in Alaska.'' Institute of Social and Economic Research, 
University of Alaska Anchorage. (November 2016), available online 
at: https://iseralaska.org/static/legacy_publication_links/2016_12-PFDandPoverty.pdf. p. 25 of pdf.
---------------------------------------------------------------------------

    Much of the North Slope Borough's economy is tied to the oil and 
gas industry, primarily in the greater Prudhoe Bay region. Some borough 
residents have rotational work in the oilfields or in a position 
supporting the oil industry, but the greatest contribution to the 
economy is through tax revenue. The borough assesses property taxes on 
infrastructure, the primary funding source for the borough's operations 
and capital projects, which include building roads, operating schools, 
and funding for other public services, such as health clinics and fire 
departments.\15\
---------------------------------------------------------------------------

    \15\ https://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.\16\ In general, the formations are fairly continuous across the 
Arctic Alaska Petroleum Province.
---------------------------------------------------------------------------

    \16\ Houseknecht, D.W., and Bird, K.J., 2006, Oil and gas 
resources of the Arctic Alaska petroleum province: U.S. Geological 
Survey Professional Paper 1732-A, 11 p., available online at: https://pubs.usgs.gov/pp/pp1732/pp1732a/.
---------------------------------------------------------------------------

    Although most of the Arctic's oil production to date is attributed 
to the North Slope, most of the undiscovered resources are located off 
the Arctic coast, within the Chukchi Sea and Beaufort Sea Planning 
Areas. According to BOEM's 2016 Assessment of Undiscovered Technically 
Recoverable Oil and Gas Resources of the Nation's

[[Page 79271]]

OCS (mean estimates available at https://www.boem.gov/National-Assessment-2016/), there are approximately 23.6 billion barrels of 
undiscovered technically recoverable oil and about 104.4 trillion cubic 
feet (TCF) of technically recoverable natural gas (mean estimates) in 
the combined Beaufort Sea and Chukchi Sea Planning Areas. BOEM re-
assessed its Beaufort Sea Planning Area estimates due to recent onshore 
discoveries in the National Petroleum Reserve-Alaska (NPR-A) from two 
formations that extended offshore. In December 2017, BOEM published its 
updated re-assessment (mean estimates available at https://www.boem.gov/2016a-National-Assessment-Fact-Sheet/), which estimated 
that there are approximately 24.3 billion barrels of technically 
recoverable oil and about 104. TCF of technically recoverable natural 
gas in the combined Beaufort Sea and Chukchi Sea Planning Areas; an 
increase of about 680 million barrels of oil and 100 billion cubic feet 
of natural gas. Of the 24.3 billion barrels of oil, the Chukchi Sea 
Planning Area makes up about 63% of the estimate, while the Beaufort 
Sea Planning Area makes up 37%. With respect to gas, the Chukchi Sea 
Planning Area makes up about 73% of the 104.5 TCF of gas and the 
Beaufort Sea Planning Area makes up 27% of the estimate. These 
estimates represent about one-quarter of the technically recoverable 
oil resources and one-third of the technically recoverable gas 
resources on the OCS.
    While not as large, the Arctic's onshore undiscovered oil and gas 
resources are also considerable. In January 2020, the United States 
Geological Survey (USGS) published an assessment of undiscovered oil 
and gas resources in the central portion of the Alaska North Slope, 
(mean estimates available at https://pubs.usgs.gov/fs/2020/3001/fs20203001.pdf). The assessment estimated that there are approximately 
3.6 billion barrels of undiscovered technically recoverable oil and 
about 8.9 TCF of undiscovered technically recoverable natural gas 
resources on State and Native lands, and State waters, east of the NPR-
A and west of the Arctic National Wildlife Refuge (ANWR). According to 
a 2017 USGS assessment of undiscovered oil and gas resources in the 
Alaska North Slope, (mean estimates available at https://pubs.usgs.gov/fs/2017/3088/fs20173088.pdf), there are approximately 8.8 billion 
barrels of undiscovered technically recoverable oil and about 39 TCF of 
undiscovered technically recoverable natural gas in the NPR-A. In 
addition, USGS's assessment of the 1002 Area \17\ of the ANWR estimated 
(mean estimates available at https://pubs.usgs.gov/of/2005/1217/pdf/2005-1217.pdf) there are 7.6 billion barrels of technically recoverable 
oil and 7.04 \18\ TCF of technically recoverable natural gas. Efforts 
are already underway to bring some of these new onshore resources 
online. Collectively, these offshore and onshore assets are enormous, 
and most of the resources are located offshore.\19\ However, the Arctic 
OCS's vast potential has yet to be realized.
---------------------------------------------------------------------------

    \17\ The Alaska National Interest Lands Conservation Act 
(ANILCA) of 1980 required ANWR to be managed as a protected 
wilderness. Section 1002 of ANILCA, however, deferred a decision 
regarding future management of a 1.5 million-acre coastal plain 
portion of ANWR (known as the ``1002'' area) in order to 
continuously study the various natural resources on the coastal 
plain, and analyze how oil and gas exploration, development, and 
production could potentially impact those resources. Section 20001 
of the Tax Cuts and Jobs Act of 2017 lifted a provision in Section 
1003 of ANILCA that prohibits oil and gas leasing and production in 
the 1002 area, and the BLM is in the process of developing an oil 
and gas leasing program for that area.
    \18\ This value represents the combined estimates of natural gas 
that could technically be produced from gas fields as well as 
associated gas that could be produced from oil fields.
    \19\ D.L. Gautier et al., ``Circum-Arctic Resource Appraisal: 
Estimates of Undiscovered Oil and Gas North of the Arctic Circle,'' 
U.S. Geological Survey, USGS Fact Sheet 2008-3049, 2008. M.E. 
Brownfield et al., ``An Estimate of Undiscovered Conventional Oil 
and Gas Resources of the World,'' U.S. Geological Survey, USGS Fact 
Sheet 2012-3024, 2012, available at https://pubs.usgs.gov/fs/2008/3049/fs2008-3049.pdf.
---------------------------------------------------------------------------

    In the Arctic, the circumstances associated with drilling from a 
MODU can be different than those in the Gulf of Mexico. The geological 
pressures in the hydrocarbon bearing zones in the shallow seas of 
Alaska's Arctic are, in many cases, likely to be substantially lower 
than those encountered during the Deepwater Horizon incident, reducing 
certain risk factors of a major blowout. As reviewed by the NPC, 
through the NPC 2019 Report, subsurface conditions (below the seafloor) 
for the Arctic OCS--geology, pressure, resource depth, and drilling 
depth--are much simpler as compared to other areas, such as the 
deepwater Gulf of Mexico OCS. The NPC 2019 Report states that the 
targeted Arctic potential reservoirs are shallow and normally 
pressured, but that exploration and development are dominated by other 
challenges, such as water depth, ice conditions, and the length of the 
open-water season, which make the Arctic unique (NPC 2019 Report at 
10). The NPC 2015 Report found, however, that most of the U.S. Arctic 
offshore conventional oil and gas potential can be developed using 
existing field-proven technology, which was reaffirmed by the NPC 2019 
Report (NPC 2015 Report at 28).
    As identified by the NPC, targeted potential reservoirs in the 
Arctic OCS may be shallow and normally pressured.\20\ However, this 
condition is not consistent throughout all areas in the Arctic OCS that 
have already been explored. For example, a study published by the 
American Rock Mechanics Association \21\ analyzed wells drilled in the 
Chukchi Sea in order to provide an improved interpretation and 
delineation of pore pressure in the Chukchi shelf region. A majority of 
the wells contained significant overpressure at depths ranging from 
1,098 to 2,317 meters (i.e., 3,602 to 7,601 feet) subsea. In the 
Beaufort Sea, the Alaska Department of Natural Resources (ADNR) noted 
that, as part of its findings to support Beaufort Sea areawide oil and 
gas lease sales,\22\ operators may reasonably expect to encounter 
extremely high pore pressures along the central Beaufort Sea region 
where `` . . . Cenozoic strata (sedimentary layers) are very thick, 
such as in the Kaktovik, Camden, and Nuwuk Basins,'' and suggests that 
challenges from over pressured areas could be reduced by ``. . . 
identifying locations of overpressured sediments via seismic data 
analysis, and then adjusting the mud mixture accordingly as the well is 
drilled.'' In the Point Thomson area, for example, where drilling has 
taken place from an onshore facility into a reservoir located primarily 
offshore, the pore pressure gradients were measured as high as 0.8 
pounds per square inch per foot (psi/ft) at depths of 2.5 miles (13,200 
feet). A pore pressure gradient of 0.433 psi/ft is considered normal in 
this area.\23\
---------------------------------------------------------------------------

    \20\ ``Normally pressured'' is not defined in the NPC 2019 
Report. However, as a general matter, normal pressure generally 
refers to the hydrostatic pressure within a well. ``Normally 
pressured'' refers to conditions present when formation pressures 
are predictable at any given depth and follow a normal formation 
pressure gradient or ``hydrostatic pressure gradient.'' Normal 
formation pressure, at any given depth, equals the normal formation 
pressure gradient multiplied by the depth. The normal pressure is 
expressed in pounds per square inch (psi).
    \21\ Elowe, K.E., & Sherwood, K.W., 2017, ``Abnormal Formation 
Pressure in the Chukchi Shelf, Alaska,'' American Rock Mechanics 
Association Conference Paper, Document ID ARMA-2017-0194, available 
online at https://www.onepetro.org/conference-paper/ARMA-2017-0194.
    \22\ Alaska Department of Natural Resources, 2019, ``Beaufort 
Sea Areawide Oil and Gas Lease Sales,'' p. 3-20, available online at 
https://aws.state.ak.us/OnlinePublicNotices/Notices/View.aspx?id=193811.
    \23\ Craig, J.D., K.W. Sherwood, and P.P. Johnson. 1985. 
Geologic report for the Beaufort Sea planning area, Alaska: Regional 
geology, petroleum geology, environmental geology. U.S. Department 
of the Interior, Minerals Management Service, Alaska OCS Region, OCS 
Report MMS 85-0111. Anchorage, Alaska. https://www.boem.gov/BOEM-Newsroom/Library/Publications/1985/85_0111.aspx.

---------------------------------------------------------------------------

[[Page 79272]]

    While these reports' findings do not fully align with the NPC's 
findings, there are other sources of information confirming that, to a 
certain degree, typical geologic conditions in the Arctic OCS are 
normally pressured. For example, a BOEM report that studied the Chukchi 
Sea's Burger gas discovery calculated the pore pressure gradient for 
one of the Chukchi Sea wells in the study to be 0.44 psi/ft up to 4,850 
feet subsea, which the report determined to be normally pressured. 
However, beneath 4,850 feet, the pore pressure gradient became over-
pressurized having a pore pressure gradient of 0.88 psi/ft.\24\ For the 
Beaufort Sea, a USGS report analyzed pressure data from five offshore 
wells and found that the pressures in the area where the wells were 
located were normally pressured (i.e., at hydrostatic pressure) up to 
2,000 feet subsea, and increased only slightly above hydrostatic 
pressure deeper into the well. By 10,000 feet, however, the pressure in 
all five wells were over-pressured, 1.5 times higher than the 
hydrostatic pressure.\25\ Over-pressure started to occur at around 
6,700 feet subsea.
---------------------------------------------------------------------------

    \24\ Craig, J.D., & Sherwood, K.W., 2001 (revised 2004), 
``Economic Study of the Burger Gas Discovery, Chukchi Shelf, 
Northwest Alaska,'' U.S. Department of the Interior, Minerals 
Management Service, p. 67, available online at https://www.boem.gov/sites/default/files/boem-newsroom/Library/Publications/2004/Economic-Study-of-the-Burger-Gas-Discovery.pdf.
    \25\ Hayba, D.O., Houseknecht, D.W., and Rowan, E., 1999, 
``Stratigraphic, Hydrogeologic, and Thermal Evolution of the Canning 
River Region, North Slope, Alaska,'' U.S. Department of the 
Interior, U.S. Geological Survey, p. FF-21, available online at 
https://pubs.usgs.gov/of/1998/ofr-98-0034/FF.pdf.
---------------------------------------------------------------------------

    While it is not possible to confirm that all targeted potential 
reservoirs would be shallow and normally pressured in all exploratory 
drilling situations, BSEE and BOEM will have access to the relevant 
geologic and geophysical information to help identify hydrocarbon 
bearing zones and zones with potential geologic risk, such as over-
pressurized zones, that may be encountered during drilling operations. 
These higher pressured, hydrocarbon zones are, in fact, the targeted 
formations the industry has attempted to produce. For example, the BOEM 
report analyzing the Chukchi Sea's Burger gas discovery illustrated the 
regional geology of all the wells included in the study, and showed 
that the higher pressured zones in the wells occurred at the same point 
where the oil-bearing zones were located.\26\ The Bureaus have the 
means, through access to relevant geological and geophysical (G&G) data 
and drilling application regulatory reviews, to confirm that operators 
identify and plan for these potential risks. For example, the bureaus 
confirm that operators have properly designed well casing and drilling 
programs and ensure that operators have access to properly designed 
equipment that is readily available to quickly respond to an incident, 
such as the availability of a capping stack in advance of drilling into 
the targeted productive zones.
---------------------------------------------------------------------------

    \26\ Craig, J.D., & Sherwood, K.W., 2001 (revised 2004), 
``Economic Study of the Burger Gas Discovery, Chukchi Shelf, 
Northwest Alaska,'' U.S. Department of the Interior, Minerals 
Management Service, p. 72, available online at https://www.boem.gov/sites/default/files/boem-newsroom/Library/Publications/2004/Economic-Study-of-the-Burger-Gas-Discovery.pdf.
---------------------------------------------------------------------------

4. Partnership With Alaska Natives in Northern Alaska
    The bowhead whale provides the largest subsistence resource 
available to the native villages of Alaska's northern shores. In 1977, 
Eskimo whalers from these villages established the Alaska Eskimo 
Whaling Commission (AEWC), whose mission is to safeguard the bowhead 
whale and its habitat, defend the Aboriginal Subsistence Whaling Rights 
of their members, and preserve the cultural and traditional values of 
their villages. Eskimo whalers established the AEWC in response to 
actions taken by the International Whaling Commission (IWC) that 
resulted in the IWC's assumption of direct jurisdiction over the 
Alaskan Native bowhead whale subsistence hunt, without Alaska Native 
input. The IWC assumed direct jurisdiction over Alaska Native's bowhead 
whale subsistence in response to the IWC's concerns regarding the 
decline in the western Arctic bowhead whale stock. The IWC's only 
mechanism for protecting whale stocks is the setting of hunting quotas. 
Therefore, the IWC's only recourse for addressing its concerns was to 
prohibit the Alaska Native bowhead whale subsistence hunt. This action 
devastated local communities, creating immediate and severe food 
shortages. In response, in 1981, the AEWC was able to establish an 
agreement with the Federal Government to co-manage the bowhead whale 
hunting quotas.
    Although the AEWC was able to regain control of its bowhead whale 
hunting quotas, the organization shared a similar concern with the IWC 
regarding the potential effects of offshore oil exploration and 
development on the bowhead whale. Whalers observed how bowhead whales 
were responding to the presence of ocean-going oil and gas industry 
exploration vessels, which were making the whales skittish and 
affecting the whalers' ability to effectively meet the quotas for their 
communities. In response, the AEWC worked with industry stakeholders to 
establish the ``Oil/Whaler Agreement,'' which was a communication plan 
between whalers and exploration vessels that was intended to prevent 
direct threats to the whalers' safety from industry vessels.
    The AEWC and industry stakeholders eventually turned the ``Oil/
Whaler Agreement'' into a framework for understanding and addressing 
indirect interference with hunting activities, resulting from 
behavioral changes in bowhead whales as they react to the noise and 
other pollutants accompanying oil and gas work. This framework of 
understanding eventually formed the basis of what is now known as a 
CAA.\27\ While DOI does not require executing a CAA, BSEE and BOEM 
highly encourage operators to work with the AEWC to establish CAAs, 
since these agreements essentially acknowledge, within CAA provisions, 
that both subsistence hunting activities and oil and gas development 
can and should coexist. See discussion in Section I.E.3, History and 
Background on the Conflict Avoidance Agreement, of this preamble 
describing the provisions typically included in a CAA. This 
longstanding process allows for industry representatives to sit, in 
council, with members of the AEWC, local tribes, and village and 
regional corporations to determine cultural circumstances and 
situations that could cause conflict--and thus avoid them. For example, 
during whale (or walrus) hunting seasons in the spring and fall, the 
CAA may include provisions whereby industry will avoid construction or 
production noise and related activities during those times when whales 
are transiting nearby, and the hunters are in the area. With this early 
initiative, direct collaboration with local hunters, specifically the 
whaling captains and their representative organization, the AEWC, 
became a critical element of offshore industrial development planning 
and management in the Alaskan Arctic.
---------------------------------------------------------------------------

    \27\ Conflict Avoidance Agreements are contracts signed by the 
operators and the Alaska native communities to which BOEM is not a 
party.
---------------------------------------------------------------------------

    Today, the AEWC includes registered whaling captains and their 
crews from eleven whaling communities of the

[[Page 79273]]

Arctic Alaska coast: Gambell, Savoonga, Wales, Little Diomede, 
Kivalina, Point Hope, Point Lay, Wainwright, Barrow \28\ (Utquiavik), 
Nuiqsut, and Kaktovik. The AEWC often represents the Inupiat Community 
of the Arctic Slope (ICAS) in matters pertaining to energy exploration 
or development specifically for the OCS. The ICAS is a unique federally 
recognized tribal entity. ICAS membership is based on an individual's 
ancestral lineage to a village tribe; it includes the peoples of eight 
Native Villages: Kaktovik, Atqasuk, Nuiqsut, Anaktuvuk Pass, Barrow, 
Wainwright, Point Lay, and Point Hope. Each village tribe acts 
independently but will interact with ICAS and its membership as it 
relates to Federal and State energy issues.
---------------------------------------------------------------------------

    \28\ Although the Alaska Native tribe is based in Utquiavik, at 
any given time, the whaling may involve members of the Apugauti and 
Nalukatq tribes, whose native lands do not border the coast. For 
this reason, the AEWC prefers to refer to this group of whaling 
captains collectively by the broader term ``Barrow.''
---------------------------------------------------------------------------

    Conflict avoidance tools are often incorporated into leasing 
stipulations addressing consultation with subsistence communities, and 
will continue to be essential to help satisfy the need to provide a 
secure source of energy for the Nation while at the same time 
protecting the subsistence resources and uses of the local communities 
where these energy resources are located.
5. Industry Interest in the Arctic OCS
    In 1979, a year after the first Arctic offshore discovery (i.e., 
the Endicott oil field) was made in State waters, the Department, 
acting through the Bureau of Land Management (BLM), held the first oil 
and gas lease sale in the Arctic OCS, offering tracts adjacent to 
Prudhoe Bay in the Beaufort Sea Planning Area. That sale resulted in 24 
leases, covering 85,776 acres, being issued. Although it was the first 
sale ever conducted for the Arctic OCS, the revenues generated from 
that sale, over $491 million, make it the 4th largest sale in Arctic 
OCS history. That dollar amount would represent almost $1.9 billion 
dollars in 2019 after adjusting for inflation. Between 1979 and 2008, 
the Department, acting through the BLM and Minerals Management Service 
(MMS),\29\ held 13 oil and gas lease sales, and issued nearly 1,800 
leases, covering over 9.7 million acres, on the Arctic OCS. These sales 
generated over $6.8 billion in bonus bids. As many as 23 companies/
bidders have participated in an Alaska OCS lease sale and, while the 
number of companies/bidders participating from one sale to the next 
varied, an average of 10 companies/bidders participated in each sale.
---------------------------------------------------------------------------

    \29\ MMS was the predecessor agency of BSEE and BOEM.
---------------------------------------------------------------------------

    By 2008, U.S. oil production had been steadily declining for 5 
years to an average of 5 million barrels per day, while U.S. 
consumption of crude oil and petroleum products reached an all-time 
high of 20.68 million barrels per day.\30\ The price of oil increased 
steadily through 2007 from approximately $50 to $90 per barrel by the 
time the most recent Arctic sale, Lease Sale 193, was held in February 
of 2008.\31\ These market factors may have contributed to the outcome 
of Lease Sale 193, one of the most successful in Arctic OCS history, 
based on multiple metrics--the number of bids received, the number of 
tracts receiving bids, and the total amount of bonus bids received from 
the sale. The MMS received a total of 667 bids on 488 blocks; both 
record-setting numbers for the Arctic OCS. A total of 487 leases, 
covering over 2.7 million acres, were issued, and the sale generated 
over $2.6 billion in bonus bids, which went to the U.S. Treasury. Since 
2008, however, the Department has not conducted any new lease sales for 
the Arctic OCS. A description of the status of active leases in the 
Artic OCS is discussed in further detail below within this subsection, 
prior to the subheading entitled, Global Arctic Exploration Activities.
---------------------------------------------------------------------------

    \30\ https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=MTTUPUS2&f=A, table entitled, ``U.S. 
Product Supplied of Crude Oil and Petroleum Products (Thousand 
Barrels per Day)''.
    \31\ https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=F000000__3&f=M.
---------------------------------------------------------------------------

    Sale 193 was significant, not only in number of tracts sold and the 
amount received from the sale, but in that the industry's interest 
spurred a flurry of activities on the Arctic OCS prior to and after the 
sale. The following table lists those activities:

                                  2006
------------------------------------------------------------------------
June 20........................  MMS authorizes ConocoPhillips, Shell,
                                  and GX Technology Corporation to
                                  conduct geophysical operations for a
                                  portion of Chukchi Sea Planning Area,
                                  which covered the Sale 193 area.
------------------------------------------------------------------------
                                  2007
------------------------------------------------------------------------
July 13........................  MMS authorizes Shell to conduct
                                  additional geophysical operations in
                                  Chukchi Sea Planning Area covering the
                                  same area as their 2006 geophysical
                                  permit.
------------------------------------------------------------------------
                                  2008
------------------------------------------------------------------------
February 6.....................  MMS holds Chukchi Sea Lease Sale 193.
                                  Seven companies were issued leases
                                  from this sale--NACRA; Repsol; Shell;
                                  ConocoPhillips; Eni Petroleum;
                                  StatoilHydro; and Iona Energy Company.
February 15....................  MMS authorizes Shell to conduct even
                                  further geophysical operations, also
                                  covering the same area as their 2006
                                  geophysical permit.
------------------------------------------------------------------------
                                  2009
------------------------------------------------------------------------
May 9..........................  Shell submits its initial EP for the
                                  Chukchi Sea.
------------------------------------------------------------------------
                                  2010
------------------------------------------------------------------------
April 10.......................  BP Deepwater Horizon Incident--Blowout
                                  of the Macondo well (Gulf of Mexico).
May 19.........................  Secretary's Order 3299 reorganizing the
                                  Minerals Management Service and
                                  dividing its functions between three
                                  separate bureaus.
June 18........................  Secretary's Order 3302 creating the
                                  Bureau of Ocean Energy Management,
                                  Regulation, and Enforcement (BOEMRE).
August 8.......................  BOEMRE authorizes Statoil to conduct
                                  geophysical operations within and
                                  around the area where their leases
                                  were located in the Chukchi Sea
                                  Planning Area.

[[Page 79274]]

 
December 7.....................  BOEMRE conditionally approves Shell's
                                  initial EP for the Chukchi Sea.
------------------------------------------------------------------------
                                  2011
------------------------------------------------------------------------
May 11.........................  Shell submits a revised EP for the
                                  Chukchi Sea.
August 29......................  Secretary's Order 3299 was amended to
                                  divide BOEMRE into the Bureau of Ocean
                                  Energy Management (BOEM), the Bureau
                                  of Safety and Environmental
                                  Enforcement (BSEE), and the Office of
                                  Natural Resources Revenue (ONRR).
December 16....................  BOEM conditionally approves Shell's
                                  revised EP for the Chukchi Sea.
------------------------------------------------------------------------
                                  2012
------------------------------------------------------------------------
August 30......................  BSEE authorizes Shell to initiate
                                  certain limited preparatory
                                  exploration drilling activities;
                                  drilling of the top hole for Burger A
                                  exploration well in the Chukchi Sea.
September 9....................  Shell begins drilling operations for
                                  its Burger A exploration well in the
                                  Chukchi Sea, but was not able to
                                  complete its well operations. Shell
                                  returned in 2016 to complete its well
                                  operations, ultimately plugging and
                                  abandoning the well.
September 20...................  While not applicable to the Chukchi
                                  Sea, BSEE also authorizes Shell to
                                  initiate drilling of the top hole for
                                  the Sivuliq N exploration well in the
                                  Beaufort Sea.
October 3......................  Shell begins drilling operations for
                                  its Sivuliq N exploration well in the
                                  Beaufort Sea, but was not able to
                                  complete its well operations. Shell
                                  returned in 2016 to complete its well
                                  operations, ultimately plugging and
                                  abandoning the well.
------------------------------------------------------------------------
                                  2013
------------------------------------------------------------------------
August 5.......................  BOEM authorizes TGS to conduct
                                  geophysical operations for a portion
                                  of Chukchi Sea Planning Area covering
                                  a portion of the Sale 193 area.
November 6.....................  Shell submits a revised EP for the
                                  Chukchi Sea in response to lessons
                                  learned from its 2012 drilling
                                  operations of the Sivuliq N and Burger
                                  A exploration wells.
------------------------------------------------------------------------
                                  2014
------------------------------------------------------------------------
August 28......................  Shell submits a revised EP for the
                                  Chukchi Sea, replacing its November
                                  2013 submission.
------------------------------------------------------------------------
                                  2015
------------------------------------------------------------------------
January 21.....................  President Obama signed E.O. 13689,
                                  which calls for multiple agencies that
                                  may have jurisdictional
                                  responsibilities in the Arctic to
                                  enhance their coordination efforts to
                                  protect the nation's various interests
                                  in the region.
January 27.....................  President Obama issues Presidential
                                  Memorandum withdrawing certain areas
                                  of the OCS within the Beaufort and
                                  Chukchi Seas from leasing. These areas
                                  included the Hannah Shoal in the
                                  Chukchi Sea and lease deferral areas
                                  identified in BOEM's 2012-2017
                                  National OCS Oil and Gas Leasing
                                  Program.
February 24....................  BSEE and BOEM published the 2015
                                  Proposed Arctic Exploratory Drilling
                                  Rule, providing a 90-day period for
                                  the public to review and comment on
                                  the proposed rule.
May 11.........................  BOEM conditionally approves Shell's
                                  revised EP for the Chukchi Sea.
July 22........................  BSEE authorizes Shell to initiate
                                  certain limited preparatory
                                  exploration drilling activities;
                                  drilling of the top hole for Burger J
                                  exploration well in the Chukchi Sea.
July 31........................  Shell begins drilling operations for
                                  its Burger J exploration well in the
                                  Chukchi Sea.
September 21...................  Shell completes its Burger J
                                  exploration operations, and ultimately
                                  plugs and abandons the well.
October 16.....................  The Department cancels all Beaufort and
                                  Chukchi lease sales that were
                                  scheduled to take place as part of
                                  BOEM's 2012-2017 National OCS Oil and
                                  Gas Leasing Program.
------------------------------------------------------------------------
                                  2016
------------------------------------------------------------------------
December 30....................  President Obama issues a Presidential
                                  Memorandum that expands the withdrawal
                                  to all areas of the Chukchi Sea
                                  planning area and much of the Beaufort
                                  Sea planning area that were not
                                  currently withdrawn at that time. The
                                  withdrawal excludes Beaufort tracts
                                  located nearshore in an area that
                                  included existing leases at the time.
 

    A key factor that contributed to the length of time taken to 
authorize Shell's exploration drilling activities was a lawsuit filed 
by the Native Village of Point Hope challenging the Department's 
decision to hold Sale 193. See Native Village of Point Hope v. Salazar, 
730 F. Supp.2d 1009 (D. Ak., 2010); see also Native Village of Point 
Hope v. Jewell, 740 F.3d 489 (9th Cir., 2014). The original 
Environmental Impact Statement (EIS) for Sale 193 was published in 
2007, and the lease sale was held, but subsequent legal challenges and 
Federal court decisions remanded the lease sale to BOEM for further 
analysis. In response to the court remand, BOEM conducted additional 
analysis and incorporated that information into a Supplemental EIS that 
was published in February 2015 and affirmed the sale as held. Only 
thereafter were BOEM and BSEE able to complete their formal review of 
Shell's exploration plan for the Chukchi Sea and approve the drilling 
activities that took place in the summer of 2015.
    Between 2008 and 2019, oil prices remained unstable, increasing to 
an all-time high of almost $96 per barrel in 2013 to $44 per barrel in 
2015, which increased to $56 per barrel in 2019.\32\ Domestic oil 
production had grown since 2008, in part due to developments in tight 
oil onshore and Gulf of Mexico production, to about 9.4 million barrels 
per day in 2015 and 12.2 million barrels in 2019.\33\ Demand for oil 
remained relatively stable between 2008 and 2019, with only a minor 
increase in 2019 over 2008--approximately a 4% increase.\34\
---------------------------------------------------------------------------

    \32\ https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=F000000__3&f=M.
    \33\ https://www.eia.gov/todayinenergy/detail.php?id=4910.
    \34\ https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=MTTUPUS2&f=A, table titled ``U.S. Product 
Supplied of Crude Oil and Petroleum Products (Thousand Barrels per 
Day).
---------------------------------------------------------------------------

    On September 28, 2015, Shell announced that it would cease further 
exploration activity in offshore Alaska for the foreseeable future. 
Shell stated that its decision was based on the results of their Burger 
J well, which found indications of oil and gas, but were insufficient 
to warrant further

[[Page 79275]]

exploration in the Burger prospect. The company also stated that its 
decision was motivated by the high costs associated with the project, 
and the challenging and unpredictable Federal regulatory environment 
offshore Alaska.\35\ On November 17, 2015, Statoil announced its 
decision to exit Alaska and relinquish its leases acquired from Sale 
193. All leaseholders that acquired leases in Sale 193 eventually 
relinquished their leases.
---------------------------------------------------------------------------

    \35\ https://www.shell.com/media/news-and-media-releases/2015/shell-updates-on-alaska-exploration.html.
---------------------------------------------------------------------------

    Despite these setbacks, industry interest in the Arctic OCS and 
other areas of the Arctic, globally, has shown to be consistent amidst 
fluctuating commodity prices and concerns about regulatory challenges. 
Since 1998, nineteen geological and geophysical seismic surveys were 
permitted and completed for the Beaufort Sea and Chukchi Sea Planning 
Areas. The data from these surveys provide information to both industry 
and the government for use in lease sales and for design and evaluation 
of activities described in EPs and DPPs. Several different companies 
participated in each of the four Beaufort Sea Planning Area lease sales 
and the one Chukchi Sea Planning Area lease sale indicating on-going 
industry interest in the area. Companies submitted EPs, three in the 
Beaufort and one in the Chukchi Sea. These plans, and their revisions, 
received evaluation and conditional approval. BOEM approved two DPPs, 
both for the Beaufort Sea. Currently, there are 19 oil and gas leases 
in the Arctic OCS, all of which are located in the Beaufort Sea 
Planning Area. Exploratory drilling and development on these leases 
have taken place from gravel islands in State waters.
Global Arctic Exploration Activities
    In addition to the Arctic OCS activities just described, global 
interest and development has taken place in other parts of the Arctic. 
Countries, such as Russia, Norway, Canada, and Greenland have been 
diligently exploring their oil and gas resources in or near the Arctic.
    Greenland--Since the 1970s, exploration activities have taken place 
on the offshore waters of western Greenland. While these exploration 
activities have taken place in sub-Arctic regions, operators do 
experience some of the key challenges present in the Arctic. It is not 
uncommon for icebergs to pose dangers to drilling operations. Operators 
use ice management plans to identify, monitor, and tow away any 
icebergs that may impact their exploration operations. Operators also 
have contingency plans that may require disconnecting their drilling 
rig from the well and moving off location to avoid contact with 
icebergs.
    Canada--In the Jeanne d'Arc, Orphan, and Flemish Pass oil and gas 
basins on the Grand Banks of Newfoundland, operators have conducted 
exploration drilling from MODUs in shallow and deep waters. Like 
Greenland, the areas with oil and gas potential are located in sub-
Arctic regions that experience some seasonal sea ice and significant 
iceberg incursions. In these areas, operators also employ strong ice 
management and contingency plans.
    Norway--In Norway's portion of the Barents Sea, which is located 
entirely within the Arctic, exploration activities have taken place 
since 1980. Most of the area is free of sea ice year-round, but 
drilling has taken place in areas that do experience challenging Arctic 
OCS conditions. As late as 2014, exploration drilling took place in 
Norway's northern portion of the Barents Seas in what is known as the 
Hoop area. Those exploration operations entailed the use of winterized 
semisubmersible rigs and the availability of a capping stack.
    Russia--Russia's latest drilling operations also took place in 2014 
when ExxonMobil drilled a well in the South Kara Sea. The operation 
took place in an area of the Arctic where drilling could not take place 
during the winter months, similar to the Chukchi and Beaufort Seas. 
Exploration activities took place during the summer, when little to no 
sea ice was present at the drilling location and were completed in mid-
fall. The operation was similar to the operations from the other 
countries just described--a winterized MODU and robust ice management 
and contingency plans. However, unique to this project was the use of a 
subsea isolation device (SSID). (NPC Report 2015 at 6-17 and 6-18, and 
NPC Report 2019 at C-10). The Kara Sea project is discussed in more 
detail below in Section II. Section-by-Section Discussion of Proposed 
Changes, Subsection A. Key Revisions Proposed by BSEE, under the 
subheading entitled, Supplemental Assessment to the 2015 Report on 
Arctic Potential: Realizing the Promise of U.S. Arctic Oil and Gas 
Resources (NPC 2019 Report).
Global Arctic Exploration Requirements
    Norway, Canada, and Greenland have similar regulatory requirements 
to the United States for Arctic offshore drilling operations performed 
from a MODU. The Bratslavsky and SolstenXP study also included a review 
of the regulatory requirements from these countries that pertain to 
relief wells, SCCE, and approval of alternative technologies. The study 
did not include Russia in its review because the country's regulations 
could not be accessed. Here is a summary of that review:
     Relief Wells--All the Arctic countries that were reviewed 
specifically require relief wells, but regulations among them differ. 
For example, Canada simply requires a ``same[hyphen]season'' relief 
well capacity, whereby the operator demonstrates its capability to 
drill a relief well and kill an out[hyphen]of[hyphen]control well in 
the same drilling season. Whereas the U.S. requires the ability to 
bring in a relief[hyphen]drilling rig and complete the plug and 
abandonment within 45 days, Norway and Greenland require a 
relief[hyphen]drilling rig to be on site within 12 days.
     SCCE--Canada is the only country besides the U.S. that has 
specific SCCE requirements. Canada's requirements, however, are less 
prescriptive in that they include a more general requirement for ``cap 
and containment methods and same[hyphen]well intervention methods,'' as 
compared to the U.S. requirement for access to specific SCCE equipment 
within a specified time period.
     Alternative Technologies--With respect to approval of 
alternative technologies in lieu of a relief rig or SCCE, the U.S. has 
specific regulations that allow for potential substitutions and 
accommodations for innovative technologies. Canada also provides for 
the approval of alternative technologies through specific approval 
processes. Norway's regulations, in general, are largely performance-
based. As such, their regulations allow for the consideration of 
different technologies at the onset when planning a project.

B. BSEE and BOEM Statutory and Regulatory Authority and 
Responsibilities

    The Outer Continental Shelf Lands Act, 43 U.S.C. 1331 et seq., was 
first enacted in 1953 and substantially amended in 1978. In amending 
OCSLA, Congress established a national policy of making the OCS 
``available for expeditious and orderly development, subject to 
environmental safeguards, in a manner which is consistent with the 
maintenance of competition and other national needs.'' (43 U.S.C. 
1332(3)). OCSLA authorizes the Secretary of the Interior (Secretary) to 
lease the OCS for mineral development and to regulate oil and gas 
exploration, development, and production operations on the OCS.
    On May 19, 2010, Secretary Ken Salazar issued S.O. 3299, which

[[Page 79276]]

restructured and divided the former MMS's responsibilities under OCSLA 
among three new bureaus: (i) BOEM; (ii) BSEE; and the (iii) Office of 
Natural Resources Revenue (ONRR). S.O. 3299 delegated those 
responsibilities for oil and gas operations to BSEE and BOEM, both of 
which are charged with administering and regulating aspects of the 
Nation's OCS oil and gas program (see 30 CFR parts 250 and 550).
    On June 18, 2010, Secretary Salazar issued S.O. No. 3302, which 
announced the name change of part of the former MMS to the Bureau of 
Ocean Energy Management, Regulation and Enforcement (BOEMRE). This 
name, BOEMRE, would remain in effect until BOEM and BSEE were 
officially created under S.O. 3299, effective October 1, 2011.
    On October 1, 2010, the revenue-collection functions of the former 
MMS were transferred to ONRR, reporting to the Assistant Secretary for 
Policy, Management and Budget.
    S.O. 3299 assigned BOEM the responsibility for managing the 
development of the Nation's offshore conventional and renewable energy 
resources. BOEM's mission is to manage the development of the OCS 
energy and mineral resources in an environmentally and economically 
responsible way. BOEM's functions include: Leasing; EP administration; 
DPP administration; permitting of geological and geophysical 
activities; environmental analyses in compliance with NEPA; 
environmental studies; compliance with relevant laws (e.g., the 
Endangered Species Act (ESA), the Marine Mammal Protection Act, the 
Magnuson-Stevens Fishery Conservation and Management Act, and the 
Coastal Zone Management Act \36\ (CZMA)); resource evaluation; oil 
spill worst case discharge (WCD) determination; economic analysis and 
fair market value bid/lease evaluations; management of the OCS 
renewable energy and marine mineral programs; and consultation with 
other entities at the local (e.g., North Slope Borough, Native 
Villages), tribal (e.g., Federally recognized tribes and Alaska Native 
Claims Settlement Act Corporations), State, and Federal levels (e.g., 
National Oceanic and Atmospheric Administration (NOAA) Fisheries, U.S. 
Coast Guard (USCG)) related to activities within BOEM's activities and 
areas of responsibility.
---------------------------------------------------------------------------

    \36\ BOEM is not subject to the requirements of the CZMA in 
Alaska as it is on the rest of the OCS, where it is required to 
provide opportunities to the coastal State to review the proposed 
Federal actions for consistency with the state's federally approved 
coastal management program. More specifically, on July 1, 2011, 
Alaska repealed its CZMA program.
---------------------------------------------------------------------------

    Secretary's Order 3299 made BSEE responsible for safety and 
environmental enforcement functions, including, but not limited to, the 
authority to permit activities, inspect, investigate, summon witnesses 
and produce evidence: Levy penalties; cancel or suspend activities; and 
oversee safety, and oil spill response and removal preparedness. BSEE's 
mission is to promote safety, protect the environment, and conserve 
resources through vigorous regulatory oversight and enforcement. BSEE's 
functions include evaluating permit applications for post-lease oil and 
natural gas exploration and development activities on the OCS and 
conducting inspections to ensure compliance with laws, regulations, 
lease terms, and approved plans and permits.
    BOEM evaluates EPs, and BSEE, thereafter, evaluates Applications 
for Permits to Drill (APDs) and other permits and applications, to 
determine whether the operator's proposed activities meet OCSLA's 
standards and each Bureau's regulations governing OCS exploration. 
Based on their respective evaluations, BSEE and BOEM will either 
approve the operator's EP and APD, require the operator to modify its 
submissions, or disapprove the EP or APD (Sec.  250.410, How do I 
obtain approval to drill a well?). The review and approval of these 
activities is outlined below in the following section.
1. BOEM Approval of the EP
    As promulgated through the 2016 Arctic Exploratory Drilling Rule, 
Sec.  550.204, When must I submit my IOP for proposed Arctic 
exploratory drilling operations and what must the IOP include?, 
requires that a lessee submit an IOP at least 90 days before filing an 
EP with BOEM, if that EP would involve exploration for oil and gas on 
the Arctic OCS. While the IOP is not subject to approval, the 
submission was intended to facilitate the prompt sharing of information 
among the relevant Federal agencies that may be involved in overseeing 
exploratory drilling operations conducted from MODUs. The operator may 
then submit an EP to BOEM for approval. An EP must include information 
such as a schedule of anticipated exploration activities, equipment to 
be used, the general location of each well to be drilled, and any other 
information deemed pertinent by BOEM (Sec. Sec.  550.211 through 
550.228).
2. BSEE Approval of the APD
    Approval of an EP does not, by itself, permit the operator to 
proceed with exploratory drilling. After BOEM approves the EP, the 
operator must submit to BSEE an APD, which BSEE must approve before an 
operator may drill a well (43 U.S.C. 1340(d); Sec.  250.410). Among 
other things, the APD must be consistent with the approved EP and 
include information on the well location, the drilling design and 
procedures, casing and cementing programs, the diverter and blowout 
preventer (BOP) systems, MODU (if one is to be used), and any 
additional information requested by the BSEE District Manager.

C. Executive and Secretary's Orders

    On March 28, 2017, the President issued E.O. 13783--Promoting 
Energy Independence and Economic Growth (82 FR 16093). The E.O. 
directed Federal agencies to review all existing regulations and other 
similar agency actions, which potentially burden the development or use 
of domestically produced energy resources with the goal of ``avoiding 
regulatory burdens that unnecessarily encumber energy production, 
constrain economic growth, and prevent job creation.'' It made it U.S. 
policy for agencies to ``review existing regulations that potentially 
burden the development or use of domestically produced energy resources 
and appropriately suspend, revise, or rescind those that unduly burden 
the development of domestic energy resources beyond the degree 
necessary to protect the public interest or otherwise comply with the 
law.''
    On April 28, 2017, the President issued E.O. 13795--Implementing an 
America-First Offshore Energy Strategy (82 FR 20815), which directed 
the Secretary to ``take all steps necessary to review'' the 2016 Arctic 
Exploratory Drilling Rule and, ``if appropriate, [to,] as soon as 
practicable and consistent with law, publish for notice and comment a 
proposed rule suspending, revising, or rescinding this rule.'' The 
policy underlying E.O. 13795 is ``to encourage energy exploration and 
production, including on the Outer Continental Shelf, in order to 
maintain the Nation's position as a global energy leader and foster 
energy security and resilience for the benefit of the American people, 
while ensuring that any such activity is safe and environmentally 
responsible.'' These E.O.s did not dictate outcomes; rather, they 
provided direction for review in accordance with all relevant laws.
    To further implement E.O. 13795, on May 1, 2017, the Secretary 
issued S.O. 3350, America-First Offshore Energy Strategy, directing 
BSEE and BOEM to review the 2016 Arctic Exploratory

[[Page 79277]]

Drilling Rule ``for consistency with the policy set forth in section 2 
of E.O. 13795'' and to prepare a report ``summarizing the review and 
providing recommendations on whether to suspend, revise, or rescind the 
rule.''
    Consistent with E.O.s 13783 and 13795, and S.O. 3350, BSEE and BOEM 
reviewed the regulations promulgated through the 2016 Arctic 
Exploratory Drilling Rule and are proposing revisions to those 
regulations to reduce unnecessary burdens on industry while maintaining 
safety and environmental protection.

D. Purpose and Summary of the Rulemaking

    BSEE and BOEM promulgated the 2016 Arctic Exploratory Drilling Rule 
based on experiences gained from Shell's 2012 and 2015 Arctic 
operations, internal reviews conducted on potential oil and gas 
operations on the Arctic OCS, and concerns expressed by environmental 
organizations and Alaska Natives.
    Since publication of the 2016 Arctic Exploratory Drilling Rule, 
however, BSEE and BOEM have become aware of additional information 
informing and warranting the bureaus' reconsideration of certain 
regulatory provisions promulgated through that rule. BSEE commissioned 
a Technology Assessment Program study (Bratslavsky and SolstenXP, 2018) 
that entailed a historical statistical analysis of recent Alaska Arctic 
OCS drilling seasons (5-year period between 2012 and 2016), in which 
meteorology and physical oceanographic (``metocean'') and operational 
conditions would support the safe deployment of SCCE, the drilling of a 
relief well, or both. The study included a comprehensive review and gap 
analysis of U.S. and international regulations, standards, recommended 
practices, specifications, technical reports, and common industry 
methods regarding the safe deployment of SCCE, as compared to the 
effectiveness of drilling a relief well in Arctic conditions.
    The Bratslavsky and SolstenXP study determined that metocean 
conditions prevalent in the Chukchi Sea and Beaufort Sea (i.e., rough 
sea states and sea ice conditions, primarily) are key factors that 
limit the ability to safely deploy SCCE throughout the Arctic OCS. The 
study determined that, when operating in the presence of sea ice in the 
Chukchi Sea and the Beaufort Sea, there is a greater probability for 
safe relief well deployment versus SCCE deployment. When operating in 
open water conditions (i.e., those prone to rough sea states) in the 
Chukchi Sea, there is also a greater probability for safe deployment of 
a relief rig versus SCCE. In the Beaufort Sea, the probability for 
safely deploying relief wells and SCCE is the same. This is because the 
Beaufort Sea has fewer ice-free days than the Chukchi and ice helps 
maintain calm sea state conditions.
    The study also determined that water depth in the Arctic OCS is 
also a factor limiting the safe deployment of SCCE. According to the 
Bratslavsky and SolstenXP study, safe deployment of SCCE is likely to 
be impaired in water depths shallower than 984 feet because the 
equipment would potentially encounter a gas boil at the surface caused 
by a subsea blowing well (Bratslavsky and SolstenXP at 143). Water 
depths in the majority of the Chukchi Sea and Beaufort Sea where 
exploration has historically occurred are relatively shallow--167 feet 
or less (id. at 7 to 9). This water depth range limits the fleet of 
support vessels that could be used for the safe deployment of SCCE.
    The NPC also published its NPC 2019 Report as a supplemental 
assessment to the NPC 2015 Report. The NPC prepared the NPC 2019 Report 
in response to an April 2018 request from the Secretary of Energy. The 
Secretary of Energy requested that the NPC provide recommendations for 
enhancing the Nation's regulatory environment by improving reliability, 
safety, efficiency, and environmental stewardship of oil and gas 
activities on the OCS. That report specifically addressed the 
regulatory burdens associated with U.S. Arctic OCS development.
    Key findings from the NPC's supplemental assessment that helped 
inform the preparation of this proposed rule include the NPC's 
determination that the requirement to drill an SSRW to mitigate the 
risk of a late season well control event continuing over the winter 
season is ``outdated.'' The report concluded that SSIDs and capping 
stacks are superior solutions that could stop the flow of oil and allow 
intervention through the original borehole before a relief well could 
be completed (NPC 2109 Report at 19). Details in the report regarding 
Russia's 2014 drilling operation that included the use of an SSID in 
the South Kara Sea also informs this proposed rule.
    In this proposed rule, the Bureaus also address other issues in 
addition to those addressed in the 2016 Arctic Exploratory Drilling 
Rule, including seasonal weather-related constraints in the Arctic that 
severely impact an operator's ability to safely perform leaseholding 
operations for a significant portion of the term on a lease. While 
these issues are in addition to the issues addressed by the 2016 Arctic 
Exploratory Drilling Rule, they are unique to the Arctic OCS and, 
therefore, are appropriate to address as part of this proposed 
rulemaking.
    BSEE and BOEM recognize that the 2016 Arctic Exploratory Drilling 
Rule addressed specific operational and environmental conditions that 
are unique to the Arctic OCS. While this proposed rule would leave most 
of the regulations promulgated by the 2016 rule unaltered, certain of 
these regulations are worth reconsidering to accommodate technological 
innovation and encourage energy exploration on the Arctic OCS. Based on 
the new scientific information gathered from the Bratslavsky and 
SolstenXP study, and global practical experience gained in recent 
years, as described in the NPC Reports, the bureaus believe that these 
proposed revisions reduce unnecessary regulatory burdens on 
stakeholders and increase the ability to review and apply advancing 
technological innovations, while ensuring safety and environmental 
protection.
    The following paragraphs briefly summarize the key elements of this 
proposed rule, which are more fully explained in Section II. Section-
by-Section Discussion of Proposed Changes of this preamble:
    1. Seasonal Conditions SOO--The unique seasonal conditions in the 
Arctic make it difficult or physically impossible for operators to 
explore their leases for a significant portion of each year. To 
facilitate the proper development of Arctic leases in accordance with 
OCSLA sec. 5,\37\ BSEE proposes to add a new provision to its 
regulations that would provide those operators that are conducting 
drilling operations, but are prevented from completing those 
leaseholding operations due to seasonal constraints unique to the 
Arctic, with the opportunity to obtain an SOO. If granted, this type of 
SOO would suspend the running of the lease term and effectively extend 
the term of the affected lease by a period equivalent to the period of 
such suspension. This would provide operators that are otherwise ready 
and able to conduct drilling operations with additional time to 
diligently explore their leases, without facing lease expiration due to

[[Page 79278]]

interference by seasonal constraints unique to the Arctic.
---------------------------------------------------------------------------

    \37\ OCSLA sec. 5 (as amended) provides in pertinent part: ``The 
regulations prescribed by the Secretary . . . shall include . . . 
provisions . . . for the suspension . . . of any operation or 
activity . . . at the request of a lessee, in the national interest, 
[or] to facilitate proper development of a lease . . . and for the 
extension of any permit or lease affected by [such] suspension . . . 
by a period equivalent to the period of such suspension . . . .'' 43 
U.S.C. 1334(a)(1).
---------------------------------------------------------------------------

    2. Water-Based Mud and Cuttings--BSEE proposes to eliminate 
references to the Regional Supervisor's discretionary authority to 
require the capture of water-based muds and cuttings in those cases 
where subsistence values might be impacted by such discharges. While 
not intended, BSEE understands that this reference created some 
uncertainty for the regulated industry, because it appeared to overlap 
with regulation by the Environmental Protection Agency (EPA) and, if 
implemented, might result in BSEE issuing requirements that contradict 
EPA's requirements.
    3. SCCE--BSEE would preserve the requirement for the operator to 
have access to its SCCE when drilling below or working below the 
surface casing. However, with respect to the capping stack, the Bureau 
proposes to provide an opportunity to the operator to adjust the point 
in time during operations when it must position its capping stack so 
that it is available to arrive at the well location within 24 hours 
after a loss of well control. The existing regulations also impose a 
positioning requirement on the cap and flow system, and containment 
dome--slightly different from the capping stack--``positioned to ensure 
that it will arrive at the well location within 7 days after a loss of 
well control.'' BSEE's proposed changes to the positioning requirement 
for the cap and flow system and containment dome are discussed in more 
detail later in this paragraph. If the operator is able to demonstrate 
to BSEE, based on documentation it submits as part of its APD, that the 
operations it plans to conduct below the surface casing would not 
encounter any abnormally high-pressured zones or other geological 
hazards before reaching the last casing point prior to penetrating a 
zone capable of flowing hydrocarbons in measurable quantities, then 
BSEE will allow the operator to delay its positioning of the capping 
stack until reaching that casing point. BSEE's proposal to delay the 
positioning of the capping stack would be based on the documentation 
that the operator provides as well as any other available data and 
information. As previously mentioned, BSEE also proposes to eliminate 
the requirement for the operator to ensure that the containment dome 
and cap and flow system are positioned so as to arrive at the well 
location within seven days after a loss of well control. The 
Bratslavsky and SolstenXP study evaluated current industry methods and 
standards for deploying SCCE in Arctic OCS conditions, and determined 
that meteorological conditions (e.g., rough sea state and sea ice 
conditions) prevalent in the Chukchi Sea and Beaufort Sea are the key 
factors limiting the time periods when SCCE may be safely deployed 
throughout the Arctic OCS. This is discussed in further detail below in 
Section II. Section-by-Section Discussion of Proposed Changes, under 
the subheading What are the requirements for Arctic OCS source control 
and containment? (Sec.  250.471). It is not practical for BSEE's 
regulations to prescribe that certain SCCE (containment dome and cap 
and flow system, in particular) be positioned within proximity to a 
well location when the conditions for safely deploying this equipment 
in the Arctic OCS are limiting. However, BSEE would retain other 
existing containment dome and cap and flow system requirements in Sec.  
250.471, which provide that the operator must:
    (i) Demonstrate that it has access to a containment dome and cap 
and flow system;
    (ii) Provide a containment dome and cap and flow system that meets 
BSEE's operating standards;
    (iii) Conduct tests or exercises for all SCCE; and
    (iv) Maintain records pertaining to the testing, inspection, 
maintenance, and use of the SCCE and make these available to BSEE upon 
request. The changes BSEE proposes to the SCCE requirements in Sec.  
250.471 would preserve the regulations' requirement that operators have 
redundant protective measures that are appropriate for Arctic OCS 
conditions because there is no guarantee that a single measure could 
control or contain a WCD.
    4. Same Season Relief Well (SSRW) Requirement and Subsea Isolation 
Devices (SSID)--BSEE proposes to revise the relief rig and SSRW 
requirements by providing the operator with the option of using an SSID 
or having access to a relief rig as an additional means to secure the 
well in the event of a loss of well control, if the operator will be 
conducting exploratory drilling operations from a MODU. In addition, 
BSEE proposes to provide an opportunity to the operator to adjust the 
point in time during operations when it must stage its relief rig (if 
the operator elects to have access to a relief rig) when conducting 
Arctic OCS exploratory drilling operations--from when drilling below or 
working below the ``surface casing'' to when drilling below or working 
below the ``last casing point prior to penetrating a zone capable of 
flowing hydrocarbons in measurable quantities.'' If the operator is 
able to demonstrate to BSEE, based on documentation it submits as part 
of its APD, that the operations it plans to conduct below the surface 
casing would not encounter any abnormally high-pressured zones or other 
geological hazards before reaching the last casing point prior to 
penetrating a zone capable of flowing hydrocarbons in measurable 
quantities, then BSEE will allow the operator to delay its staging of 
the relief rig until reaching that casing point. BSEE's proposal to 
permit the delay of the staging of the relief rig will be based on the 
documentation that operator provides, as well as any other available 
data and information. In the relief rig and SSRW regulation, BSEE would 
also eliminate the reference to expected seasonal ice encroachment 
because the relevant timeframes for operations should be based on the 
capabilities of the operator's rig and equipment to operate in the 
applicable ice conditions, rather than an absolute date.
    5. Mudline Cellars--BSEE proposes to clarify the requirement for 
the operator, in areas of ice scour, to use a mudline cellar when 
drilling that is designed to minimize the risk of damage to the well 
head and wellbore. The existing regulation could be read to require the 
operator to use a mudline cellar in all cases, except when the operator 
can prove that the mudline cellar would present an operational risk, 
and that was not BSEE's intent. This proposed change would make it 
clear that the operator has more flexibility to propose to employ 
alternate procedures or equipment instead of the mudline cellar under 
appropriate circumstances, as provided by the longstanding provisions 
of Sec.  250.141, May I ever use alternate procedures or equipment?; 
not just when a mudline cellar would present an operational risk and if 
the operator is able to demonstrate that the alternate procedure or 
equipment would provide a level of safety and environmental protection 
that equals or surpasses the mudline cellar requirement.
    6. IOP--BOEM proposes to eliminate the requirement that the 
operator submit an IOP because it requires submission of information 
that overlaps with that required in the EP and the IOP's early 
information sharing is unnecessary in light of BOEM's practice for 
reviewing and coordinating review of the EP. Consequently, the operator 
is already aware that it must plan for how it will reduce operational 
risks and address the challenges associated with operations on the 
Arctic OCS through its EP.

[[Page 79279]]

E. Partner Engagement in Preparation for This Proposed Rule

1. Summary of Partner Interaction
    In advance of publishing this proposed rule, BSEE and BOEM reached 
out to Alaska Native tribal leaders, ANCSA corporations, and native 
village leaders in Northern Alaska for Government-to-Government 
consultations and municipal meetings. These Bureaus arranged 
consultations and meetings to receive input from these groups on 
potential regulatory changes that could encourage energy exploration 
and production and reduce unnecessary regulatory burdens, while 
maintaining safety and environmental protection. Between November 29, 
2018 and January 30, 2019, BSEE and BOEM officials met with 23 tribal, 
ANCSA corporation, and municipal leaders at villages throughout 
Northern Alaska (Kotzebue, Point Hope, Utqiagvik [i.e., Barrow], 
Nuiqsut, and Kaktovik), in Fairbanks, and in Anchorage. In addition, 
BSEE and BOEM held a consultation meeting via a conference call with 
tribal representatives from the Native Village of Point Lay. The 
following list identifies the entities with which BSEE and BOEM met:
     Tribal Governments--Native Village of Utqiagvik, Native 
Village of Wainwright, Native Village of Kotzebue, Native Village of 
Point Hope, Native Village of Nuiqsut, Native Village of Kaktovik, 
Tanana Chiefs Conference, and Native Village of Point Lay;
     Native Corporations--Olgoonik Native Corporation, Doyon 
Limited, Arctic Slope Regional Corporation, Tikigaq Native Corporation, 
Cully Corporation, Kuukpik Corporation, and Kaktovik Inupiat 
Corporation;
     Municipal Governments--Northwest Arctic Borough, Point 
Hope, North Slope Borough, City of Utqiagvik, Nuiqsut, and Kaktovik; 
and,
     Other Tribal Organizations--ICAS and the AEWC.
    BSEE and BOEM shared information with the tribal representatives 
describing potential options for regulatory change that the Bureaus 
were considering at the time the meetings took place. BSEE and BOEM 
made multiple attempts to contact two corporations--Kikiktagruk 
Corporation and NANA Regional Corporation but did not receive a 
response from them.
2. Summary of Comments Received
    BSEE and BOEM heard a variety of perspectives during these meetings 
with Alaska Natives. The most common comment received was a concern 
over food security. Subsistence resources, including bowhead and beluga 
whales, other marine mammals, fish, and birds, are a key food source 
for many peoples' diets in the native villages. The Alaska Natives' 
primary concerns pertained to protecting their food sources. BSEE and 
BOEM are fully aware that subsistence resources play a key role in 
offsetting the high costs of conventional food supplies and that 
subsistence hunting and fishing play a key role in the cultural 
identity of Alaska Natives. BOEM's leases all contain provisions 
related to the protection of these subsistence uses and BOEM's 
regulations at Sec. Sec.  550.227(b)(7) and 550.261(b)(7) require 
lessees to explain how they propose to protect these subsistence uses. 
In addition, BSEE and BOEM are not proposing any regulatory changes 
that would adversely affect protection of subsistence uses.
    Certain tribal representatives, and most ANCSA corporations, were 
supportive of this rulemaking, and explained that it could help attract 
more economic opportunities to their villages. In some cases, tribes or 
corporations advocated for the use of their villages to support safer 
oil and gas operations, because the villages have deeper ports that 
could support larger vessels, or because they may be located closer to 
potential drilling operations than those ports or facilities that have 
been used in the past. This could allow for quicker response to 
emergency incidents.
    BSEE did not include any regulatory changes in this proposed rule 
specifically designed to respond to this comment. While requiring the 
staging of equipment at strategically located coastal depots could have 
a positive impact on oil spill responses in the Arctic, the 
identification and placement of depots for such resources falls to the 
discretion of the operator (within the parameters established by 
existing regulation). To provide each plan holder with the flexibility 
needed to respond to their WCD scenarios, BSEE's Oil Spill Response 
Plan (OSRP) regulations do not mandate the use of any particular 
staging location(s) for equipment and personnel. BSEE will review the 
operator's staging arrangements submitted as part of the proposed OSRP 
to ensure that the OSRP would fully comply with the planning 
requirements in the governing regulations.
    Other comments provided during the consultation meetings included a 
recommendation for BSEE and BOEM to provide broader outreach by 
presenting this proposed rule to their tribal assembly and to citizens 
within the communities.
    DOI strives to strengthen its government-to-government relationship 
with federally recognized tribes through a commitment to consultation 
with tribes and recognition of their right to self-governance and 
tribal sovereignty. E.O. 13175, Consultation and Coordination with 
Indian Tribal Governments and DOI's tribal consultation policy, which 
implements the E.O., provide for procedures for consultation with 
tribes when taking an action with tribal implications. DOI has extended 
its consultation policy to ANCSA corporations. Furthermore, BSEE and 
BOEM recently issued their own expanded tribal consultation guidance on 
August 20, 2019 and June 29, 2018, respectively. BSEE's guidance 
(Bureau of Safety and Environmental Enforcement (BSEE) Tribal 
Consultation Guidance, August 20, 2019, available at https://www.bsee.gov/bsee-tribal-guidance-2019) and BOEM's guidance (BOEM 
Tribal Consultation Guidance, June 29, 2018, available at https://www.boem.gov/Tribal-Engagement/), identify various consultation 
authorities that BSEE and BOEM will follow in consulting with tribes 
and ANCSA corporations.
    DOI recognizes and respects the distinct, unique, and individual 
cultural traditions and values of Alaska Native people and the 
statutory relationship between ANCSA Corporations and the Federal 
Government. BSEE and BOEM will endeavor to go above and beyond their 
consultation responsibilities where and when appropriate throughout the 
rulemaking process to maintain a strong working relationship with their 
tribal and ANCSA corporation partners.
    BSEE and BOEM also received a comment from one of the ANCSA 
corporations recommending that this rulemaking take into account the 
NPC 2019 Report. BSEE and BOEM considered the NPC reports when 
preparing this proposed rule and based some of the proposed regulatory 
revisions on that report's recommendations, as discussed more fully 
below.
    Another common comment that BSEE and BOEM received was a 
recommendation to include a requirement for a CAA between the oil and 
gas operator and those whaling communities potentially affected by an 
operator's proposed drilling project. A CAA is typically established 
through a collaborative process whereby both parties work to create 
mitigation strategies that would avoid adverse impacts to bowhead 
whales and other marine mammals, their habitat, and hunting 
opportunities. Historically, operators have voluntarily used the CAA 
process and, currently, existing lessees are required to do so through

[[Page 79280]]

lease stipulations.\38\ See discussion in Section I.E.3, History and 
Background on the Conflict Avoidance Agreement, of this preamble 
describing the history and background of the CAA. In addition, under 
the MMPA, the taking of marine mammals without a permit or exception is 
prohibited in order to prevent the decline of species and populations. 
To avoid liability for take, operators must obtain an Incidental Take 
Authorization or Incidental Harassment Authorization for activities 
related to offshore exploration, development and production. 
Implementation of the MMPA is shared between NMFS and USFWS.
---------------------------------------------------------------------------

    \38\ Every BOEM Arctic lease contains a variant of the following 
stipulation: ``Prior to submitting an exploration plan or 
development and production plan (including associated oil-spill 
contingency plans) to MMS for activities proposed during the bowhead 
whale migration period, the lessee shall consult with the directly 
affected subsistence communities, Barrow, Kaktovik, or Nuiqsut, the 
North Slope Borough (NSB), and the AEWC to discuss potential 
conflicts with the siting, timing, and methods of proposed 
operations and safeguards or mitigating measures which could be 
implemented by the operator to prevent unreasonable conflicts. 
Through this consultation, the lessee shall make every reasonable 
effort, including such mechanisms as a conflict avoidance agreement, 
to assure that exploration, development, and production activities 
are compatible with whaling and other subsistence hunting activities 
and will not result in unreasonable interference with subsistence 
harvests.
    A discussion of resolutions reached during this consultation 
process and plans for continued consultation shall be included in 
the exploration plan or the development and production plan. In 
particular, the lessee shall show in the plan how its activities, in 
combination with other activities in the area, will be scheduled and 
located to prevent unreasonable conflicts with subsistence 
activities.''
---------------------------------------------------------------------------

    Section 7(a)(2) of the ESA requires every Federal agency to ensure 
that any action they authorize, fund, or carry out is not likely to 
jeopardize the continued existence of a listed species or result in the 
adverse modification of designated critical habitat. When any 
exploration or development plan, or G&G permit application, is 
submitted to BOEM, BOEM evaluates the proposal, and consults with NMFS 
and USFWS on species listed under the ESA. During this process, 
mitigation measures (e.g., vessel speed restrictions, rig lighting 
specifications, and protected species observer requirements) are 
developed to reduce impacts to protected species. These measures are 
then included in BOEM's conditions of approval for the EP, DPP, or G&G 
permit.
    BOEM did not include any regulatory changes in this proposed rule 
specifically designed to respond to this comment. BOEM cannot require 
whaling communities to establish agreements with operators, since BOEM 
has no jurisdiction over such communities. Such a requirement for 
lessees and operators to execute an agreement could give a third-party 
power to set conditions for, or veto, OCS activities over which they 
otherwise have no authority.
    For those reasons, BOEM has concluded that a regulation would not 
result in any additional protections of subsistence whaling beyond 
those provided by its longstanding practice of addressing the issue in 
a lease stipulation. BOEM has included as a lease stipulation for all 
Arctic OCS lease sales since 1991 that the lessee must make every 
reasonable effort, including such mechanisms as a CAA, to assure that 
exploration, development, and production activities are compatible with 
whaling and other subsistence hunting activities and will not result in 
unreasonable interference with subsistence harvests. Implementation of 
the stipulation must be described in an EP under Sec.  550.222. In 
addition, either BOEM or BSEE may require additional mitigation 
measures at the EP or the APD stages, as necessary, to appropriately 
address potential interference with subsistence activities. For 
example, because subsistence hunters are concerned that the effects of 
offshore oil and gas exploration might displace migrating bowhead 
whales and other marine mammals (like beluga whales), the Bureaus will 
meet with the AEWC and its whaling captains to help document 
traditional knowledge pertaining to bowhead whales, including movement 
and behavior.
    Given the importance of subsistence activities and related socio-
cultural activities to the Alaska Native communities, BOEM has long 
encouraged operators to work directly with interested parties to help 
mitigate potential impacts to subsistence activities. In addition, BOEM 
funds and supports studies to better understand the potential impacts 
from OCS operations on marine mammals and subsistence activities. Over 
the last 46 years, the environmental studies program has provided more 
than $1.2 billion nationally for scientific research on the OCS. Nearly 
$500 million of that amount has funded studies in Alaska to produce 
more than 1,000 technical reports and innumerable peer reviewed 
publications. BOEM uses information from the studies program to 
evaluate the potential environmental effects of leasing OCS lands for 
exploration and development. Since July 2016, BOEM has completed 35 
environmental studies and has 23 ongoing studies that cover the Arctic, 
totaling nearly $72 million. While environmental conditions change and 
continue to change (e.g., walrus habitat, bowhead whale migration, and 
ice coverage), BOEM's environmental studies program both adds to our 
understanding and tracks these changes to have the best science 
available for the public, industry, and federal permitting decisions. 
While BOEM has observed changes through these studies, these changes 
follow the trajectory that BOEM has been studying and documenting for 
several decades. While this proposed rule would change how operators 
could explore for OCS resources in the Arctic, there are ample 
opportunities to permit these activities consistent with ESA, MMPA, 
NEPA, and consultation with Alaska Native communities.
3. History and Background on the Conflict Avoidance Agreement
    In 1977, the IWC expressed concern over the low bowhead whale 
population. Its report specifically mentioned that the future expansion 
of offshore oil and gas extraction in the Arctic posed a potential risk 
to the bowhead whale population. At that time, Inuit subsistence 
hunters knew that bowhead whales were sensitive to anthropogenic noise, 
movements, and even smells. There were concerns that increased activity 
would affect their hunt. Traditional hunters had noticed that boat 
traffic, seismic exploration, and drilling were causing migrating 
whales to deflect away from the shore and beyond the hunters' reach.
    Beginning in 1986, offshore stakeholders, such as representatives 
from whaling villages, the AEWC, and oil and gas companies, have all 
met to identify sources of potential conflict, and have relied on local 
traditional knowledge as well as other information. CAAs were developed 
first in the 1980s to address these sources of potential conflict and 
have been referenced in lease stipulations since 1991.
    Since 1991, all leases in the Arctic issued by BOEM or its 
predecessors have included a stipulation requiring the operator to 
coordinate their activities with potentially affected Alaska native 
communities. While the text of these stipulations has varied from time 
to time, all of them have included certain important components. The 
following is an extract from such a stipulation, incorporated into the 
leases issued from the Oil and Gas Lease Sale Number 202, issued on 
April 18, 2007:

    Prior to submitting an exploration plan or development and 
production plan (including associated oil-spill contingency plans) 
to MMS for activities proposed during the bowhead whale migration 
period, the lessee shall consult with the directly affected 
subsistence communities, Barrow, Kaktovik, or Nuiqsut, the North 
Slope Borough (NSB),

[[Page 79281]]

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

    Because this stipulation was provided for in the lease sale notice 
and included in the lease agreements resulting from the lease sale, its 
requirements became binding for all leases issued as a result of that 
particular lease sale.
    The intent of this stipulation is for the operator to make a 
reasonable effort to establish a CAA with potentially affected whaling 
or subsistence hunting communities. It is the operator's responsibility 
to attempt to reach agreement on a CAA with those communities.

II. Section-by-Section Discussion of Proposed Changes

    This section provides explanations of and justifications for each 
of the specific regulatory changes proposed in this document. Since 
this is a joint BSEE and BOEM proposed rulemaking, this Section-by-
Section discussion is organized according to the order in which the 
relevant provisions would appear in the CFR. BSEE's and BOEM's 
regulations are found in the CFR at Title 30--Mineral Resources, Volume 
2; BSEE's regulations are in Chapter II, and BOEM's regulations are in 
Chapter V.

A. Key Revisions Proposed by BSEE

Title 30, Chapter II, Subchapter B, Part 250
Subpart A--General
Definitions. (Sec.  250.105)
    BSEE proposes to revise the definition of Capping Stack by deleting 
the phrase ``including one that is pre-positioned'' from the 
definition. BSEE included this phrase as part of the 2016 Arctic 
Exploratory Drilling Rule in response to a suggestion that the 
definition in the 2015 Arctic Proposed Rule should be expanded to allow 
pre-positioned capping stacks to be used below subsea BOPs when deemed 
technically and operationally appropriate. Recognizing that the comment 
was helpful, BSEE agreed with the suggestion and added the phrase 
``including one that is pre-positioned'' to the capping stack 
definition (see 81 FR 46492). As a practical matter, pre-positioned 
capping stacks are similar to SSIDs. Accordingly, this modification in 
the 2016 final rule effectively allows the operator to install an SSID 
below a subsea BOP and would be in compliance with the capping stack 
requirement in the existing Sec.  250.471, What are the requirements 
for Arctic OCS source control and containment? Existing Sec.  
250.471(a)(1), specifically requires the operator, when drilling below 
or working below the surface casing, to have access to a capping stack 
that is positioned to ensure that it will be able to arrive at the well 
location within 24 hours after a loss of well control. Typically, an 
operator would comply with this requirement by having one or more 
support vessels capable of handling and deploying the capping stack 
down to the subsea wellhead, when needed. Installing an SSID below the 
subsea BOP allows the operator to comply with Sec.  250.471(a)(1) and 
forgo the need to provide support vessels and a capping stack on 
standby at the surface.
    However, BSEE is proposing to eliminate this language because a 
pre-positioned capping stack is a piece of equipment that, as 
previously mentioned, aligns closely with an SSID. The Bureau is 
currently proposing distinct SSID requirements under Sec.  250.472, 
What are the additional well control equipment or relief rig 
requirements for the Arctic OCS? This proposed revision would provide 
clarity concerning the capping stack requirements under Sec.  250.471, 
specifically that installation of an SSID under Sec.  250.472 does not 
constitute compliance with the capping stack requirements under Sec.  
250.471. For purposes of BSEE's proposed regulations, an SSID is not 
considered to be the same as, or to satisfy the requirement to have, a 
capping stack. The new SSID option that BSEE is proposing under Sec.  
250.472 does not, and is not intended to, replace any of the SCCE 
requirements in proposed Sec.  250.471(a), where BSEE's capping stack 
requirement is addressed.
When may the Regional Supervisor grant an SOO? (Sec.  250.175)
    BSEE proposes to revise Sec.  250.175 by adding a new paragraph 
(d), which would allow an operator to request an SOO under certain 
situations that may be present in the Arctic OCS. This proposed 
revision is consistent with OCSLA's requirement that the Secretary 
promulgate suspensions regulations that ``facilitate proper development 
of a lease . . . .'' \39\ The proposed regulation would list the 
factors upon which BSEE may rely when determining whether to grant an 
SOO and include when an operator:
---------------------------------------------------------------------------

    \39\ OCSLA sec. 5, as amended, codified at 43 U.S.C. 1334(a)(1).
---------------------------------------------------------------------------

    (1) Has conducted operations on the lease during the drilling 
season immediately preceding the period for which the operator is 
seeking a suspension;
    (2) is drilling from: A MODU, an artificial gravel island or a 
gravity-based structure, or an artificial ice island; and
    (3) is not able to safely continue its operations due to the 
presence of seasonal ice, temporary seasonal drilling restrictions in 
its approved oil spill response plan, or seasonal temperature changes 
(respectively, for each facility type).
    Currently, BOEM issues Alaska OCS leases with the maximum 10-year 
primary lease term allowed under OCSLA.\40\ However, operators may be 
precluded from properly developing leases because it is not possible to 
conduct leaseholding operations for significant portions of those 10-
year terms. Offshore drilling locations on the Arctic OCS are 
inaccessible for a significant portion of each year, due to seasonal 
changes that make operating conditions unsafe or otherwise preclude 
operations. Moreover, it is difficult to predict precisely when sea ice 
will persist or break-up.
---------------------------------------------------------------------------

    \40\ OCSLA sec. 8, as amended, states in part: ``An oil and gas 
lease issued pursuant [OCSLA] shall be for an initial period of (A) 
five years; or (B) not to exceed ten years where the Secretary finds 
that such longer period is necessary to encourage exploration and 
development in areas because of unusually deep water or other 
unusually adverse conditions . . . .'' 43 U.S.C. 1337(b).
---------------------------------------------------------------------------

    MODUs--For example, drilling operations performed from a MODU may 
occur only during the open-water drilling season (generally late June 
to early November), when sea ice is non-existent or minimal. This 
practical limitation, without considering other logistical problems 
unique to the Arctic OCS, could mean that during a consecutive 10-year 
period, a lease may be unavailable for operations for approximately 70 
percent of the time.
    Artificial Gravel Islands or Gravity-based Structures--Drilling 
from artificial gravel islands and gravity-based structures is 
prohibited during the spring/summer ice break-up and the fall/early 
winter freeze-up periods, because of the potential impact of weather 
and ice conditions on potential oil spill response and cleanup efforts. 
In particular, response and cleanup techniques for a large spill are 
not as effective when sea ice is broken and unconsolidated around the 
drilling location. By contrast, response and

[[Page 79282]]

cleanup efforts for a large oil spill from an artificial gravel island 
or a gravity-based structure could be executed effectively during the 
summer (i.e., in open-water conditions) using existing oil spill 
response technologies. During the winter (i.e., under solid ice 
conditions), the ice, and any snow on the ice, could provide an 
effective platform for oil spill response and cleanup efforts, and help 
absorb the spill and contain it to an area relatively close to the 
gravel island or gravity-based structure. Land-based equipment could 
then be used to collect and transport the oil-covered ice out of the 
location. For context, a gravity-based structure would include a 
concrete island drilling structure and a steel drilling caisson(s).
    Artificial Ice Islands--A similar issue would be encountered if 
drilling were to take place from a man-made ice island. In those cases, 
the drilling location would be accessible only during the winter season 
when temperatures are very low, and the area is completely covered by 
ice stable enough to safely support a drilling rig and associated 
equipment. As temperatures rise during the spring and summer seasons, 
the ice breaks or melts away, making the drilling location inaccessible 
until the next winter season.
    The new paragraph (d) of Sec.  250.175 would facilitate the proper 
development of a lease by addressing those seasonal conditions that 
limit leaseholding operations by providing an operator ready and able 
to complete its operations with the opportunity to obtain an SOO. If 
granted, this SOO would suspend the running of the lease term and 
effectively extend the term of the affected lease by a period 
equivalent to the period of such suspension. The SOO would allow a 
diligent operator to use the full 10 years in a 10-year lease term to 
explore for hydrocarbons, without the concern for a lease expiring 
because Arctic seasonal constraints prevented operations.
    BSEE would continue to require the operator to comply with the 
existing requirements for requesting a suspension under existing Sec.  
250.171, How do I request a suspension? For example, Sec.  250.171 
requires the operator to submit a reasonable schedule of work for 
resuming the suspended operations on the subject lease for which the 
operator requests the suspension. A schedule of work typically includes 
milestones describing what activities the operator will perform to 
resume operations and when those operations will be performed. If the 
operator submits a schedule of work that demonstrates a reasonable plan 
and schedule for resuming operations, BSEE will typically grant the SOO 
(assuming the other requirements are satisfied). BSEE will use the 
reasonable schedule of work as an established measuring stick by which 
the Bureau would assess the operator's diligence and progress toward 
prudent development. If the operator does not adhere to its approved 
work schedule, BSEE may terminate the SOO under existing regulations. 
Paragraph (e) of existing Sec.  250.170, How long does a suspension 
last? authorizes BSEE to terminate any suspension when the Regional 
Supervisor determines the circumstances that justified the suspension 
no longer exist. Because a reasonable schedule of work serves as a 
required foundation for BSEE's SOO approval, the operator's adherence 
to that schedule is necessary to maintain the SOO. This allows BSEE to 
ensure that the operator complies with the OCSLA Congressional 
declaration of purpose. Other regulations under Subpart A that would 
also apply to BSEE's implementation of proposed paragraph (d) of Sec.  
250.175 includes Sec.  250.170, How long does a suspension last? which 
allows BSEE to issue a suspension for up to five years and provides 
that the suspension automatically ends when the suspended operation 
commences.
    BSEE understands the requirement in OCSLA to supervise operations 
in a manner that assures due diligence in the exploration and 
development of each lease. Therefore, BSEE is contemplating the option 
of limiting the period for when the suspension would remain in effect; 
only during the period between one drilling season and the next when 
the operator is prevented from continuing its drilling or other 
leaseholding activities due to seasonal conditions. This option would 
still provide operators more time to effectively explore their leases 
without fear of an expiring lease. It could also provide BSEE with a 
better means of tracking an operator's diligence efforts. This option, 
however, could result in additional unnecessary burdens, since an 
operator would have to ``reapply'' for a new suspension if the operator 
is unable to return to the location during the next open-water season. 
BSEE is seeking comment on this regulatory option for the SOO or any 
other option that could avoid or minimize additional burden, but still 
assure diligent lease exploration and development.
    BSEE's proposed regulatory change would address concerns raised in 
the NPC reports, which suggested that the current approach toward 
administration of the 10-year primary lease term allowed under OCSLA 
``comes from other offshore areas in the U.S., where operators have 
access to the leases all year-round.'' (NPC 2015 Report at 31 and NPC 
2019 Report at 25). The NPC 2019 Report pointed out that a ``10-year 
lease in the U.S. Arctic equates to about 3 to 4 years of working time, 
compared with the equivalent 10 years working time in the Gulf of 
Mexico.'' (NPC 2019 Report at 25). While it is not possible for BOEM to 
award leases with more than the maximum ten-year primary lease term 
allowed under OCSLA, this proposed regulatory change would rely on the 
Secretary's statutorily delegated authority, which has, in turn, been 
delegated to BSEE, to administer suspensions to address, as 
appropriate, the effects of Arctic working conditions when they may 
limit the operator's ability to perform leaseholding activities.
Documents Incorporated by Reference. (Sec.  250.198)
    BSEE proposes to revise the existing relief rig and SSRW 
requirements in Sec.  250.472 by providing the operator with an option 
to either use an SSID or have access to a relief rig if the operator 
will conduct exploratory drilling operations from a MODU. As part of 
that proposed regulatory change, which is discussed in detail later 
below in the What are the relief rig or additional well control 
equipment or relief rig requirements for the Arctic OCS? (Sec.  
250.472) section-by-section discussion, BSEE proposes to require the 
SSID to include Remotely Operated Vehicle (ROV) intervention equipment 
that has the capabilities to function the SSID. Under proposed Sec.  
250.472(a)(3)(ii), BSEE would require the ROV to have panels that are 
compliant with API RP 17H, Remotely Operated Tools and Interfaces on 
Subsea Production Systems, Second Edition, June 2013; Errata, January 
2014, to ensure that the operator's ROV capabilities for the SSID 
follow BSEE's existing ROV panel requirements for BOP systems. In 
conjunction with proposed paragraph (a)(3)(ii) that would require the 
operator's ROV panels to be compliant with API RP 17H, BSEE proposes to 
add the citation for proposed Sec.  250.472(a)(3) to Sec.  
250.198(e)(73). Paragraph (e)(73) of Sec.  250.198 documents the 
locations in the regulations where API RP 17H is incorporated by 
reference as a regulatory requirement, which would include Sec.  
250.472(a)(3) under this proposed rule. Adding the citation for Sec.  
250.472(a)(3) to Sec.  250.198(e)(73) would clarify that API RP 17H is 
a regulatory requirement when complying with Sec.  250.472 and is 
subject to BSEE

[[Page 79283]]

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

Subpart C--Pollution Prevention and Control

Pollution prevention. (Sec.  250.300)
    BSEE proposes to revise paragraphs (b)(1) and (2) of Sec.  250.300 
by eliminating the existing language that states the Regional 
Supervisor may require the capture of all water-based mud, and 
associated cuttings, from operations after completion of the hole for 
the conductor casing to prevent its discharge into the marine 
environment. While this proposed rule would eliminate the language 
regarding the Regional Supervisor's discretionary authority to require 
the capture of water-based muds and cuttings, it would maintain the 
existing requirement in Sec.  250.300(b)(1) and (2) that operators 
capture all petroleum-based mud and associated cuttings while operating 
on the Arctic OCS.
    Existing Sec.  250.300(b)(1) and (2) state that the BSEE Regional 
Supervisor may exercise his or her discretionary authority to restrict 
discharges of water-based muds and associated cuttings from Arctic OCS 
exploratory drilling based on various factors, such as: Proximity of 
drilling operations to subsistence hunting and fishing locations; the 
extent to which discharged water-based mud or cuttings may cause marine 
mammals to alter their migratory patterns in a manner that impedes 
subsistence users' access to or use of those resources, or increases 
the risk of injury to subsistence users; or the extent to which 
discharged mud or cuttings may adversely affect marine mammals, fish, 
or their habitat. BSEE promulgated the existing provisions in response 
to concerns raised by Alaska Native Tribes during preparation of the 
2015 Arctic Proposed Rule. These concerns included how water-based muds 
or cuttings could adversely affect marine species (e.g., whales and 
fish) and their habitats and compromise the effectiveness of 
subsistence hunting activities.
    BSEE re-examined the language in paragraphs (b)(1) and (2) of this 
section in light of EPA's authority to address water-based muds and 
cuttings discharges. The Clean Water Act (CWA) (Section 301(a), 33 
U.S.C. 1311(a)) provides EPA with the authority to issue National 
Pollutant Discharge Elimination System (NPDES) general permits, which 
authorize certain discharges, including certain restricted discharges 
of water-based muds and cuttings, from oil and gas exploratory 
facilities on the OCS in the Beaufort Sea and the Chukchi Sea. Those 
general permits additionally prohibit the discharge of oil-based and 
non-aqueous based muds and cuttings. The EPA must issue an NPDES 
general permit before an operator may seek coverage under that general 
permit. Compliance with the CWA, including gaining coverage under an 
applicable NPDES general permit, is necessary before an operator may 
discharge pollutants from its exploratory drilling operations.
    Before issuing an NPDES permit, EPA must make specific 
determinations to ensure that issuance of a permit will not lead to 
unreasonable degradation of the marine environment. EPA's determination 
is guided by an Ocean Discharge Criteria Evaluation (ODCE). The ODCE 
requires the agency to consider multiple environmental factors, such as 
potential impacts on human health through direct and indirect pathways, 
and the importance of the receiving water area to the surrounding 
biological community. These factors take into consideration how 
discharges could impact subsistence activities, marine resources, and 
coastal areas. The most relevant NPDES permits issued for offshore oil 
and gas exploration activities conducted from a MODU on the Arctic OCS 
are two 2012 general permits that covered oil and gas exploration 
facilities conducting operations in Federal waters of the Beaufort Sea 
and the Chukchi Sea. The Beaufort Sea permit \41\ does not allow the 
discharge of water-based muds and cuttings during the fall bowhead 
whale hunt. However, the Chukchi Sea permit \42\ did not include a 
similar restriction. According to the ODCE for the Chukchi Sea permit, 
the restriction was not necessary because the migration of bowhead 
whales would be over before discharge-related activities would 
begin.\43\
---------------------------------------------------------------------------

    \41\ https://www.epa.gov/sites/production/files/2017-12/documents/r10-npdes-beaufort-oil-gas-gp-akg282100-final-permit-2012.pdf.
    \42\ https://www.epa.gov/sites/production/files/2017-12/documents/r10-npdes-chukchi-oil-gas-gp-akg288100-final-permit-2012.pdf.
    \43\ https://www.epa.gov/sites/production/files/2017-12/documents/r10-npdes-chukchi-oil-gas-gp-akg288100-odce-2012.pdf, pp. 
6-14 to 6-17.
---------------------------------------------------------------------------

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

[[Page 79284]]

muds to contain constituents that are toxic and harmful to the 
environment. Although water-based muds may not be a feasible option for 
all drilling operations, such as when drilling through hydrophobic 
geologic formations that could be damaged by water-based muds, its use 
is a more environmentally benign approach in comparison to the use of 
petroleum-based muds. However, BSEE's proposed revisions reflect the 
Bureau's understanding that the express statements regarding the 
Regional Supervisor's discretionary authority to require the capture of 
water-based muds and cuttings in existing Sec.  250.300(b)(1) and (2) 
are not necessary. In particular, the EPA already addresses the goals 
of protecting water quality through the NPDES program, protecting 
marine species and their habitats, as well as the effectiveness of 
subsistence hunting activities, through the exercise of that agency's 
authorities. Thus, BSEE does not expect the Regional Supervisor to need 
to exercise the discretionary authority under existing Sec.  
250.300(b)(1) and (2) in the foreseeable future.
    Furthermore, BSEE understands, and did so even while it was 
preparing the 2016 Arctic Exploratory Drilling rule, that the 
references to the BSEE Regional Supervisor's authority in existing 
paragraphs (b)(1) and (2) created some uncertainty for the regulated 
industry because it appeared to overlap with EPA's jurisdiction and, if 
implemented, might result in BSEE issuing duplicative or conflicting 
requirements. BSEE addressed this concern by explaining that the 
amendments were meant to clarify the Regional Supervisor's authority to 
impose operational measures that complement EPA's discharge limitations 
by considering potential impacts to specific components of the Arctic 
environment, such as subsistence activities, marine resources, and 
coastal areas (81 FR 46505). Given the policy in E.O. 13783 to review 
existing regulations that potentially burden the development or use of 
domestically produced energy resources and the general principles in 
Section 1 of E.O. 13563--Improving Regulation and Regulatory Review (76 
FR 3821)--to promote predictability and reduce uncertainty, BSEE 
believes it is appropriate to propose eliminating the water-based mud, 
and associated cuttings, provisions in Sec.  250.300(b)(1) and (2).
    This proposed regulatory change does not suggest any change in 
BSEE's recognition that it is responsible for ensuring that oil and gas 
exploration and production activities on the OCS are conducted in a 
safe and environmentally responsible manner pursuant to OCSLA. 
Therefore, the proposed rule would not alter the longstanding 
regulation at Sec.  250.300(b)(1), under which the District Manager (or 
Regional Supervisor) retains the ability to restrict the rate of 
drilling fluid discharges or prescribe alternative discharge methods 
where warranted. Pursuant to Sec.  250.300(b)(1), BSEE would be able to 
determine whether there is a need to require capture of water-based 
muds and cuttings on a case-by-case basis, if the EPA has not done so. 
In particular, the District Manager would consider and determine 
whether such a requirement would be appropriate for any facility. The 
District Manager would make this determination on a case-by-case basis, 
in conjunction with the EP and APD approval process. This process 
includes coordinating with BOEM, particularly at the EP stage, when 
BOEM conducts an environmental review to identify the direct, indirect, 
and cumulative environmental effects that may be expected as a result 
of implementing the EP. That environmental review also incorporates 
input about potential environmental effects that may be obtained 
through consultations and review by interested parties, Federal 
agencies (e.g., EPA), State or local agencies, Tribes, or the public. 
Nothing would change BSEE's position from the 2016 rule to communicate 
with other agencies responsible for oversight of discharges related to 
oil and gas exploration drilling in the Arctic. This communication will 
help ensure that conflicts do not arise (81 FR 46504). BSEE expects 
that such input from EPA would address whether that agency has issued 
or plans to issue a permit for the same exploratory drilling 
facilities, and whether that agency believes that capture of water-
based muds in a specific case is warranted. Through BSEE's longstanding 
authority under Sec.  250.300(b)(1), the District Manager could require 
an operator to restrict the rate of drilling fluid discharges or 
prescribe alternative discharge methods. Such a restriction on the 
discharge of water-based muds and cuttings might be appropriate if 
identified in the EP environmental review process.
    In addition to the proposed revisions just described, BSEE proposes 
a minor modification to the second sentence in existing paragraph 
(b)(2), which requires the operator to capture all cuttings from 
operations that ``utilize'' petroleum-based mud to prevent their 
discharge into the marine environment. BSEE proposes to replace the 
word ``utilize'' with ``use'' to improve the readability of the 
regulation.

Subpart D--Oil and Gas Drilling Operations

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

[[Page 79285]]

well design (including casing and cementing program) meet the design 
requirements in proposed Sec.  250.472(a), and the design is 
appropriate for the purpose for which it is intended under expected 
wellbore conditions. BSEE is proposing this new provision to be 
consistent with existing requirements under existing Sec.  250.420 
(a)(7)(i), which require the operator to include with the APD a 
certification signed by a registered professional engineer that the 
casing and cementing design is appropriate for the purpose for which it 
is intended under expected wellbore conditions.
What are the requirements for Arctic OCS source control and 
containment? (Sec.  250.471)
    Section 250.471(a) currently requires the operator to have access 
to the SCCE described in paragraphs (a)(1) through (3), which must be 
capable of stopping or capturing the flow of an out-of-control well if 
the operator will be using a MODU when drilling below or working below 
the surface casing. Paragraph (a)(1) specifically requires the capping 
stack to be positioned to ensure that it will be able to arrive at the 
well location within 24 hours after a loss of well control. Paragraphs 
(a)(2) and (3) require the cap and flow system and the containment dome 
to be positioned to ensure that they will be able to arrive at the well 
location within 7 days after a loss of well control.
    BSEE proposes to revise Sec.  250.471 by:
    (i) Adding a new provision at the end of paragraph (a) stating that 
``However, the Regional Supervisor will approve delaying access to your 
SCCE until your operations have reached the last casing point prior to 
penetrating a zone capable of flowing hydrocarbons in measurable 
quantities provided that you submit adequate documentation (such as, 
but not limited to, risk modeling data, off-set well data, analog data, 
seismic data), with your APD, demonstrating that you will not encounter 
any abnormally high-pressured zones or other geologic hazards. The 
Regional Supervisor will base the determination on any documentation 
you provide as well as any other available data and information.''
    (ii) modifying the language in paragraph (a) describing the 
performance standard that the SCCE must meet by replacing ``capable of 
stopping or capturing the flow of an out-of-control well'' with 
``capable of controlling or containing the flow from an out-of-control 
well when drilling below or working below the surface casing;'' and
    (iii) removing the phrase ``positioned to ensure that it will 
arrive at the well location within 7 days after a loss of well 
control'' from subparagraphs (a)(2) and (3), which apply to the cap and 
flow system and containment dome, respectively.
    The changes described in item (i) from the previous paragraph could 
allow the operator to adjust the point in time during operations when 
it must position its capping stack--from ``when drilling or working 
below the surface casing'' to ``when drilling or working below the last 
casing point prior to the zone capable of flowing hydrocarbons in 
measurable quantities''--if the operator is able to demonstrate that it 
will not encounter any abnormally high-pressured zones or other 
geological hazards before that casing point. However, unless otherwise 
approved by BSEE, the operator must have access to their SCCE as 
described in paragraph (a)(1) and proposed paragraphs (a)(2) and (3), 
when drilling or working below the surface casing. While BSEE does not 
propose changes to the capping stack provision in paragraph (a)(1), 
changes to paragraph (a) would have a practical effect on the existing 
capping stack requirements. Changes to the capping stack requirements 
are discussed in the next subsection, entitled, Revisions to the 
Capping Stack Requirements.
    BSEE's proposed modifications to the language in paragraph (a), 
describing the performance standard that the operator's SCCE must meet, 
is administrative in nature. BSEE proposes this change so that the 
language is consistent with the source ``control'' and ``containment'' 
description of this equipment, as well as the title of this section of 
the regulations (i.e., Sec.  250.471 What are the requirements for 
Arctic OCS source control and containment?). It would not change the 
performance standard that the operator's SCCE must meet.
    BSEE's proposed changes to remove the phrase ``positioned to ensure 
that it will arrive at the well location within 7 days after a loss of 
well control'' from paragraphs (a)(2) and (3) would still require the 
operator to ensure it has access to a cap and flow system or a 
containment dome. However, the operator would no longer be required to 
ensure the equipment is positioned to be able to arrive at the well 
location within 7 days after the loss of well control. The distinction 
between the positioning requirement and the requirement to have access 
to the equipment is that ``having access'' refers to ensuring the 
operator has identified the equipment that would meet the performance 
requirements in this section and in other existing BSEE regulations--
Sec.  250.462 (What are the source control, containment, and collocated 
equipment requirements?) and is able to deploy the equipment as 
directed by the Regional Supervisor. Details regarding BSEE's proposed 
revisions to Sec.  250.471(a)(2) and (3) are discussed in the 
subsection below, entitled, Revisions to the Cap and Flow System, and 
Containment Dome Requirements.
     Revisions to the Capping Stack Requirements
    BSEE's proposed revisions to paragraph (a) would provide an 
opportunity to the operator to adjust the point in time during 
operations when it must position its capping stack, so that it will be 
available to arrive at the well location within 24 hours after a loss 
of well control. If the operator is able to demonstrate to BSEE that 
the operations it plans to conduct below the surface casing would not 
encounter any abnormally high-pressured zones or other geologic hazards 
before reaching the last casing point prior to penetrating a zone 
capable of flowing hydrocarbons in measurable quantities, then BSEE 
would allow the operator delay its positioning of the capping stack 
until that point. A capping stack, as defined under the existing 
regulations at Sec.  250.105, is a mechanical device that can be 
installed on top of a subsea or surface well head or BOP to stop the 
uncontrolled flow of fluids into the environment. BSEE also proposes 
certain non-substantive language changes for clarity.
    The existing capping stack requirements in paragraphs (a) and 
(a)(1) are intended to ensure that a capping stack is readily available 
to stop or capture the flow of hydrocarbons in case of a loss of well 
control when drilling below or working below the surface casing. While 
BSEE does not propose to eliminate the requirement in paragraph (a)(1) 
to ensure that the capping stack will be able to arrive at the well 
location within 24 hours after a loss of well control, the existing 
requirement in paragraph (a) to ensure the equipment is accessible when 
drilling below the surface casing does not fully take into 
consideration the known geology of an area. The formations below the 
surface casing, based on the known geology of the area, may have 
minimal or no potential to flow hydrocarbons in measurable quantities 
during drilling operations. This obviates the need for ensuring capping 
stack availability during operations in those zones. Prior to 
submitting an APD, operators assess the formations they will 
potentially encounter during drilling operations,

[[Page 79286]]

including the potential for hydrocarbon flow. Operators base this 
assessment on existing G&G data that they include in the APD.
    In many cases, flowable hydrocarbons are not anticipated or 
encountered in measurable quantities until the target productive 
formation is reached. For example, a surface casing shoe setting depth 
for an Arctic OCS exploration well could be only 1,500 feet, but the 
hydrocarbon bearing formation may be thousands of feet below that 
point. The existing regulations require the operator to have access to 
an available capping stack when drilling or working below the surface 
casing, even though geologic and engineering risk analyses the operator 
must submit as part of their APD may show that there is little or no 
potential for hydrocarbons to escape the formation and flow into the 
well prior to reaching the targeted productive formation. In such 
circumstances, the operator could safely drill for thousands of feet 
below the surface casing, without any identifiable need for a capping 
stack. This proposed change would, when appropriate, eliminate an 
unnecessary burden for the operator to maintain a positioned capping 
stack while drilling into low risk, non-productive sections of the well 
below the surface casing.
    An extensive amount of geophysical data already exists for certain 
areas of both the Beaufort and Chukchi Sea Planning Areas, and there 
has been extensive drilling in certain areas of the Beaufort Sea 
Planning Area. In the known geologic conditions of the U.S. Arctic, 
operators have a good understanding of the locations of reservoirs that 
they will encounter, which can be relatively shallow and normally 
pressured above certain geologic depths. Therefore, it may not be 
necessary to have access to a capping stack when drilling through zones 
below the surface casing that do not have abnormally high formation 
pressures or contain other geological hazards, and do not have the 
potential to flow hydrocarbons in measurable quantities, as they are 
penetrated.
    However, because geologic conditions are not uniformly normally 
pressured throughout the Arctic OCS, BSEE is maintaining the existing 
requirement to have the capping stack positioned when drilling or 
working below the surface casing. At the same time, BSEE does not 
discount the possibility that future projects would not need to have 
SCCE (i.e., the capping stack) positioned until reaching the last 
casing point prior to penetrating a zone capable of flowing 
hydrocarbons.
    The criteria BSEE proposes to rely on--that the operator can 
demonstrate to BSEE that it will not encounter ``abnormally high-
pressured zones or other geologic hazards''--to determine whether to 
grant an exception accounts for those downhole risks that could lead to 
a blowout and may require the use of a capping stack. With respect to 
abnormally high-pressured zones, BSEE is concerned that there could be 
a case where a kick (an influx, or flow, of formation fluid from the 
high-pressured zone entering into the wellbore) is not controlled and 
could lead to a blowout. While there are means of mitigating the risk 
of a kick, (i.e., overbalanced drilling), the capping stack needs to be 
readily available if heavier weight drilling muds, the BOP, and SSID, 
if applicable, fail to control the well.
    There could be other geologic hazards, such as fractured or high 
permeability zones, that may also pose a risk, particularly if those 
zones contain hydrocarbons. It is possible that normally pressured 
zones may be highly permeable or contain fractures, in which lost 
circulation may occur. This could cause a dynamic effect where drilling 
mud flows into the permeable formation causing the circulating pressure 
to decrease below the zone's pore pressure resulting in formation 
fluids flowing into the well bore. This may lead to a loss of well 
control. The capping stack needs to be readily available if heavier 
weight drilling muds, the BOP, and SSID, if applicable, fail to control 
the well.
    However, if the operator is able to demonstrate that a highly 
permeable or fractured zone is predicted to only contain water, BSEE 
would consider allowing the operator to delay positioning of the 
capping stack. Under this scenario, the operator would be able to use 
the diverter system in conjunction with the BOP system to maintain 
safety and environmental protection because it would be unlikely for 
hydrocarbons to be released into the environment. The diverter system 
consists of a mechanical device similar to a BOP annular preventer. The 
diverter system is used to divert gases, fluids, and other materials 
flowing from the well, away from facilities and personnel. Also, an 
operator would pump fluid loss materials into the well to bridge the 
formation to reduce its permeability and allow drilling muds to isolate 
the formation from the well. To permanently address the incident, the 
operator could also install a liner or set a new casing point at the 
interval where that highly permeable or fractured zone is located. BSEE 
would like to know whether there are more appropriate criteria, other 
than ``abnormally high-pressured zones or other geologic hazards,'' 
that the Bureau should use to determine whether to allow the operator 
to delay positioning of the capping stack.
    BSEE's proposed regulatory language describing the types of 
documentation it would consider adequate to demonstrate that abnormally 
high-pressured zones or other geological hazards would not be 
encountered before reaching the last casing point prior to penetrating 
a zone capable of flowing hydrocarbons in measurable quantities--``such 
as, but not limited to, risk modeling data, off-set well data, analog 
data, seismic data''--is not meant to be an exhaustive list. BSEE would 
accept any other types of documentation the operator may provide that 
will help its demonstration. BSEE does not anticipate this submission 
requirement would lead to a significant information collection burden 
on the operator because it is normal practice for operators to gather 
these types of information to develop and design an offshore 
exploration drilling project on the OCS in the Arctic. BSEE is 
requesting comment on what other types of information could be used to 
demonstrate the absence of abnormally pressured zones or other geologic 
hazards, and how burden on the operator could change--increase or 
decrease--if BSEE were to require its submission.
    At the APD stage, BSEE would evaluate the operator's documentation 
along with other accompanying geologic and engineering information/
analyses that must be submitted as part of its APD. BSEE would also 
consider any other available G&G information, such as information 
gathered from prior drilling operations in the area (e.g., well log and 
pressure testing information), and any other applicable geophysical 
(e.g., seismic data) information. BSEE makes clear in its proposed 
regulatory language that the Regional Supervisor will base the 
determination on whether to allow the operator to delay positioning of 
the capping stack on the documentation that the operator submits, as 
well as any other available data and information.
    BSEE is also considering an alternative regulatory approach whereby 
the Bureau would instead revise existing paragraph (a) by replacing 
``surface casing'' with ``last casing point prior to penetrating a zone 
capable of flowing hydrocarbons in measurable quantities.'' This 
regulatory option would uniformly adjust the point in time during 
operations when the operator must have access to its capping stack, by 
requiring the operator to have

[[Page 79287]]

its capping stack positioned before drilling below or working below the 
last casing point prior to penetrating a zone capable of flowing 
hydrocarbons in measurable quantities.
    Under this regulatory option, BSEE would evaluate the geologic and 
engineering information/analysis that the operator must submit as part 
of its APD, while also taking into consideration any other available 
G&G information the Bureau may have (e.g., off-set well data, such as 
well logs and pressure testing information, or geophysical information, 
such as seismic data). Based on these different sources of information, 
BSEE would determine whether there may be a need for the operator to 
position the capping stack at a point in time during operations earlier 
than last casing point prior to penetrating a zone capable of flowing 
hydrocarbons in measurable quantities.
    There may be cases where the operator or BSEE may not have 
sufficient G&G or analogous well data during the permit review process 
on a proposed project to provide an adequate level of certainty 
regarding anticipated formations that may be encountered prior to 
reaching the targeted productive formation. Therefore, BSEE is also 
considering, as part of this regulatory option, a clarification that 
the Regional Supervisor may require the operator to have access to a 
capping stack in advance of drilling below or working below the last 
casing point prior to penetrating a zone capable of flowing 
hydrocarbons in measurable quantities if BSEE determines there is 
insufficient G&G or analogous well data.
    For example, there may be insufficient G&G or analogous well data 
in cases where there have been a limited number of wells drilled within 
proximity to the planned well. In most cases, G&G and analogous well 
data are gathered from multiple sources. However, the same sets and 
amounts of data and information may not be available for each area, 
well, or project. There is no single set of criteria for determining 
the sufficiency of G&G or analogous well data. The more data that are 
available from sources near to the proposed drilling location, the 
greater confidence BSEE will have in the G&G interpretations. BSEE 
wants to ensure the operator has the most accurate data to make 
determinations about where the zones capable of flowing hydrocarbons in 
measurable quantities are located.
    This alternative regulatory option would maintain the same level of 
safety and environmental protection in comparison to BSEE's proposed 
regulatory change. The decision on whether it is appropriate to delay 
positioning of the capping stack at a point in time when operations are 
taking place below the surface casing resides with BSEE. BSEE, 
ultimately, may decide not to allow the operator to delay positioning 
of the capping stack if the Bureau reasonably assesses that potential 
risks below the surface casing exist that may require immediate 
deployment of this device. However, the distinction under this 
regulatory option is that the operator would not need to specifically 
demonstrate that abnormally high-pressured zones or other geologic 
hazards would be encountered above last casing point prior to 
penetrating a zone capable of flowing hydrocarbons in measurable 
quantities. The presumption would be that all zones above the last 
casing point prior to penetrating a zone capable of flowing 
hydrocarbons are safe unless BSEE determines otherwise. In addition, 
under BSEE's proposed regulatory change, it would be clear that the 
Bureau may request additional information from the operator and would 
provide that BSEE may consider other available data and information.
    BSEE is specifically soliciting comments about the benefits or 
disadvantages of this regulatory option. BSEE is also soliciting 
comments about the need for the operator to verify on a case-by-case 
basis those zones incapable of flowing hydrocarbons in measurable 
quantities. Operators verify these zones by analyzing G&G data to 
evaluate the formations that are expected to be encountered during 
drilling operations and confirm that there are no hydrocarbons present. 
Operators must use available offset well data in conjunction with the 
G&G data. BSEE requests comment on other methods operators use to 
verify the hydrocarbon zones, or abnormally high-pressured zones or 
other geologic hazards (such as fractured or high permeability zones), 
they anticipate encountering for a proposed drilling project and how 
frequently the data would be lacking at the point of preparing 
information to submit as part of an APD.
     Revisions to the Cap and Flow System, and Containment Dome 
Requirements
    As described at the beginning of this section-by-section 
discussion, Sec.  250.471, BSEE is also proposing to revise paragraphs 
(a)(2) and (3) of existing Sec.  250.471, which refers to the timing of 
the arrival of a cap and flow system and containment dome, 
respectively, by removing the phrase ``positioned to ensure that it 
will arrive at the well location within 7 days after a loss of well 
control'' from each paragraph. This proposed change would remove the 
requirement to have a cap and flow system or a containment dome 
positioned to ensure the equipment will be available to arrive at the 
well location within 7 days after the loss of well control, while 
preserving the existing requirement to deploy those pieces of equipment 
as directed by BSEE.
    BSEE proposes to allow the operator to adjust the point in time 
during operations when it must position its capping stack under 
paragraph (a), from ``when drilling or working below the surface 
casing'' to ``when drilling below or working below last casing point 
prior to penetrating a zone capable of flowing hydrocarbons in 
measurable quantities'' if the operator is able to demonstrate that it 
will not encounter any abnormally high-pressured zones or other 
geologic hazards before that casing point. Only the 7-day arrival 
timing related to the ``flow'' part of the cap and flow system would be 
altered as a result of BSEE's proposed modification to paragraph (a)(2) 
of Sec.  250.471.\44\
---------------------------------------------------------------------------

    \44\ Existing Sec.  250.105 defines Cap and flow system and 
Capping stack.
---------------------------------------------------------------------------

    The changes proposed in paragraphs (a)(2) and (3) to remove the 
requirement for the cap and flow system and the containment dome to 
arrive at the well location within 7 days after a loss of well control 
would not change other existing requirements throughout Sec.  250.471 
for the operator to ensure:
    (i) Access to a containment dome and cap and flow system;
    (ii) that the cap and flow system is designed to capture at least 
the amount of hydrocarbons equivalent to the calculated WCD rate 
referenced in the operator's BOEM-approved EP;
    (iii) that the containment dome has the capacity to pump fluids 
without relying on buoyancy;
    (iv) that tests or exercises are conducted for the SCCE, as 
directed by the Regional Supervisor;
    (v) that records pertaining to the testing, inspection, 
maintenance, and use of the SCCE are maintained and made available to 
BSEE upon request;
    (vi) that all SCCE identified in Sec.  250.471 are transported to 
the well upon a loss of well control; and
    (vii) that SCCE is deployed as directed by the Regional Supervisor.
    BSEE proposes to remove the cap and flow system and containment 
dome 7-day arrival timing requirements based on the Bratslavsky and 
SolstenXP study. The Bratslavsky and SolstenXP study determined that 
the time periods when SCCE may be safely deployed throughout the Arctic 
OCS is limited based on typical Arctic conditions. In

[[Page 79288]]

the Chukchi Sea, this means that safe SCCE deployment could only occur 
between August and October in the historically active exploration area. 
Moving north from the historically active exploration area of the 
Chukchi Sea, the ability to safely deploy SCCE diminishes significantly 
(id. at 100). The study mentions there are more opportunities for safe 
deployment of SCCE in other portions of the Chukchi Sea (June through 
December). However, it is only in the southwestern extent of the 
Chukchi Sea Planning Area; outside of the historically active 
exploration area.
    In the Beaufort Sea, the study noted that sea ice concentrations 
tend to be greater year-round as compared to the Chukchi Sea (id. at 
75). Accordingly, safe SCCE deployment could occur from ice capable 
vessels between early August and October in the historically active 
exploration area of the Beaufort Sea (i.e., the southern portion of the 
Beaufort Sea Planning Area). However, moving north beyond the 
historically active exploration area, time windows for safe SCCE 
deployment decrease significantly (id. at 104).
    In the case of open water operations in both the Chukchi and 
Beaufort Seas, the study points out that sea state is an important 
limiting factor for safe SCCE deployment. Rough sea states--high waves 
and longer wave periods--can affect the safety and operating limits of 
SCCE deployment. The vessel carrying the SCCE can become very unstable 
in rough sea states and the heave action on the deck can therefore 
increase significantly beyond the vessel's tolerance levels for 
conducting operations, which may negatively affect the ability to 
safely deploy the SCCE. Rough sea states are most likely to occur when 
there is less sea ice coverage and larger open water areas to generate 
large waves, which is more of an issue in the Chukchi Sea, where there 
are larger open water areas throughout the open water season (id. at 
11).
    When operating in open water conditions, sea states generally 
dictate that safe SCCE deployment could occur only between late 
September and October in the historically active exploration area of 
the Chukchi Sea, and that window diminishes significantly moving north 
of the historically active exploration area. In the Beaufort Sea, where 
there is less open water throughout the operating season, sea states 
would generally permit safe deployment of SCCE between late-August and 
early-to mid[hyphen]October in the historically active exploration 
area. Beyond that, the probability for safe SCCE deployment decreases 
rapidly in the historically active exploration area and in the other 
areas of the Beaufort Sea. (id. at 98,102)
    Water depth is also an important factor to consider for the safe 
deployment of SCCE. Deployment is likely to be impaired in water depths 
shallower than 984 feet because the equipment would potentially be 
subject to a gas boil at the surface from a subsea blowing well (id. at 
143). A gas boil is a forceful release of hazardous gases which can 
present human[hyphen]health hazards to workers, fire hazards, and 
potential stability problems for support vessels and the vessel 
deploying the SCCE directly above the blowing well. Water depths in the 
majority of the Chukchi Sea and Beaufort Sea where exploration has 
historically occurred are relatively shallow--167 feet or less (Table 
1-1 and Table 1-2, id. at 7 to 9). As recently as April of 2020,\45\ 
there were active leases in the Arctic OCS where SCCE may be deployed. 
These leases were located in the Beaufort Sea in water depths less than 
approximately 170 feet deep. This water depth range limits the fleet of 
support vessels that can be used for the safe deployment of SCCE. A 
possible solution that could enable SCCE deployment in the presence of 
a gas boil is the use of offset[hyphen]deployment technology to 
remotely position SCCE over the blowing well in shallow water (id. at 
A-35).
---------------------------------------------------------------------------

    \45\ In April of 2020, the only leases with potential projects 
that would be subject to the Arctic OCS's SCCE requirements were 
relinquished. However, there are other active leases in the Beaufort 
Sea located nearer to the shore in shallow waters where exploration 
and development projects are being pursued (primarily through man-
made gravel islands).
---------------------------------------------------------------------------

    When BSEE proposed its original Arctic OCS SCCE requirements in 
2015, the Bureau explained that there is limited ability in the Arctic 
region to summon additional source control and containment resources. 
Accordingly, the Bureau required operators to plan for response 
redundancies and planning complexities not required elsewhere (80 FR 
9938). BSEE determined that the provisions finalized in 2016 provided 
for the necessary redundancy and sequencing of the responses, based on 
the time necessary to deploy, and therefore provided sufficient safety 
and environmental protection to allow for exploratory drilling on the 
Arctic OCS. At that time, BSEE believed that the technologies 
identified in its SCCE requirements represented the optimal approach to 
well control capabilities available for the Arctic OCS (81 FR 46520).
    Since publication of the 2016 rule, however, BSEE has sought to 
better understand the ability to safely deploy SCCE (and relief rigs) 
in Arctic OCS conditions, through a study it commissioned to 
Bratslavsky Consulting Engineers, Inc., and SolstenXP, Inc. According 
to the Bratslavsky and SolstenXP study, the time periods when SCCE may 
be safely deployed throughout the Arctic OCS is limited in comparison 
to relief-well drilling operations, based on typical Arctic conditions. 
BSEE did not have the benefit of having the Bratslavsky and SolstenXP 
study when finalizing the 2016 Arctic Exploratory Drilling Rule. BSEE's 
proposed changes to Sec.  250.471(a)(2) and (3) for the containment 
dome and cap and flow system responds to the information it has 
gathered from the study.
    In light of these findings, BSEE proposes the revisions under Sec.  
250.471 to the containment dome and cap and flow system deployment 
requirements in paragraphs (a)(2) and (3) because it is not reasonable 
to impose such universal, prescriptive requirements for equipment that 
may not be safely deployed (moved to the location, equipment put into 
place, and activated) and effectively used under certain Arctic OCS 
conditions. The deployment and arrival schedules of the cap and flow 
system and the containment dome will be directed by the BSEE Regional 
Supervisor on a case-by-case basis.
    However, as previously described, BSEE proposes only to adjust, 
rather than eliminate, the reference to the point in time during 
operations when the operator must have access to a capping stack that 
is positioned to be able to arrive at the well location within 24 hours 
after a loss of well control. The Bratslavsky and SolstenXP study shows 
that the time periods when SCCE (capping stack, containment dome, and 
cap and flow system) may safely be deployed and effectively used are 
limited. Metocean conditions (i.e., rough sea states and sea ice 
concentrations) prevalent in the Arctic OCS can exceed the operating 
limits of the vessels that transport and deploy the SCCE. In addition, 
SCCE deployment is likely impaired in water depths shallower that 984 
feet, where gas boils could form above a blowing well. Water depths in 
the majority of the Chukchi Sea and Beaufort Sea where exploration has 
historically occurred are relatively shallow--167 feet or less. 
However, BSEE's independent observation outside of the study is that 
the chances for successfully deploying a capping stack under Arctic OCS 
conditions is greater in comparison to the containment dome

[[Page 79289]]

and cap and flow system. More specifically, in comparison to the 
containment dome, the capping stack has proven to be a more effective 
technology when successfully deployed and has a different function 
compared to a containment dome. The capping stack latches on to a 
connector or pipe stub located on or in the well to achieve a pressure 
tight seal to capture or stop all fluids flowing out of the well. A 
containment dome, which removes oil and gas from the water column, will 
likely capture only a portion of the hydrocarbon flow due to the non-
sealing design. In addition, the use of a containment dome may be 
constrained by the drilling unit itself. Certain drilling rigs, such as 
jackups and submersible drilling vessels, are unlikely to provide 
adequate structural clearance for deployment of a containment dome 
without moving the rig off the drill site. (id. at 33). Furthermore, 
containment domes have limited field application to prove their 
capabilities while, in contrast, capping stacks have been field tested 
and successfully deployed in multiple practice drills (id. at 32 and 
34).\46\
---------------------------------------------------------------------------

    \46\ For example, the capping stack technology was used to shut-
in the Macondo well during the Deepwater Horizon incident.
---------------------------------------------------------------------------

    With respect to the cap and flow system, the flow portion of the 
system would require additional vessel support activities on the 
surface (e.g., support vessels for oil and gas processing, and 
hydrocarbon storage/transfer) to keep the system working in comparison 
to what would be needed to deploy a capping stack (e.g., a single 
vessel that would load the capping stack and deploy to the well when 
needed). The support activities and the vessel on which the flow system 
is loaded would be subject to the same challenging metocean conditions 
previously described, thus limiting their ability to be safely deployed 
throughout the Arctic drilling season. The capping stack would 
generally have a better opportunity for deployment because once the 
capping stack is lowered under the water and attached to the wellhead, 
weather becomes less of a factor.
    BSEE believes it is critical to ensure that operators have 
redundant protective measures in place, as there is no guarantee that a 
single measure could control or contain a worst-case discharge (see 81 
FR 46487). Because the chances of successfully deploying a capping 
stack under Arctic OCS conditions may be greater in comparison to the 
containment dome and cap and flow system, BSEE is revising, and not 
eliminating, the capping stack positioning requirement. BSEE invites 
comments on any technological upgrades or methods that exist for SCCE 
that would meet the objective of being a redundant system that could 
control or contain a WCD.
    Although BSEE is proposing to remove the requirement in existing 
paragraphs (a)(2) and (3) to ensure that the cap and flow system and 
containment dome will be available to arrive at the well location 
within 7 days after a loss of well control, BSEE would maintain the 
provisions under the same paragraphs that require that the operator 
identify and have access to a containment dome and cap and flow system 
capable of deployment as directed by BSEE. BSEE would also maintain the 
requirement under existing paragraph (g) to initiate transit of all 
SCCE identified under Sec.  250.471 upon a loss of well control. 
Collectively, the proposed revisions to paragraphs (a)(2), (a)(3), and 
existing paragraph (g) would mean that, in the event of a loss of well 
control, the containment dome and cap and flow system would be in 
transit while the capping stack is being deployed at the well location. 
In light of the distinct functions and capabilities of these various 
elements of SCCE under anticipated Arctic OCS exploratory drilling 
conditions, BSEE proposes to retain these requirements, as modified, to 
preserve the regulations' requirement for redundant protective 
measures, while acknowledging the capability of each SCCE component, as 
there is no guarantee that a single measure could control or contain a 
WCD.
    Finally, BSEE proposes to revise existing paragraph (b) by 
eliminating the requirement for the operator to conduct a stump test of 
a pre-positioned capping stack, if the operator elects to use one, 
prior to installation on each well. This proposed change would provide 
consistency with BSEE's proposed revision to the definition of a 
capping stack in Sec.  250.105 and the new SSID alternative BSEE is 
proposing under Sec.  250.472. BSEE's proposed SSID alternative 
includes specific testing procedures, which is discussed in detail 
later in this preamble. BSEE's prior references to ``pre-positioned 
capping stacks'' were intended to address a comment on the 2015 Arctic 
Exploratory Drilling Proposed Rule suggesting that the definition of a 
capping stack be expanded to allow pre-positioned capping stacks to be 
used below subsea BOPs when deemed technically and operationally 
appropriate.
What are the additional well control equipment or relief rig 
requirements for the Arctic OCS? (Sec.  250.472)
    Paragraph (b) of Sec.  250.472 currently requires the operator to 
have access to a relief rig (different from the primary drilling rig), 
when drilling or working below the surface casing. In addition, when 
drilling or working below the surface casing, paragraph (b) requires 
the operator to stage the relief rig so that it could arrive on site, 
drill a relief well, kill and permanently plug the out-of-control well, 
and abandon the relief well prior to expected seasonal ice encroachment 
at the drill site, and in no event later than 45 days after the loss of 
well control.
    BSEE proposes to revise the existing relief rig and SSRW 
requirements in Sec.  250.472 by:
    (i) Providing the operator with an option to either use an SSID or 
have access to a relief rig, if the operator will conduct exploratory 
drilling operations from a MODU;
    (ii) Establishing the requirements that the operator must satisfy 
if the operator elects to use an SSID to comply with Sec.  250.472;
    (iii) Establishing the requirements that the operator must satisfy 
if the operator elects to have access to a relief rig to comply with 
Sec.  250.472;
    (iv) Adding a new provision that would apply if the operator elects 
to have access to a relief rig, which states, ``However, the Regional 
Supervisor will approve delaying access to your relief rig until your 
operations have reached the last casing point prior to penetrating a 
zone capable of flowing hydrocarbons in measurable quantities provided 
that you submit adequate documentation (such as, but not limited to, 
risk modeling data, off-set well data, analog data, seismic data), with 
your APD, demonstrating that you will not encounter any abnormally 
high-pressured zones or other geological hazards. The Regional 
Supervisor will base the determination on any documentation you provide 
as well as any other available data and information.''; and
    (v) Eliminating the reference to expected seasonal ice encroachment 
at the drill site, which applies to relief rig operations.
    With respect to the structure of Sec.  250.472, proposed paragraph 
(a) would establish the requirements the operator must follow if the 
operator elects to use an SSID, and proposed paragraph (b) would 
establish the requirements the operator must follow if the operator 
elects to maintain access to a relief rig. BSEE would combine the

[[Page 79290]]

requirements in existing paragraphs (a) and (b) into a single 
paragraph--proposed paragraph (b)--for organizational purposes, since 
existing paragraphs (a) and (b) cover relief rigs. Proposed paragraph 
(b) would also include the relief rig-related revision described in 
item (iv) of the previous paragraph, which could allow the operator to 
adjust the point in time during operations when it must stage its 
relief rig--from ``when drilling or working below the surface casing'' 
to ``when drilling or working below the last casing point prior to the 
zone capable of flowing hydrocarbons in measurable quantities''--if the 
operator is able to demonstrate that it will not encounter any 
abnormally high-pressured zones or other geological hazards before that 
casing point. However, unless otherwise approved by BSEE, the operator 
must stage its relief rig in a location, such that the relief rig would 
be available to arrive on site, drill a relief well, kill and abandon 
the original well, and abandon the relief well no later than 45 days 
after the loss of well control, when drilling or working below the 
surface casing. Finally, proposed paragraph (b) would include the 
proposed relief rig-related revision to eliminate the reference to 
expected seasonal ice encroachment at the drill site, which could 
potentially extend the open-water drilling season for MODUs. The 
changes included in proposed paragraphs (a) and (b) are discussed in 
further detail below, respectively, under the two subheadings entitled, 
Proposed Paragraph (a)--Complying with Sec.  250.472 by Using an SSID 
and Proposed Paragraph (b)--Complying with Sec.  250.472 by Having 
Access to a Relief Rig.
    In addition, the general alternative compliance language in 
existing paragraph (c) would be eliminated because the proposed rule 
would provide the operator with the alternatives of either using an 
SSID or having access to a relief rig, and because Sec.  250.141, May I 
ever use alternate procedures or equipment?, already provides an option 
for an operator to seek approval to use alternate procedures or 
equipment, potentially including future technologies that have not yet 
been developed.
    When it promulgated the 2016 Arctic Exploratory Drilling Rule, BSEE 
understood that, based on past loss of well control events (including 
the Deepwater Horizon incident), it was important for the operator to 
be prepared to drill a relief well to permanently plug a well, in the 
event of a loss of well control. Arctic OCS exploratory drilling 
operations conducted from MODUs are complicated by the fact that these 
operations can take place only during a short period each year, when 
ice hazards can be physically managed and there is no continuous ice 
layer over the water. Outside of that window, ice encroachment 
complicates or prevents drilling, including drilling a relief well, and 
transit operations. Therefore, BSEE concluded in the proposed rule: Oil 
and Gas and Sulphur Operations on the OCS--Requirements for Exploratory 
Drilling on the Arctic OCS (February 24, 2015, 80 FR 9916) that, for 
Arctic OCS Conditions, it was necessary to establish a relief rig and 
SSRW requirements, whereby the rig would be positioned at a location 
that would enable it to transit to the well site, drill a relief well, 
kill and permanently plug the out-of-control well, plug the relief 
well, and demobilize from the site, prior to expected seasonal ice 
encroachment. (see 80 FR 9940).
    Prior to finalizing the 2016 Arctic Exploratory Drilling Rule, BSEE 
did not identify any alternative technologies that provided a 
comparable level of results to drilling a relief well and permanently 
killing an out-of-control well. Drilling a relief well prior to 
seasonal ice encroachment eliminates the risk of a prolonged 
uncontrolled flow of hydrocarbons under the ice, throughout the winter 
season. The SCCE intervention options in BSEE's existing regulations 
(capping stack, cap and flow system, and containment dome) are intended 
only to temporarily control a well and not to be left in place over an 
entire ice season. However, BSEE did provide an option through the 2016 
rule for the operator to request that BSEE approve ``alternative 
compliance measures to the relief rig requirement,'' as provided in the 
longstanding regulation at Sec.  250.141, May I ever use alternate 
procedures or equipment?
    Since the promulgation of the 2016 Arctic Exploratory Drilling 
Rule, BSEE has received and considered new information regarding the 
current relief rig and SSRW requirements in Sec.  250.472. BSEE used 
the following information when developing the proposed requirements of 
this section:
     Supplemental Assessment to the 2015 Report on Arctic 
Potential: Realizing the Promise of U.S. Arctic Oil and Gas Resources 
(NPC 2019 Report)
    In April 2018, the Secretary of Energy, in cooperation with DOI, 
requested that the NPC develop a supplemental assessment to the NPC 
2015 Report. In April 2019, the NPC issued a report entitled, 
``Supplemental Assessment to the 2015 Report on Arctic Potential: 
Realizing the Promise of U.S. Arctic Oil and Gas Resources.'' The 
supplemental assessment evaluated recent experiences with Arctic 
exploration and advancements in technology, and it provided findings 
and recommendations directed toward enhancing the Nation's regulatory 
environment to improve reliability, safety, efficiency, and 
environmental stewardship for Arctic oil and gas development. One of 
the key areas the Secretary of Energy requested that the NPC address 
was regulatory burdens related to development on the Arctic OCS. (NPC 
2019 Report at A-1)
    The NPC 2015 Report described various technologies employed by 
industry as preventative measures, to reduce the risk of a well control 
incident or to mitigate the impacts of an incident through response and 
recovery measures. It recommended further examination of source control 
and containment technologies, including capping stacks and SSIDs, 
noting that such alternatives ``. . . could prevent or significantly 
reduce the amount of spilled oil compared to a relief well, which could 
take a month or more to be effective.'' (NPC 2015 Report at 4-16).
    In July/August of 2007, BSEE's predecessor, MMS, published a paper 
entitled, ``Absence of fatalities in blowouts encouraging in MMS study 
of OCS incidents 1992-2006.'' You may download and view the paper at 
https://drillingcontractor.org/dcpi/dc-julyaug07/DC_July07_MMSBlowouts.pdf. The paper summarizes BSEE's assessment of 
statistical information about loss of well control events that occurred 
during drilling operations on the OCS from 1992 through 2006. The paper 
noted that although relief wells were initiated in 2 of the 39 blowouts 
that occurred during the study period, both wells were controlled by 
other means prior to completion of the relief well. According to the 
NPC 2015 report, ``[a] relief well under good weather conditions may 
take 30 to 90 days plus rig mobilization, whereas a capping stack could 
be installed significantly sooner, and a subsea shut-in device could be 
activated in minutes.'' (NPC 2015 Report at 8-17)
    The NPC 2019 Report noted that, when ExxonMobil drilled an 
exploratory well in the Russian waters of the Kara Sea, it used an SSID 
that was built and tested in Norway. According to the NPC 2019 Report, 
the SSID used in the Kara Sea used existing capping stack technology, 
including dual blind shear rams; an upgraded, redundant control system; 
and side inlets for intervention below the shear rams. (id. at C-10). 
At the same time, the NPC 2019 Report described the SSID as

[[Page 79291]]

similar to a second BOP that was designed to be left on the wellhead, 
instead of being removed with the drilling rig, if the rig moves off 
the well near the end of the drilling season. The SSID, which could be 
actuated remotely, and the casing design together were capable of safe 
full well shut-in, diminishing the risk related to a loss of well 
control event occurring in late season and continuing over the winter 
season. The NPC 2019 Report observed that this design approach could 
eliminate the need for an SSRW. (id. at C-28). Ultimately, the NPC 
recommended that the use of an SSID, in conjunction with capping 
stacks, be accepted in place of the existing requirement for SSRW 
capability. (id. at 2).
    The NPC 2019 Report also included additional data regarding the 
geologic characteristics of the formations targeted during exploratory 
drilling operations in the Chukchi Sea and Beaufort Sea. The NPC 2019 
Report provides an illustrative comparison of the geologic depths 
encountered in the Arctic OCS and the Gulf of Mexico OCS. (NPC 2019 
Report at 11). The shallower targeted geologic formations in the Arctic 
OCS make drilling less complex and lower risk. This is different from 
current water depths encountered by operators in the Gulf of Mexico. In 
the Arctic OCS, exploratory drilling operations conducted from MODUs 
have taken place in waters less than 200 feet. In the Gulf Mexico, 
drilling activities are continually taking place in waters deeper than 
9,000 feet.
    The Arctic OCS's distinct challenges are driven by the region's 
extreme environmental conditions, geographic remoteness, and a relative 
lack of fixed infrastructure and existing operations. In comparison to 
the Gulf of Mexico, the Arctic OCS lacks extensive operations and 
infrastructure from which resources could be drawn to respond to a well 
control incident. In addition, the open water season for drilling from 
a MODU is limited, allowing operators to perform drilling operations 
only during the summer and early fall. A late-season well-control event 
could challenge an operator's ability to perform well intervention 
operations prior to freeze up.
     Suitability of Source Control and Containment Equipment 
versus SSRW in the Alaska Outer Continental Shelf Region (Bratslavsky 
and SolstenXP, 2018)
    In addition to the NPC 2019 Report, BSEE received information about 
SSIDs through the Bratslavsky and SolstenXP study, discussed in the 
previous section in connection with the proposed changes to the current 
Arctic OCS source control and containment requirements in Sec.  
250.471. As previously mentioned, the Bratslavsky and SolstenXP study 
entailed a comprehensive review and gap analysis of U.S. and 
international regulations, standards, recommended practices (RP), 
specifications, technical reports, and common industry methods 
regarding the safe deployment of SCCE as compared to the effectiveness 
of drilling an SSRW in Arctic conditions. BSEE notes that the 
Bratslavsky and SolstenXP study refers to the SSID as a ``subsea 
intervention device'' and considers the device to be SCCE, which is 
used to mitigate the consequences of a well control event. However, 
consistent with the findings in the NPC 2019 Report that categorizes 
SSIDs as preventative measures (instead of a response and recovery 
measure), BSEE considers SSIDs to be a barrier intended to prevent or 
minimize the impacts of a well control event. (id. at 16).
    The Bratslavsky and SolstenXP study noted that an SSID was 
installed and field tested on a submersible drilling vessel (i.e., a 
steel drilling caisson) for a 2005/2006 drilling project in the 
Canadian Beaufort Sea. However, the system was not completed in time to 
meet the approval process timelines and shipping deadlines required for 
timely implementation of the unit. (Bratslavsky & SolstenXP at A-36). 
According to the study, the use of a preinstalled SSID could provide a 
faster and safer additional line of defense for a response to a blowout 
than an SSRW or deployment of a capping stack or containment dome, 
resulting in smaller discharges to the environment. The report also 
mentions that the ability to remotely function the SSID ensures that it 
can be used in instances where other types of SCCE cannot be deployed 
due to site hazards that make it unsafe or inaccessible. These 
instances may include: A blowout with pressurized fluids coming up 
solely through the wellbore (forming a gas boil on the surface), a rig 
catching fire or collapsing on top of the well, or an incident in an 
area where response operations are limited, such as in shallow waters 
(id. at 35). The report also stated that if the well is designed to 
accommodate a full shut-in of the last casing string interval, the SSID 
can temporarily cap and control a well and facilitate its plugging and 
abandonment. This finding is consistent with the information from the 
NPC 2019 Report discussed previously. In 2008, Chevron initiated a 
technology venture with its partners on an R&D project to develop an 
SSID that would advance the best BOP technologies available at the time 
and would meet or exceed Canada's SSRW Arctic offshore regulations. The 
SSID was known as the Alternative Well Kill System (AWKS), which had 
two shear rams that were capable of simultaneously shearing and sealing 
heavier wall, larger diameter tubulars, and casings than was possible 
at that time. According to the NPC 2015 Report, Chevron successfully 
completed its testing of the AWKS in 2014 and is ready for deployment. 
(NPC 2015 Report at 4-18).
    Although the Bratslavsky and SolstenXP study points out that SSIDs 
could provide a faster and safer response to a blowout than capping 
stacks or containment domes, BSEE does not conclude from this 
observation that SSIDs should also replace the SCCE requirements in 
existing and proposed Sec.  250.471. In the Arctic, it is critical for 
the operator to have redundant protective measures in place, as there 
is no guarantee that a single measure could control or contain a WCD. 
(see 81 FR 46487). In addition to these redundant protective measures, 
the SSID, well design, and BOPs serve as controls and barriers that 
prevent or minimize the likelihood of loss of well control.
    Other pertinent information from the Bratslavsky and SolstenXP 
study includes the statistical analysis of recent OCS drilling seasons 
in the Beaufort and Chukchi Seas. The analysis identified the metocean 
and operational conditions that would support the safe drilling of a 
relief well. The study noted that the hazards of sea ice to drilling 
vessels and associated support vessels are primarily determined by the 
concentration and thickness of the sea ice. A vessel's ice 
classification, which are determined by various marine classification 
societies, such as the American Bureau of Shipping (ABS) and Det Norske 
Veritas and Germanischer Lloyd (DNV GL), indicates the vessel's 
capabilities. As ice concentrations increase, a vessel's efficiency 
decreases. (Bratslavsky & SolstenXP at 23).
    The study notes that the currently available open water operating 
season in the Chukchi Sea ranges from approximately 60 to 90 days in 
the historically active exploration area. (id. at 143). However, the 
results of the study showed that there is a high probability (90 
percent) that drilling can be conducted safely in sea ice conditions in 
a majority of the historically active exploration area of the Chukchi 
Sea for 70 to 160 days if an ice class MODU and associated support 
vessels are used as part of the drilling

[[Page 79292]]

operation. (id. at 108 and 145). Moreover, the NPC 2019 Report notes 
that ``vessels and equipment that are positioned in the theater `just 
in case' they are needed to minimize environmental impact, can actually 
impede personnel safety and source control objectives, because they 
distract operations personnel, add congestion, and can impede surface 
access to the well location.'' (NPC 2019 Report at 19).
    In the Beaufort Sea, the available open water operating season is 
limited to approximately 50 to 60 days across the historically active 
exploration area. (id. at 143). The study's analysis showed there is a 
high probability (90 percent) that drilling can be conducted safely for 
70 days, from mid[hyphen]August through October, in a majority of the 
historically active exploration area of the Beaufort Sea. (id. at 146).
    In light of the information from the NPC reports and the 
Bratslavsky and SolstenXP study, and BSEE's consideration of that 
information, BSEE proposes to revise Sec.  250.472 in the following 
manner:
     Proposed Paragraph (a)--Complying with Sec.  250.472 by 
Using an SSID
    The use of an SSID is not a new concept and was discussed in the 
2016 Arctic Exploratory Drilling Rule.\47\ Through the 2016 rulemaking 
comment process, stakeholders informed the Bureau that use of an SSID 
could help significantly reduce the risk of a release of hydrocarbons 
if the BOP system fails. At that time, BSEE focused more on permanent 
remediation to resolve a WCD event in the Arctic. Nonetheless, the 
Bureau agreed that an operator could request to use an SSID as an 
alternate procedure or equipment to the relief rig (80 FR 9940). 
Stopping short of requiring the use of an SSID, BSEE, instead, stated 
in the 2016 rule that it would consider the use of an SSID as an 
alternate procedure or equipment, under appropriate circumstances, if 
proposed for use with a jack-up (when surface BOPs are used). At that 
time, BSEE determined that, in the case where subsea BOPs are used in 
conjunction with floating drilling units, SSIDs would only be 
marginally effective or redundant (81 FR 46531). Since the publication 
of the 2016 rule, BSEE has reevaluated the use of SSIDs and the overall 
improved technology for similar components (BOPs). In this proposed 
rule, BSEE would allow operators the option to use an SSID based on 
BSEE's assessment of improved SSID design and operating requirements, 
including the ability to shut in a well over the winter ice season with 
a well cap. Additionally, BSEE would make this revision to potentially 
minimize environmental damage due to a prolonged ongoing well control 
event. An SSID is not a permanent solution for well remediation. 
However, it can provide a significantly quicker response time to 
address a well control event compared to drilling a relief well.
---------------------------------------------------------------------------

    \47\ See, e.g., 80 FR 9940 (``[BSEE] requests comments on 
alternative compliance approaches and specifically requests data on 
the performance of SIDs, including operational issues (such as 
timeframes needed to activate such alternatives). In particular, 
BSEE requests comments on appropriate staging requirements for a 
relief rig assuming that an SID has been installed at the 
exploration well. Comments are also requested on the need for an 
operator to have an in- season relief well drilling capability if an 
SID is used at a location that is not subject to ice scouring.'')
---------------------------------------------------------------------------

    Consistent with the policy in E.O. 13783 to review existing 
regulations that potentially burden the development or use of 
domestically produced energy resources, BSEE re-considered the SSID 
more closely, in light of the SSID information from the NPC reports and 
the Bratzlavsky and SolstenXP study, to determine whether the device 
could address the issues the Bureau identified when promulgating the 
2016 rule.
    Drilling a relief well is a complex, time-consuming process. After 
setting up the drill rig and drilling begins, the process to intercept 
the original wellbore may take several weeks or more because the 
operator needs to drill deep enough at great precision to ensure 
interception of the original well. This delay increases the length of 
the time oil and other fluids within the original well could be flowing 
uncontrollably into the marine environment. There is no delay for 
operational use of an SSID compared to the process of using the relief 
rig or capping stack.
    In this proposed rule, BSEE developed its proposed SSID 
requirements based on existing BOP equipment/technology whose 
performance and reliability has been tested, proven in a manner that is 
repeatable and reproducible, and has improved since promulgation of the 
2016 rule. BSEE also proposes to require an SSID used in the Arctic OCS 
to operate independently from the BOP. This would be accomplished by 
requiring the SSID to have a redundant control system, independent from 
the BOP control system, and independent, dedicated subsea accumulators 
to operate the SSID. By having two independent, redundant components 
(i.e., the BOP and the SSID) as part of the well control system, the 
overall reliability and effectiveness of the entire system increases. 
The following paragraphs describe BSEE's proposed requirements 
associated with the SSID, including the SSID's redundant control system 
(i.e., under proposed Sec.  250.472(a)(2)(ii)) and subsea accumulators 
(i.e., under proposed Sec.  250.472(a)(2)(iii)).
    Although the NPC 2019 Report recommended that the use of an SSID 
and capping stacks replace the requirement for an SSRW capability, BSEE 
is not proposing to eliminate the relief rig and SSRW requirements. 
Rather, BSEE is proposing to maintain the relief rig and SSRW 
requirement as an option for the operator to meet the regulatory 
requirements of Sec.  250.472. BSEE has determined that its regulations 
should provide options and flexibility to the operator (i.e., an SSID 
or a relief rig) to fit its needs and plans to develop its Arctic OCS 
leases. There could be cases where the operator's drilling schedule may 
not align with the availability of an SSID. In such a case, the 
operator should have the option to elect to proceed by complying with 
the relief rig and SSRW requirements. If an operator does not complete 
its exploratory drilling operations during that open water operating 
season, the operator could come back during a subsequent open water 
operating season and use an SSID, if one has become available in time.
    There could also be cases where two or more operators may plan to 
perform exploratory drilling operations during the same open water 
season. In such a case, each operator's drilling rig could serve as the 
other's relief rig. Under the existing regulations, BSEE would consider 
this type of a scenario to be in compliance with the relief rig and 
SSRW requirements. BSEE would not change that interpretation as part of 
this rulemaking. In a scenario like this, none of the operators would 
need to install an SSID, so long as there is an agreement among the 
operators that their drilling rigs will serve as a relief rig, if 
necessary. While it is not possible to identify every conceivable 
scenario, BSEE recognizes there could be other scenarios that are 
reasonably possible. Thus, it is appropriate to provide regulatory 
flexibility in order to accommodate an operator's drilling program. 
BSEE also retains its regulatory authority to approve alternate 
procedures or equipment if the proposed procedures or equipment either 
meet or exceed the level of safety and environmental protection 
required.
    The term SSID is a broadly used industry term, and there is not a 
single, all-encompassing definition that establishes the scope and 
function of an SSID. In some cases, different terms are used to 
describe the device. For example, as stated earlier, the

[[Page 79293]]

Bratslavsky and SolstenXP study refers to the device as a ``subsea 
intervention device,'' while some in the industry also refer to the 
SSID as a ``mudline closure device.'' Irrespective of these synonymous 
titles, BSEE uses the term SSID to refer to a fit-for-purpose device 
that may be used for different types of situations, including for well 
intervention applications, and can be used in different locations, 
including outside of the Arctic. However, for the purposes of Arctic 
OCS exploratory drilling from a MODU, BSEE is proposing to define the 
minimum acceptable capabilities and functions of an SSID. BSEE notes 
that, outside of the Arctic OCS, operators are contemplating using 
SSIDs for future projects, and SSIDs have already been approved for use 
in other parts of the OCS. The NPC 2019 Report notes that the 
requirement to drill an SSRW to mitigate the risk of a late season well 
control event continuing over the winter season is ``outdated.'' The 
2019 report concludes that SSIDs and capping stacks are superior 
solutions that could stop the flow of oil and allow intervention 
through the original borehole before a relief well could be completed. 
(NPC 2109 Report at 19). The SSID requirements BSEE is proposing to 
establish in this proposed rule would not apply to projects outside of 
the Arctic OCS. The design requirements for those SSIDs would be based 
on the needs of a particular project and may or may not be similar to 
what BSEE is proposing in this proposed rule. BSEE requests comments on 
these SSID requirements as outlined in the proposed rule.
    Under proposed paragraph (a) of Sec.  250.472, if the operator 
elects to satisfy the requirements of this section by using an SSID, 
BSEE would require the operator to ensure that the SSID and well design 
(including the casing and cementing program) are designed to achieve a 
full shut-in, without causing an underground blowout or having 
reservoir fluids broach to the seafloor.
    Currently, BSEE's regulations for SCCE under Sec.  250.462 do not 
require all wells to be designed to achieve a full shut-in (e.g., 
partial shut-in is acceptable) as there are methods to control the 
residual fluid flow into a surface production and storage system when a 
well is designed for partial shut-in. However, because BSEE is 
proposing that the SSID be designed to achieve full wellbore shut-in 
until kill operations are completed, it is important that the well 
design assures that the well will be able to withstand the associated 
loads for the entire time the SSID is closed (e.g., prevents gas 
migration in the shut-in wellbore). If the wellbore is compromised 
during or after a full shut-in, an underground blowout or broach to the 
seafloor may occur. BSEE reviewed available incident data on loss of 
well control events,\48\ and determined that, on average, five loss of 
well control events occurred each year on the OCS between 2007 and 
2017.
---------------------------------------------------------------------------

    \48\ See, BSEE's website at https://www.bsee.gov/stats-facts/offshore-incident-statistics.
---------------------------------------------------------------------------

    The well design language in proposed paragraph (a) would also 
require the operator to account for the stresses and loads placed on 
the well from the equipment that may be required to regain control 
after a loss of well control event. This includes the SSID, BOP stack, 
and capping stack. It is imperative that all well components are 
designed to withstand all potential loads and stresses placed on the 
well, including those that may be required during well control 
situations and deployment of SCCE (i.e., the well must be able to 
support a capping stack in addition to the other equipment required for 
normal operations).
    The need for the operator to account for all potential loads placed 
on the well also includes consideration of conditions where a well 
would be shut-in over the ice season. For example, in typical well 
control operations, a BOP is used to stop the uncontrolled flow and 
shut-in the well. It remains shut-in for a relatively short period of 
time while well kill operations are implemented and, if needed, 
materials and personnel are mobilized to the rig.
    For wells that may be shut-in for extended periods, the operator 
must consider the potential effects of gas expansion within the well. 
For example, in reservoirs containing gas, which is less dense than the 
liquids in the wellbore (e.g., drilling mud, completion fluid, brine), 
the gas will migrate upward in the wellbore until it reaches the closed 
BOP. This gas exerts a lower hydrostatic pressure than the column of 
oil or drilling fluids in the wellbore, and more of the reservoir 
pressure is transmitted to the top of the wellbore as a result. As the 
hydrostatic pressure acting on the bubbles decreases, the bubbles 
expand.
    As these bubbles continue to migrate and expand over time, the 
wellbore pressure profile increases. What was once a low pressure at 
the top of the well, with a hydrostatic pressure gradient below it, 
will eventually increase to reservoir pressure, increasing the downhole 
pressure. As the pressures in the wellbore increase, some of the liquid 
may bleed into the open formation(s). Eventually, the pressure may 
exceed the strength of the formation (fracture pressure) in the 
wellbore, potentially resulting in a fracture of the formation and an 
underground blowout. Because proposed paragraph (a) of Sec.  250.472 
contemplates allowing the operator to leave a well shut-in from one 
open-water season to the next (i.e., in the case of a late season well 
control event), wells need to be designed to withstand this potential 
loading condition.
    In a new paragraph (a)(1), BSEE proposes to establish performance-
based design requirements for the SSID. BSEE would require the operator 
to ensure that the SSID is designed to:
    (1) Close and seal the wellbore, independent of the BOP;
    (2) Perform under the maximum environmental and operational 
conditions anticipated to occur at the well;
    (3) Be left on the wellhead in the event the drilling rig is moved 
off location (e.g., due to storms, ice incursions, or emergency 
situations);
    (4) Preserve isolation through the winter season without relying on 
the elastomer elements of the rams (e.g., by using a well cap) and 
allow re-entry during the following open-water season; and
    (5) In the event of a loss of well control, preserve isolation 
until other methods of well intervention may be completed, including 
the need to drill a relief well.
    BSEE's analysis of loss of well control events data indicates that 
the most common methods employed to regain control of a well include 
pumping mud or cement into the uncontrolled well or activating 
mechanical well control equipment (e.g., blowout preventer).
    These SSID design requirements would help ensure the device is 
capable of shutting in and containing all fluids within the wellbore 
for an entire ice season (in the case of a loss of well control event 
too late in the open-water season to provide enough time for the 
operator to perform well kill or plug and abandonment operations). BSEE 
is basing the proposed design requirement for the SSID to be capable of 
preserving isolation through the winter season without relying on the 
elastomer elements of the rams (e.g., by using a well cap) on 
information it gained from the Kara Sea project. BSEE understands that 
the SSID used in the Kara Sea project was capable of preserving 
isolation over an entire ice season because it was designed to have a 
metal-to-metal cap installed on top of the SSID, after the BOP is 
detached and all equipment is moved off of the drill site. BSEE 
understands that isolation could

[[Page 79294]]

not be achieved over the ice season if the shut-in relied solely on the 
elastomer elements of the rams. The design requirements would also 
ensure the SSID will allow for re-entry to perform well recovery 
operations during the following open water season.
    In a new paragraph (a)(2), BSEE proposes to require that the 
operator's SSID include the following equipment:
    (1) Dual shear rams, including ram locks; one ram must be a blind 
shear ram;
    (2) A redundant control system, independent from the BOP control 
system, that includes ROV (remotely operated vehicle) capabilities and 
a control station on the rig;
    (3) Independent, dedicated subsea accumulators with the capacity to 
function all components of the SSID; and,
    (4) Two side inlets for intervention, one of which must be located 
below the lowest ram on the SSID.
    The dual shear ram requirement in proposed paragraph (a)(2)(i) 
would ensure that the SSID is capable of shearing through drill pipe, 
sealing the wellbore, and containing the fluids before they can escape 
during a loss of well control event. BSEE notes that the NPC 2019 
Report describes the SSID as having shearing/sealing rams. In fact, 
when describing the SSID used in the Kara Sea Project, the report 
explains that the device utilized dual blind shear rams. While proposed 
paragraph (a)(2)(i) would require only one of the rams to be a blind 
shear ram, BSEE is seeking comment on the advisability of requiring 
dual blind shear rams on the SSID. As described in the bow-tie diagram 
of the NPC 2019 Report, the SSID is the last line of prevention to 
minimize the impacts of an event. (NPC 2019 Report at 14).
    The redundant control system requirements in proposed paragraph 
(a)(2)(ii) would ensure there is reliability in the system and that the 
SSID will function when needed in an emergency situation. This proposed 
requirement is intended to align with the existing requirement in 
existing Sec.  250.734(a)(2), which requires subsea BOPs to have a 
redundant control system to ensure proper and independent operation of 
the BOP system. With respect to the requirement that an SSID have a 
separate control station on the rig that is independent from the BOP 
control system located on the rig, it is important for the SSID 
functions to be controlled by personnel directly involved in the 
drilling process to allow for an appropriate response from a 
``situationally aware'' individual. Therefore, while BSEE is proposing 
to require the SSID control system to remain independent of the BOP 
control system, it would not require those systems to be located in 
separate locations.
    BSEE is seeking comment on whether the proposed requirement in 
paragraph (a)(2)(ii) is appropriate for the SSID or whether there are 
additional ways to enhance the system's reliability. For example, BSEE 
is contemplating whether it may be more appropriate to require the 
SSID's redundant control system capabilities to be separate from the 
ROV's capabilities. BSEE is also considering, as part of the final 
rule, requiring the SSID control systems to be consistent with the 
fully redundant control system requirements described in American 
Petroleum Institute (API) Specification (Spec.) 16D (e.g., yellow pod 
and blue pod). More specifically, BSEE is further considering whether 
there should be an additional manual method (separate from the 
redundant control system) to close the SSID's rams with the ROV and 
whether it may be appropriate to require a standby or tending vessel 
with an ROV. These measures could address cases where the SSID's 
control system on the drilling rig is not available (e.g., due to 
failure or an evacuation of the rig).
    The requirement in proposed paragraph (a)(2)(iii) for SSIDs to have 
independent, dedicated subsea accumulators with capacity to function 
all components of the SSID would help ensure that, if the BOP system 
fails, the SSID will have the capabilities to function as needed, 
independent of the BOP's accumulator system. The requirement in 
proposed paragraph (a)(2)(iv) for SSIDs to have two side inlets, with 
one of the inlets located below the lowest ram on the SSID, would allow 
for re-entry through the SSID to perform well intervention operations. 
Side inlets allow the operator to pump fluids into the well to kill the 
well, before opening the blind shear ram to perform additional well 
intervention operations.
    In proposed paragraph (a)(3), BSEE would require the SSID to 
include ROV intervention equipment and capabilities to function the 
SSID. BSEE regulations currently include requirements for ROV 
intervention capabilities in relation to a BOP's functionality. BSEE is 
proposing similar requirements for the SSID because the SSID functions 
similarly to a BOP. Under proposed paragraph (a)(3), the ROV equipment 
and capabilities must:
    (1) Be able to close each shear ram under the Maximum Anticipated 
Surface Pressures (MASP), as defined for the operation;
    (2) Include an ROV panel that is compliant with API RP 17H (as 
incorporated by reference in Sec.  250.198);
    (3) Meet the ROV requirements in existing Sec.  250.734(a)(5); and,
    (4) Have the ability to function the SSID in any environment (e.g., 
when in a mudline cellar).
    The requirement in proposed paragraph (a)(3)(i) for the ROV to be 
able to close each shear ram under the operation's defined MASP would 
ensure that the operator is able to remotely close (through the ROV) 
each shear ram on the SSID and seal the well, which are the most 
critical functions during a well control event. The requirement in 
proposed paragraph Sec.  250.472 (a)(3)(ii) for the ROV to have panels 
that are compliant with API RP 17H would ensure that the operator's ROV 
capabilities for the SSID follow BSEE's existing ROV panel requirements 
for BOP systems. API RP 17H provides recommendations and overall 
guidance for the design and operation of ROV tooling used on offshore 
subsea systems (e.g., provision for high flow Type D hot stabs). This 
guidance is critical to ensuring safe and reliable ROV operations. In 
conjunction with the proposal in paragraph (a)(3)(ii) to require the 
operator's ROV panels to be compliant with API RP 17H, BSEE proposes to 
add the citation for proposed Sec.  250.472(a)(3) to Sec.  
250.198(e)(73). Section 250.198(e)(73) documents the locations in the 
regulations where API RP 17H is incorporated by reference as a 
regulatory requirement, which would include Sec.  250.472(a)(3) under 
this proposed rule. Adding the citation for Sec.  250.472(a)(3) to 
Sec.  250.198(e)(73) would clarify that API RP 17H is a regulatory 
requirement when complying with Sec.  250.472 and is subject to BSEE 
oversight and enforcement in the same manner as other regulatory 
requirements.
    The requirement in proposed paragraph (a)(3)(iii) for the operator 
to meet the requirements in existing Sec.  250.734(a)(5) would ensure 
that the operator has a trained ROV crew on each rig unit. The crew 
must ensure that the ROV is maintained and capable of carrying out the 
necessary tasks during emergency operations and be trained in operating 
the ROV, including stabbing into the ROV intervention panel on the 
SSID. The crew must also have the capability to communicate with 
designated rig personnel, who are knowledgeable about the SSID's 
capabilities.
    The requirement in proposed paragraph (a)(3)(iv) for the ROV to be 
capable of functioning the SSID in any

[[Page 79295]]

environment is meant to address those cases where it may be necessary 
to place the SSID in an enclosed or restricted environment. For 
example, if the SSID is used in an area with ice scouring or with deep 
ice keels, the SSID would be placed in a mudline cellar. If the ROV 
panels are attached to the SSID, the ROV may not be able to access the 
panels if there is not enough space in the cellar. The operator must 
ensure that the ROV has the capabilities to address these types of 
scenarios. BSEE is aware of current projects that are evaluating 
positioning the ROV panels away from the SSID. The ROV would function 
the SSID from the remote panel, which would be hardwired to the SSID. 
In addition, it is possible for a mudline cellar to be constructed via 
a dragline. In such a case, the mudline cellar could be constructed 
wide enough to provide adequate space for the ROV to access the panel 
if the panel was attached to the SSID. BSEE proposes to make the 
requirement in proposed paragraph (a)(3)(iv) flexible, recognizing that 
there are multiple ways an operator could address this type of concern.
    In general, however, BSEE is seeking comment on the feasibility of 
installing an SSID below a subsea BOP in cases where the SSID would 
also be installed in a mudline cellar. BSEE's current regulations at 
Sec. Sec.  250.734(a)(13) and 250.738(h) require placement of subsea 
BOP systems in mudline cellars when drilling occurs in areas subject to 
ice-scouring. In addition, proposed Sec.  250.720(c)(2) requires 
placement of the wellhead in a mudline cellar in areas subject to ice-
scouring. BSEE is requesting more information about whether there are 
any other operational or installation challenges that the operator may 
encounter when attempting to effectively operate the SSID in this 
environment. If so, what are those challenges, and how could they be 
addressed?
    BSEE understands that the SSID used in the Kara Sea could be 
manually activated using acoustic technologies. While such technologies 
are available to function the SSID from a remote location, BSEE is 
proposing to require use of an ROV, as described in proposed paragraph 
(a)(3). BSEE understands that ROVs are more reliable for this type of 
application. However, BSEE requests that commenters provide any 
information that demonstrates the reliability of acoustic (or other) 
technologies to actuate an SSID from a remote location.
    Furthermore, although BSEE is not proposing to require the SSID to 
have a self-actuating function, the Bureau is contemplating whether one 
may be necessary for certain emergency situations. BSEE is aware that 
in the Arctic OCS, it is possible for a drilling vessel to sink and 
allide with (i.e., strike against) the top of a wellhead during a loss 
of well control event (Bratslavsky and SolstenXP at 17). As discussed 
in the previous section, all exploratory drilling in the Beaufort Sea 
and the Chukchi Sea has taken place in waters less than 167 feet deep, 
and as recent as April 2020,\49\ there were active leases in the 
Beaufort Sea where an SSID could have been deployed. These leases were 
located in water depths less than approximately 170 feet deep. In these 
water depths, during an emergency, a vessel could sink before the BOP 
or SSID can be activated. A self-actuating system incorporated into the 
SSID could potentially address this problem.
---------------------------------------------------------------------------

    \49\ In April 2020, the only leases with potential projects that 
would be subject to the Arctic OCS's SSID or SSRW requirements were 
relinquished. However, there are other active leases in the Beaufort 
Sea located nearer to the shore in shallower waters where 
exploration and development projects are actively being pursued 
(primarily through man-made gravel islands).
---------------------------------------------------------------------------

    One option BSEE is considering is whether it may be appropriate to 
establish an autoshear and deadman system requirement for the SSID. The 
intent would be to address those emergency situations, such as when a 
sunken MODU allides with the wellhead, where the SSID could no longer 
be functioned via the ROV (due to lack of access) or a control station 
on the drill ship. BSEE's regulations already address autoshear and 
deadman systems for subsea BOPs. Existing Sec.  250.734(a)(6)(i) 
requires subsea BOPs to have an autoshear system that is designed to 
automatically shut-in the wellbore in the event of a disconnect of the 
lower marine riser package (LMRP). Also, existing Sec.  
250.734(a)(6)(ii) requires a deadman system, that is designed to 
automatically shut-in the wellbore in the event of a simultaneous 
absence of hydraulic supply and signal transmission capacity in the 
subsea control pods, respectively. However, BSEE did not propose this 
requirement for SSIDs in this rulemaking. The SSID is meant to be a 
backup to the BOP, and it is not necessary for the SSID to have the 
same automatic emergency functions as the BOP.
    There could potentially be negative consequences if both systems 
were to automatically function. For example, there could be a situation 
where the BOP's autoshear or deadman systems function, but they are not 
able to shut-in the well because a non-shearable drill string is 
positioned across the rams. If the subsea BOP rams are experiencing 
this issue, then the SSID may also encounter the same problem, 
depending on the part of the drill string that is across the rams at 
that time. In this scenario, it would be more appropriate to assess the 
situation to determine whether other well intervention operations could 
be performed to address the position of the drill string, before 
activating the SSID.
    Regardless of these challenges, BSEE is seeking comment on what 
fail-safe mechanism(s) may be appropriate to address cases where the 
BOP fails and the SSID is inaccessible by an ROV or a control station. 
If an autoshear system or a deadman system are appropriate fail-safe 
mechanisms to add to the SSID, BSEE is seeking input on what criteria 
should be used to function these systems, to ensure the system does not 
function at the wrong time or interferes with or impacts the BOP's 
autoshear and deadman systems.
    BSEE is also seeking comment on how to ensure that the SSID will be 
able to preserve isolation over the winter season in the event of a 
late-season emergency incident, such as a sunken drillship. As 
previously mentioned, BSEE understands that prior SSIDs have planned 
for long-term isolation through installation of a metal-to-metal cap 
(i.e., a well cap) on the SSID before leaving the device on the 
seafloor over the winter season. In the case of a late-season emergency 
situation that prevents access to the SSID to install a metal-to-metal 
cap, how would isolation be preserved through the winter season?
    In addition, BSEE is soliciting comment on whether the regulations 
should require use of an autoshear or deadman system in cases where 
these systems are not built into the BOP's system. As previously 
mentioned, BSEE's autoshear and deadman system requirements currently 
apply to subsea BOPs. There is no current requirement to use an 
autoshear or deadman system when surface BOPs are used. BSEE would 
expect that if an operator uses a surface BOP, the operator would still 
install the SSID on the seafloor. BSEE seeks comment on whether it 
would be appropriate in such a case to require use of an autoshear or 
deadman system on the SSID. If so, what criteria should BSEE apply to 
the functioning of the autoshear or deadman systems in an environment 
where a surface BOP is used? Furthermore, BSEE welcomes any other 
comments, unrelated to autoshear or deadman systems, regarding use of a 
surface BOP.
    With respect to installation of the SSID, BSEE proposes in 
paragraph (a)(4) to require operators to install the SSID:
    (1) Below the BOP;

[[Page 79296]]

    (2) At or before the time they install their BOP; and
    (3) In a way that will provide protection from deep ice keels in 
the event it must remain in place over the winter season (e.g., 
installed in a mudline cellar).
    Installing the SSID below the BOP would allow for quick detachment 
of the BOP and other equipment above the SSID, which would be critical 
when moving off of a location for emergency purposes. With respect to 
timing of the SSID's installation, the operator would be required to 
install the SSID at or before the time they install the BOP. The 
proposed requirement for the SSID to be installed in a way that will 
provide protection from deep ice keels would help ensure that the 
device is not damaged by ice in areas of ice scour. As previously 
discussed, this could be accomplished by placing the SSID in a mudline 
cellar. In complying with this proposed requirement, the operator must 
also consider situations where the drill site is not located in an ice 
scour area, but could experience ice floes with keels deep enough to 
clip and compromise the SSID if left on the seafloor over the winter 
season.
    In a new paragraph (a)(5), BSEE proposes to require the operator to 
test the SSID according to the BOP testing requirements in Sec.  
250.737, What are the BOP system testing requirements? The SSID's 
testing requirements should align with the BOP testing requirements 
since, as previously mentioned, the SSID functions similarly, and in 
addition, to a BOP. This testing would aid in predicting future 
performance of the SSID to ensure that the device will function when 
needed during an emergency situation. While BSEE proposes to align the 
SSID testing requirements with the Bureau's existing BOP testing 
requirements, BSEE welcomes input on whether there are more appropriate 
and reliable testing methods. For example, what testing procedures have 
been used in the past to test an SSID when it was deployed? For future 
operations, what testing procedures are being developed specifically 
for an SSID? What testing procedures should be applied to SSIDs, and 
why?
    Overall, BSEE intends for the SSID to provide time for the operator 
to marshal the equipment and materials necessary to permanently address 
a well control event, without the constraints of seasonal ice coverage, 
and to prevent the potential environmental impacts that could occur if 
an out of control well was allowed to flow over the season when the 
operator would not have access to the site due to ice. The SSID, along 
with the proper well design, would allow the well to be shut in over 
the ice season without requiring additional vessels and the situation 
addressed permanently in the following open water season. It would also 
allow the operator the time necessary to complete the intervention, 
without the well flowing, if unforeseen problems are encountered.
    Collectively, the SSID's design requirements; equipment 
specifications; ROV intervention capabilities; installation 
requirements; and testing requirements; together with the additional 
well design requirements, would help ensure that the device will 
function when needed during an emergency situation and will be capable 
of controlling the well over the ice season, if necessary, until the 
operator returns to perform well intervention operations during the 
following open-water season. In connection with that well intervention 
operation, BSEE may still exercise its existing authority to also 
require the operator to drill a relief well to permanently plug and 
abandon the out-of-control well, if needed. BSEE reviewed recent 
incident data from 2013 to 2017, which may be accessed on BSEE's 
website at https://www.bsee.gov/stats-facts/offshore-incident-statistics, to try to identify any past incidents involving the use of 
a BSEE directed relief well to remedy the loss of well control. Aside 
from the Macondo well incident in 2010, one incident in 2013 required 
the drilling of a relief well (see https://www.bsee.gov/newsroom/latest-news/statements-and-releases/press-releases/drilling-of-relief-well-begins-at-south). Other loss of well control events during that 
timeframe were successfully remedied with conventional well control 
methods. These incidents occurred in the Gulf of Mexico and were 
controlled by either circulating heavier weighted muds into the well or 
closing the BOP (or both), to control pressures within the well. BSEE 
would evaluate the individual circumstances associated with each case 
to make this determination. For these reasons, BSEE's proposed changes 
to Sec.  250.472 would maintain safety and environmental protection, 
though BSEE invites comment on the technical feasibility of such 
requirements.
    BSEE is seeking comment on whether the use of an SSID, particularly 
in a case where a subsea BOP is deployed, could present operational or 
installation challenges. For example, if the well is not located in an 
ice scour area and the BOP system, including the LMRP, and the SSID are 
placed on the seafloor, then these pieces of equipment could get as 
tall as 88 feet when installed (BOP approximately 70 feet + SSID 
approximately 18 feet). In addition, the bottom of a ship's hull, in 
the case where a drillship is used, may extend as much as 40 feet into 
the water from the sea surface. Historically, drilling in the Beaufort 
Sea and the Chukchi Sea has occurred in waters less than 167 feet deep. 
With as much as 128 feet of water column taken up by the BOP system, 
SSID, and ship's hull, very little space remains for operations between 
the bottom of the ship and the top of the well control system. BSEE 
seeks comment on what sorts of challenges operators have faced or would 
anticipate facing in the scenario just described. BSEE would also like 
to know how operators addressed those challenges in the past or could 
address them for future operations, taking into account the unique 
characteristics and extreme conditions of the Arctic OCS.
    BSEE is also generally seeking comment on its proposed changes to 
Sec.  250.472. For example, BSEE is seeking comments on how well design 
could be better addressed in this rulemaking to enhance overall safety 
of operations on the Arctic OCS. Is the well design requirement 
proposed in paragraph (a) adequate to address the situations that may 
be encountered if a well is shut-in with an SSID over a winter season? 
As previously described, there could be cases where the wellbore 
pressure profile may increase to reservoir pressures at the top of the 
well over the course of a winter season. What other scenarios should 
BSEE consider that could occur in the well over the ice season that 
could be addressed in proposed paragraph (a)?
     Proposed Paragraph (b)--Complying with Sec.  250.472 by 
Having Access to a Relief Rig
    As discussed earlier, BSEE proposes to combine existing paragraphs 
(a) and (b) into a single, new paragraph (b), Relief Rig, for 
organizational purposes because both existing paragraphs cover relief 
rigs. Combining existing paragraph (a) into proposed paragraph (b) 
would not be a substantive modification to BSEE's regulations because 
the specific requirements from existing paragraph (a) would remain 
unchanged. More specifically, the provision in existing paragraph (a) 
that requires the operator's relief rig to comply with all other 
requirements of 30 CFR part 250 that pertain to drill rig 
characteristics and capabilities, and requires the relief rig to be 
able to drill a relief well under anticipated Arctic OCS conditions, 
would be relocated to proposed paragraph (b)(1). The provision in 
existing paragraph (a) that provides that the Regional Supervisor

[[Page 79297]]

may direct the operator to drill a relief well in the event of a loss 
of well control would be relocated to proposed paragraph (b)(2).
    [cir] Last Casing Point Prior to Penetrating a Zone Capable of 
Flowing Hydrocarbons in Measurable Quantities
    Substantively, BSEE proposes to revise the requirements in existing 
paragraph (b) that prescribe the availability of the relief rig. BSEE 
would maintain the requirement for the operator to have access to a 
relief rig, different from its primary drilling rig, when drilling or 
working below the surface casing. However, BSEE proposes to add a new 
provision to the newly rearranged proposed paragraph (b) stating 
``However, the Regional Supervisor will approve delaying access to your 
relief rig until your operations have reached the last casing point 
prior to penetrating a zone capable of flowing hydrocarbons in 
measurable quantities, provided that you submit adequate documentation 
(such as, but not limited to, risk modeling data, off-set well data, 
analog data, seismic data), with your APD, demonstrating that you will 
not encounter any abnormally high-pressured zones or other geological 
hazards. The Regional Supervisor will base the determination on any 
documentation you provide as well as any other available data and 
information.''
    BSEE would also add new language at the beginning of existing 
paragraph (b) that says ``Relief Rig. If you choose to satisfy this 
requirement by having access to a relief rig, you must have access to 
your relief rig at all times when you are drilling below or working 
below the surface casing during Arctic OCS exploratory drilling 
operations.'' This language would simply clarify that if the operator 
chooses to use a relief rig to comply with proposed Sec.  250.472, it 
must have access to its relief rig at all times when drilling below or 
working below the surface casing. The changes described in this 
paragraph would be shown as a general requirement in proposed paragraph 
(b).
    BSEE's proposed revisions to paragraph (b) would potentially 
provide an opportunity for the operator to adjust the point in time 
during its operations when it must stage its relief rig. If the 
operator is able to demonstrate to BSEE that the operations it plans to 
conduct below the surface casing would not encounter any abnormally 
high-pressured or other geologic hazards before reaching the last 
casing point prior to penetrating a zone capable of flowing 
hydrocarbons in measurable quantities, then BSEE would allow the 
operator to delay staging of its relief rig until reaching that point.
    The changes BSEE is proposing would make proposed paragraph (b) of 
Sec.  250.472 and proposed paragraph (a) of Sec.  250.471 consistent, 
with respect to providing a potential opportunity to the operator to 
delay access to its SCCE (as described in Sec.  250.471(a)(1) and 
proposed Sec.  250.471(a)(2) and (3)) until its operations have reached 
the last casing point prior to penetrating a zone capable of flowing 
hydrocarbons in measurable quantities, so long as the operator submits 
adequate documentation, with its APD, demonstrating that it will not 
encounter any abnormally high-pressured zones or other geologic hazards 
before that casing point.
    The existing requirement in Sec.  250.472(b) pertaining to the 
availability of a relief rig does not take into consideration that the 
operator may demonstrate, based on geologic and engineering analyses, 
that there could be zones below the surface casing that are not 
hydrocarbon-bearing or that have minimal or no potential to flow 
hydrocarbons in measurable quantities during drilling operations. In 
many cases, operators do not anticipate or encounter flowable 
hydrocarbons in measurable quantities until the target productive 
formation is reached. For example, a surface casing shoe setting depth 
for an Arctic OCS exploration well could be only 1,500 feet deep, but 
the hydrocarbon bearing formation may be thousands of feet deeper below 
that point. The existing regulations require the operator to stage its 
relief rig when drilling or working below the surface casing, even 
though geologic and engineering risk analyses the operator must submit 
as part of their APD may indicate that there is little or no potential 
for hydrocarbons to escape the formation and flow into the well prior 
to reaching the targeted productive formation. In such circumstances, 
the operator could safely drill for thousands of feet below the surface 
casing without any identifiable need for a relief rig.
    This proposed change would, when appropriate, eliminate the need 
for the operator to stage its relief rig while drilling through low 
risk, non-productive sections of the well below the surface casing. 
Arctic regional pore pressure modeling conducted by BOEM for an area in 
the Beaufort Sea identifies a general uniformity following an average 
pressure gradient (i.e., normally pressured) up to approximately 7,500 
feet to 8,500 feet, subsea. The typical reservoirs targeted for 
exploration in the Arctic are usually located at less than 8,000 feet. 
In the GOM, there are many different geological features that can 
affect the pressure profiles and potentially create abnormal pressures 
(e.g., salt domes, and shallow water flow areas).
    An extensive amount of geophysical data already exists for certain 
areas of both the Beaufort and Chukchi Sea Planning Areas, and there 
has been extensive drilling in certain areas of the Beaufort Sea 
Planning Area. In the known geologic conditions of the U.S. Arctic, 
operators have a good understanding of the locations of reservoirs that 
they will encounter, which can be relatively shallow and normally 
pressured to certain depths. Therefore, it may not be necessary to have 
a relief rig immediately available when drilling through zones below 
the surface casing that do not have abnormally high formation pressures 
or contain other geological hazards, and do not have the potential to 
flow hydrocarbons in measurable quantities as they are penetrated.
    However, because geologic conditions are not uniformly normally 
pressured throughout the Arctic OCS, BSEE is maintaining the existing 
requirement to have the relief rig staged when drilling or working 
below the surface casing. At the same time, BSEE does not want to 
discount the possibility that future projects would not need to have 
the relief rig staged until reaching the last casing point prior to 
penetrating a zone capable of flowing hydrocarbons.
    The criteria BSEE proposes to rely on--that the operator can 
demonstrate to BSEE that it will not encounter ``abnormally high-
pressured zones or other geologic hazards''--to determine whether to 
grant an exception accounts for those downhole risks that could lead to 
a blowout and may require the use of a relief rig. With respect to 
abnormally high-pressured zones, BSEE is concerned that there could be 
a case where a kick (an influx, or flow, of formation fluid from the 
high-pressured zone entering into the wellbore) is not controlled and 
could lead to a blowout. While there are means of mitigating the risk 
of a kick, (i.e., overbalanced drilling), the relief rig needs to be 
readily available if heavier weight drilling muds, the BOP and SSID, if 
applicable, fail to control the well.
    There could be other geologic hazards, such as fractured or high 
permeability zones, that may also pose a risk, particularly if those 
zones contain hydrocarbons. It is possible that normally pressured 
zones may be highly permeable or contain fractures, in which lost 
circulation can occur. This could cause a dynamic effect where drilling 
mud flows into the permeable formation

[[Page 79298]]

and causing the circulating pressure to decrease below the zone's pore 
pressure resulting in formation fluids flowing into the well bore. This 
may lead to a loss of well control. The relief rig needs to be readily 
available if heavier weight drilling muds, the BOP, and the capping 
stack, fail to control the well.
    However, if the operator is able to demonstrate that a highly 
permeable or fractured zone is predicted to only contain water, BSEE 
would consider allowing the operator to delay the staging of its relief 
rig. Under this scenario, the operator would be able to use the 
diverter system in conjunction with the BOP system to maintain safety 
and environmental protection because it would be unlikely for 
hydrocarbons to be released into the environment. The diverter system 
consists of a mechanical device similar to a BOP annular preventer. The 
diverter system is used to divert gases, fluids, and other materials 
flowing from the well, away from facilities and personnel. Also, an 
operator would pump fluid loss materials into the well to bridge the 
formation to reduce its permeability and allow drilling muds to isolate 
the formation from the well. To permanently address the incident, the 
operator could also install a liner or set a new casing point at the 
interval where that highly permeable or fractured zone is located. As 
requested in the section-by-section discussion of Sec.  250.471, BSEE 
would like to know whether there are more appropriate criteria, other 
than ``abnormally high-pressured zones or other geologic hazards,'' the 
Bureau should use to determine whether to allow the operator to delay 
its staging of the relief rig.
    BSEE's proposed regulatory language describing the types of 
documentation it would consider adequate to demonstrate that abnormally 
high-pressured zones or other geologic hazards would not be encountered 
before reaching the last casing point prior to penetrating a zone 
capable of flowing hydrocarbons in measurable quantities-- ``such as, 
but not limited to, risk modeling data, off-set well data, analog data, 
seismic data''--is not meant to be an exhaustive list. BSEE would 
accept any other types of documentation the operator may provide that 
will help its demonstration. BSEE does not anticipate this submission 
requirement would lead to a significant information collection burden 
on the operator because it is normal practice for operators to gather 
these types of information in order to develop and design an offshore 
exploration drilling project in the Arctic OCS. BSEE is requesting 
comment on what other types of information could be used to demonstrate 
the absence of abnormally pressured zones or other geologic hazards, 
and how burden on the operator could change--increase or decrease--if 
BSEE were to require its submission.
    At the APD stage, BSEE would evaluate the operator's documentation 
along with other accompanying geologic and engineering information/
analyses that must be submitted as part of their APD. BSEE would also 
take into consideration any other available G&G information, such as 
information gathered from prior drilling operations in the area (e.g., 
well log and pressure testing information), and any other applicable 
geophysical information (e.g., seismic data). BSEE makes clear in its 
proposed regulatory language that the Regional Supervisor will base the 
determination for whether to allow the operator to delay staging of its 
relief rig on the documentation the operator submits as well as any 
other available data and information.
    BSEE is also considering an alternative regulatory approach whereby 
the Bureau would instead revise existing paragraph (b) by replacing 
``surface casing'' with ``last casing point prior to penetrating a zone 
capable of flowing hydrocarbons in measurable quantities.'' This option 
would adjust the point in time during operations when the operator must 
stage its relief rig. This alternative regulatory change would, 
instead, require the operator to stage its relief rig before drilling 
below or working below the last casing point prior to penetrating a 
zone capable of flowing hydrocarbons in measurable quantities.
    Under this regulatory option, BSEE would evaluate the geologic and 
engineering information/analysis the operator must submit as part of 
its APD, while also taking into consideration any other available G&G 
information the Bureau may have (e.g., off-set well data, such as well 
logs and pressure testing information, or geophysical information, such 
as seismic data). Based on these different sources of information, BSEE 
would determine whether there may be a need for the operator to 
position the capping stack at an interval earlier than last casing 
point prior to penetrating a zone capable of flowing hydrocarbons in 
measurable quantities.
    There may be cases where the operator or BSEE may not have 
sufficient G&G or analogous well data during the permit review process 
on a proposed project to provide an adequate level of certainty 
regarding anticipated formations that may be encountered prior to 
reaching the targeted productive formation. Therefore, BSEE is also 
contemplating, as part of this regulatory option, a clarification that 
the Regional Supervisor may require the operator to stage its relief 
rig prior to drilling below or working below the last casing point 
prior to penetrating a zone capable of flowing hydrocarbons in 
measurable quantities if BSEE determines there is insufficient G&G or 
analogous well data.
    For example, there may be insufficient G&G or analogous well data 
in cases where there have been a limited number of wells drilled within 
proximity to the planned well. In most cases, G&G and analogous well 
data are gathered from multiple sources. However, the same sets and 
amounts of data and information may not be available for each area, 
well, or project. There is no single set of criteria for determining 
the sufficiency of G&G or analogous well data. The more data that are 
available from sources near to the proposed drilling location, the 
greater confidence BSEE will have in the G&G interpretations. BSEE 
wants to ensure the operator has the most accurate data to make 
determinations about where the zones capable of flowing hydrocarbons in 
measurable quantities are located.
    This alternative regulatory option would maintain the same level of 
safety and environmental protection in comparison to BSEE's proposed 
regulatory change. The decision on whether it is appropriate to delay 
positioning of the capping stack below the surface casing resides with 
BSEE. BSEE, ultimately, may not allow the operator to delay staging of 
the relief rig if there are potential risks below the surface casing 
that may require immediate relief rig deployment. However, the 
distinction under this regulatory option is that the operator would not 
need to specifically demonstrate that abnormally high-pressured zones 
or other geologic hazards would be encountered above last casing point 
prior to penetrating a zone capable of flowing hydrocarbons in 
measurable quantities. BSEE would be responsible for making that 
determination.
    BSEE is specifically soliciting comments about its views of the 
benefits or disadvantages of this regulatory option and the need for 
the operator to verify on a case-by-case basis which zones are 
incapable of flowing hydrocarbons in measurable quantities.
    [cir] Expected Seasonal Ice Encroachment at the Drill Site
    In the 2015 proposed Arctic Exploratory Drilling Rule, BSEE 
determined that, because Arctic OCS exploratory drilling operations 
from a MODU take place only during the open water season (i.e., that 
period of time in

[[Page 79299]]

the summer and early fall when ice hazards can be physically managed 
and there is no continuous ice layer over the water), it was critical 
to ensure that drilling (including relief well drilling) and other 
operations affected by sea ice are concluded before ice encroachment. 
Ice encroachment may complicate or prevent drilling, transit, and oil 
spill response operations. However, the analysis from the Bratslavsky 
and SolstenXP study shows that the sea ice capabilities of an ice class 
MODU and its support vessels can extend the currently available open-
water operating seasons in the Chukchi and Beaufort Seas, depending on 
the drilling location within each planning area (id. at 143). 
Therefore, BSEE proposes to eliminate the reference to ``expected 
seasonal ice encroachment'' at the drill site in existing paragraph 
(b). BSEE, however, would retain the requirement clarifying that the 
relief rig must be different than the operator's primary drilling rig 
and that the relief rig must be staged in a location such that it can 
arrive on site, drill a relief well, kill and abandon the original 
well, and abandon the relief well no later than 45 days after the loss 
of well control. This proposed regulatory change would effectively 
extend the drilling season in those cases where the operator's MODU and 
associated support vessels are capable of safely operating beyond the 
period when seasonal sea ice begins to encroach at a drill site. The 
operator would no longer need to plan for their well operations to end 
in time to complete a relief well prior to the date when sea ice is 
expected to encroach on the drill site. The operator would, instead, 
have to plan to end its operations with sufficient time to complete its 
relief well prior to the anticipated date when sea ice conditions at 
the drill site are approaching the ice classification capability and 
rating limits of the operator's vessels.
    BSEE and BOEM would evaluate the ice classification capabilities 
and limitations of the operator's MODU and associated support vessels 
using existing permitting and review processes. For example, through 
BOEM's EP review process, the operator is required under existing Sec.  
550.220(c)(6) to specify when it anticipates completing onsite 
operations and when it anticipates terminating drilling operations. In 
addition, Sec.  550.220(c)(1) requires the operator to describe how it 
will design and conduct its exploratory drilling activities in a manner 
that accounts for Arctic OCS conditions. Furthermore, in the EP 
regulations at proposed Sec.  550.220(c)(1), BOEM would require the 
operator to submit a description of how all vessels and equipment will 
be designed, built, and/or modified to account for Arctic OCS 
conditions and how such activities will be managed and overseen as an 
integrated endeavor. This preamble discusses this proposed regulatory 
change in more detail later. Collectively, this information provided in 
an EP would allow BOEM (in conjunction with BSEE) to evaluate the 
capability of the operator's equipment, including its vessels and 
procedures to manage and mitigate risks associated with Arctic OCS 
conditions.
    At the APD stage, BSEE would also review the capabilities of the 
operator's MODU and associated supporting vessels. Existing paragraph 
(a)(2) of Sec.  250.470, What additional information must I submit with 
my APD for Arctic OCS exploratory drilling operations? requires the 
operator to describe how it plans to prepare its equipment, materials, 
and drilling unit for service in the environmental, meteorological, and 
oceanic conditions it expects to encounter at the well site and how its 
drilling unit will be in compliance with the requirements of existing 
Sec.  250.713, What must I provide if I plan to use a Mobile Offshore 
Drilling Unit (MODU) for well operations. Paragraph (d) of Sec.  
250.713 requires the operator, when using a MODU for well operations, 
to provide the current Certificate of Inspection (for U.S.-flag 
vessels) or Certificate of Compliance (for foreign-flag vessels) from 
the USCG, as well as a Certificate of Classification. The operator must 
also provide current documentation of any operational limitations 
imposed by an appropriate classification society. As discussed earlier 
in this section, the Bratslavsky and SolstenXP study notes that a 
vessel's capabilities are identified by the ice classification for the 
vessel, which is provided by marine classification societies such as 
ABS and DNV GL. BSEE would evaluate the information required under 
existing Sec. Sec.  250.470(a)(2) and 250.713(d), together with BOEM's 
approval of the operator's end-of-season date(s) in the EP, to verify 
whether the vessels' capabilities and limitations can support extending 
operations beyond when seasonal ice is expected to arrive at the drill 
site. However, in no case will BSEE approve a permit that proposes to 
use a vessel that does not meet the existing requirements of Sec.  
250.713, including providing a current certificate of inspection or 
compliance from the USCG.
    Finally, while BSEE is proposing these revisions to Sec.  250.472, 
BSEE is seeking comment on whether there are other appropriate 
approaches to well control operations in the Arctic, including 
alternative equipment/technology or performance standards. For example, 
although the NPC 2019 Report recommends accepting the use of an SSID in 
place of the requirement for SSRW capability, it also recommends 
replacing the relief rig and SSRW requirements with requirements that 
specify the desired outcome (i.e., to stop the flow of a well and allow 
the operator to propose equivalent technology and demonstrate its 
capabilities). (NPC 2019 Report at 30). BSEE assumes that the NPC 
recommends specifying a desired performance-based outcome in the 
regulations that would allow the operator to propose and demonstrate 
technologies capable of meeting that standard at the permitting stage, 
rather than prescribing a particular technology, such as a relief rig.

Subpart G--Well Operations and Equipment

When and how must I secure a well? (Sec.  250.720)
    BSEE proposes to delete the last sentence in existing paragraph 
(c)(2) that states ``BSEE may approve an equivalent means that will 
meet or exceed the level of safety and environmental protection 
provided by a mudline cellar if the operator can show that utilizing a 
mudline cellar would compromise the stability of the rig, impede access 
to the well head during a well control event, or otherwise create 
operational risks.'' In its place, BSEE proposes to insert a new 
sentence that states ``You may request, and the Regional Supervisor may 
approve, an alternate procedure or equipment in accordance with 
Sec. Sec.  250.141 and 250.408.'' BSEE, however, would preserve the 
basic requirement in in paragraph (c)(2) for the operator to use a 
mudline cellar or an equivalent means if there is indication of ice 
scour. The regulatory change BSEE is proposing in this section would 
make clear that BSEE could approve the equivalent means of doing so in 
accordance with Sec. Sec.  250.141, May I ever use alternate procedures 
or equipment? and 250.408, May I use alternate procedures or equipment 
during drilling operations?
    The new language that BSEE proposes to insert reiterates 
longstanding regulatory provisions contained in Sec. Sec.  250.141 and 
250.408 that describe what procedures the operator must follow and 
standards it must meet to receive BSEE's approval of a request to use 
alternate procedures or equipment to those required by regulation. 
Section

[[Page 79300]]

250.141 allows the BSEE District Manager or Regional Supervisor to 
approve the use of any alternate procedures or equipment that the 
operator may propose if the proposal provides a level of safety and 
environmental protection that equals or surpasses BSEE's current 
requirements. It also describes the types of information the operator 
must submit or present to BSEE when requesting to use alternate 
procedures or equipment. Section 250.408 requires the operator to 
identify and discuss their proposed alternate procedures or equipment 
in their APD.
    Since the issuance of the 2016 Arctic Exploratory Drilling Rule, 
BSEE learned that there is an industry misconception that the last 
sentence in existing paragraph (c)(2) means that the operator would be 
required to use a mudline cellar in all cases, except when the operator 
can prove that the mudline cellar would present an operational risk--
effectively narrowing the scope of Sec. Sec.  250.141 and 250.408 in 
this context. However, BSEE did not intend that language to constrain 
the contexts in which operators could seek approval of alternatives to 
the mudline cellar requirement. Rather, in response to commenters 
expressing concern that use of a mudline cellar may create operational 
risks in certain contexts, BSEE introduced that language to make clear 
that alternate approaches were available in those contexts, while at 
the same time highlighting the general flexibility available under 
Sec.  250.141, May I ever use alternate procedures or equipment? (see 
81 FR 46507 and 46510). The last sentence in existing paragraph (c)(2) 
was not intended to, and did not, restrict or preclude use of the 
longstanding options for seeking approval of alternate procedures or 
equipment under Sec. Sec.  250.141 and 250.408, which do not 
necessarily require a demonstration of operational risk. Thus, this 
proposed change would clarify that the operator has more flexibility to 
propose alternate solutions to the mudline cellar requirement under a 
broader range of circumstances than those described in the last 
sentence of existing Sec.  250.720(c)(2). An operator could still base 
such a request on the same grounds that BSEE described in the language 
that we propose to delete (i.e., that installation of a mudline cellar 
in a specific case would cause operational risks).

B. Key Revisions Proposed by BOEM

Title 30, Chapter V, Subchapter B, Part 550, Subpart B--Plans and 
Information Definitions. (Sec.  550.200)
    BOEM is proposing to eliminate the definition of the term 
``Integrated Operations Plan,'' consistent with the proposal to 
eliminate the requirement for the operator to submit an IOP for the 
reasons listed immediately below.
Removal of the IOP Requirement (Sec.  550.204)
    The 2016 Arctic Exploratory Drilling Rule discussed how commenters 
generally criticized the IOP provision as being duplicative or 
redundant of existing requirements (see 81 FR at 46492-46493). In 2016, 
when the rule was adopted, BOEM disagreed with these commenters and 
published responses to the commenters in the preamble. In its 
responses, BOEM discussed how the IOP was distinct from existing 
regulations, the importance of contractor management as it related to 
the IOP provisions, and the BOEM Regional Director's ability to waive 
submission of required information in the EP that was already provided 
in the IOP. Circumstances have changed since the IOP requirement was 
originally adopted. The various Federal agencies have improved their 
coordination to such an extent that BOEM believes there is no need for 
operators to create and submit a separate IOP for that purpose. Much of 
the required content of the two documents overlaps, and in the 2016 
rulemaking itself BOEM added requirements that the EP include 
additional information that made this overlap even greater. BOEM is now 
proposing to keep two important provisions from the IOP and incorporate 
them into the requirements for EPs. The first provision would reinforce 
BOEM's commitment to operational safety, while the second provision 
would require the operator to provide details of how its operations 
would conform to the unique circumstances of the Arctic OCS. Taken 
together, the enhancements to BOEM's regulations made in connection 
with the 2016 Arctic Exploratory Drilling Rule and the retention of 
these key provisions from the IOP make the IOP unnecessary and 
redundant.
    For these reasons, BOEM proposes to eliminate the requirement for 
preparing and submitting the IOP. In doing so, BOEM would delete all of 
Sec.  550.204, and remove corresponding references to the IOP from 
Sec. Sec.  550.200 and 550.206. Currently, BOEM requires the operator 
to submit an IOP at least 90 days before filing an EP with BOEM. The 
IOP is not subject to agency approval. BOEM developed the IOP 
requirement based on the Report to the Secretary of the Interior, 
Review of Shell's 2012 Alaska Offshore Oil and Gas Exploration Program, 
prepared by DOI (60-Day Report), March 2013,\50\ which included \51\ 
the following recommendation:
---------------------------------------------------------------------------

    \50\ Available at: https://www.doi.gov/sites/doi.gov/files/migrated/news/pressreleases/upload/Shell-report-3-8-13-Final.pdf.
    \51\ Report to the Secretary of the Interior, Review of Shell's 
2012 Alaska Offshore Oil and Gas Exploration Program, prepared by 
DOI (60-Day Report), March 2013, available at: https://www.doi.gov/sites/doi.gov/files/migrated/news/pressreleases/upload/Shell-report-3-8-13-Final.pdf.

    All phases of an offshore Arctic program--including 
preparations, drilling, maritime and emergency response operations--
must be integrated and subject to strong operator management and 
---------------------------------------------------------------------------
government oversight. (60-day report, p. 3).

The information provided in the IOP was intended to facilitate the 
prompt sharing of information among the relevant Federal agencies 
(e.g., BOEM, BSEE, USFWS, USCG, NMFS, U.S. Army Corps of Engineers, and 
EPA). Standing BOEM practice (LP-SOP-06 Standard Operating Procedure 
for Exploration Plans) in the Anchorage, Alaska OCS Office is to inform 
other agencies about an operator's EP, well in advance of the 
completeness review (i.e., the deemed submitted determination) for the 
EP. BOEM successfully did so prior to the 2016 implementation of the 
IOP requirement.
    The IOP requirement does not supersede or supplant the operator's 
obligation to comply with all other applicable Federal agency 
requirements. As described in the 2016 Arctic Exploratory Drilling 
Rule, the IOP process does not provide a mechanism for agencies to 
approve or disapprove the operator's proposed activities. BOEM has no 
authority under the IOP provision other than to make unenforceable 
suggestions to the operator. If BOEM or another agency determined that 
an operator was failing to engage in the needed integrated planning in 
advance of EP submission, BOEM could only compel an operator to do so 
through the EP review process.
    The 2016 Arctic Exploratory Drilling Rule added informational 
requirements for EPs to address key concerns that motivated the IOP, as 
shown in Table 1, ``Crosswalk between the IOP provisions proposed for 
removal and existing EP regulations and review practices.'' Because 
this information is required in the EP, operators should be aware that 
they must plan for how they will manage contractors to reduce

[[Page 79301]]

operational risks and address the challenges associated with operations 
on the Arctic OCS. The EP regulations are clear that the operator must 
plan to coordinate the work of a number of contractors to ensure that 
time pressure, or other contractor complications, do not undermine safe 
and environmentally responsible operations. In particular, proposed 
Sec.  550.220(c)(1) would require the operator to describe in the EP 
how it will design and conduct its exploratory drilling activities, and 
how it will manage and oversee these activities as an integrated 
endeavor. BOEM does not need, and nothing in OCSLA requires, an 
operator to inform Federal agencies about its planning on these issues 
in advance of an EP. The EP, however, will make evident whether the 
operator has done so, and if the EP does not address the operators' 
planning on all the required elements, BOEM will return the EP to the 
operator to include the requisite information in accordance with 
existing Sec.  550.231(b).
    As part of the 2016 Arctic Exploratory Drilling Rule, BOEM expanded 
the regulatory criteria for EPs to include information important for 
planning Arctic exploratory drilling. Specifically, BOEM expanded 
requirements for: Emergency plans at existing Sec.  550.220(a), the 
EP's suitability for Arctic OCS conditions at proposed Sec.  
550.220(c)(1), ice and weather management at existing Sec.  
550.220(c)(2), SCCE capabilities at existing Sec.  550.220(c)(3), 
deployment for a relief rig at proposed Sec.  550.220(c)(4), resource-
sharing at existing Sec.  550.220(c)(5), and anticipated end of 
seasonal operation dates at existing Sec.  550.220(c)(6).
    BOEM's EP and environmental impact analysis (EIA) requirements at 
existing Sec.  550.202, What criteria must the Exploration Plan (EP), 
Development and Production Plan (DPP), or Development Operations 
Coordination Document (DOCD) meet?, existing paragraphs (a) and (c) of 
Sec.  550.211, What must the EP include?, existing paragraph (c) of 
Sec.  550.216, What biological, physical, and socioeconomic information 
must accompany the EP?, existing paragraphs (a) and (b) of Sec.  
550.219, What oil and hazardous substance spills information must 
accompany the EP?, existing paragraphs (b), (c)(2) and (5) of Sec.  
550.220, If I propose activities in the Alaska OCS Region, what 
planning information must accompany the EP?, proposed paragraph (c)(1) 
of Sec.  550.220, existing paragraph (a) of Sec.  550.224, What 
information on support vessels, offshore vehicles, and aircraft you 
will use must accompany the EP?, and existing paragraph (b)(7) of Sec.  
550.227, What environmental impact analysis (EIA) information must 
accompany the EP? require the operator to address issues that the 
operator also needs to consider in preparing the IOP. The following 
table provides a detailed analysis of how the key operational 
provisions of the IOP are addressed in BOEM's existing regulations, and 
why the key safety provisions of the IOP will continue to be fully 
addressed by other provisions within BOEM's regulations:

 Table 1--Crosswalk Between the IOP Provisions Proposed for Removal and
              Existing EP Regulations and Review Practices
------------------------------------------------------------------------
                                          Coverage in BOEM's continuing
             IOP provision               regulations, operator EPs, and
                                                review practices
------------------------------------------------------------------------
Sec.   550.204(a)--The operator         Sec.   550.220 (c)(1)--The
 describes how vessels and equipment     operator describes how drilling
 were designed for Arctic OCS            activities account for Arctic
 conditions;                             OCS conditions.
Sec.   550.204(b)--The operator         Sec.   550.211(a)--The operator
 includes a schedule of the              includes a schedule and
 exploratory program;                    discussion of objectives for
                                         its exploration program.
Sec.   550.204(c)--The operator         Sec.   550.220 (c)(1)--The
 describes how its plans account for     operator describes how drilling
 Arctic OCS conditions;                  activities account for Arctic
                                         OCS conditions.
                                        Sec.   550.220(c)(2)--The
                                         operator describes weather and
                                         ice forecasting and management
                                         plans.
                                        Sec.   550.224(a)--The operator
                                         describes vessels and aircraft
                                         it would use during
                                         exploration, including storage
                                         capacity of fuels.
                                        Sec.   550.202--BOEM must review
                                         plans to ensure they are safe
                                         and do not cause undue or
                                         serious harm or damage to the
                                         human, marine, or coastal
                                         environment.
Sec.   550.204(d)--The operator         Sec.   550.211(a)--The operator
 describes general abandonment plans     includes a schedule and
 for wells;                              discussion of objectives for
                                         its exploration program.
                                        Sec.   550.220 (c)(1)--The
                                         operator describes how drilling
                                         activities account for Arctic
                                         OCS conditions.
                                        Sec.   550.220(c)(2)--The
                                         operator describes weather and
                                         ice forecasting and management
                                         plans.
                                        Sec.   550.220(c)(6)(ii)
                                         (proposed)--The operator would
                                         describe the termination of
                                         drilling operations consistent
                                         with the well control planning
                                         requirements under Sec.
                                         250.472 of this title.
Sec.   550.204(e)--The operator         Sec.   550.220(c)(2)--The
 describes its plans for responding      operator describes weather and
 and managing ice hazards and weather    ice forecasting and management
 events;                                 plans.
                                        Sec.   550.220(b)--The operator
                                         would describe critical
                                         operations and curtailment
                                         procedures.
Sec.   550.204(f)--The operator         Sec.   550.220 (c)(1)--The
 describes work to be performed by       operator describes how drilling
 contractors;                            activities account for Arctic
                                         OCS conditions.
                                        Sec.   550.220(c)(2)--The
                                         operator describes weather and
                                         ice forecasting and management
                                         plans.
                                        Sec.   550.202--BOEM must review
                                         plans to ensure they are safe
                                         and do not cause undue or
                                         serious harm or damage to the
                                         human, marine, or coastal
                                         environment.
Sec.   550.204(g)--The operator         Sec.   550.211(c)--The operator
 describes how it will ensure            would describe the drilling
 operational safety;                     unit, associated equipment,
                                         safety features, and storage of
                                         fuels and oils.
                                        Sec.   550.220 (c)(1)--The
                                         operator describes how drilling
                                         activities account for Arctic
                                         OCS conditions.

[[Page 79302]]

 
Sec.   550.204(h)--The operator         Sec.   550.219 (a) and Sec.
 describes oil spill response plans;     550.219 (b)--The operator would
                                         describe its oil spill response
                                         plan and associated spill
                                         modeling report.
Sec.   550.204(i)--The operator         Sec.   550.216 (c)--the operator
 describes efforts to minimize impacts   must analyze socioeconomic
 to local community infrastructure;      resources associated with its
                                         exploratory program.
                                        Sec.   550.227 (b)(7)--The
                                         operator must describe
                                         socioeconomic resources
                                         including employment and
                                         subsistence resources and
                                         harvest practices.
Sec.   550.204(j)--The operator         Sec.   550.220 (c)(5)--The
 describes how it could rely on local    operator describes agreements
 communities for parts of its            it has with third parties in
 exploratory drilling program.           the event of an oil spill or
                                         emergency.
                                        Sec.   550.219 (a) and Sec.
                                         550.219 (b)--The operator would
                                         describe its oil spill response
                                         plan and associated spill
                                         modeling report.
                                        Sec.   550.227 (b)(7)--The
                                         operator must describe
                                         socioeconomic resources
                                         including employment and
                                         subsistence resources and
                                         harvest practices.
------------------------------------------------------------------------

    The following information that was previously required as part of 
the IOP submission, but not included in the EP requirements, is 
proposed to be added to the relevant sections of the EP:

------------------------------------------------------------------------
       Existing regulation text                   New provision
------------------------------------------------------------------------
Sec.   550.204(a)--The operator         Sec.   550.220(c)(1)--The
 describes how vessels and equipment     operator describes how the
 were designed for Arctic OCS            exploratory drilling (including
 conditions;                             vessels and equipment) would
                                         account for Arctic OCS
                                         conditions, including any
                                         allowances or limitations its
                                         vessels have from a
                                         classification society and/or
                                         the USCG.
Sec.   550.204(g)--The operator         Sec.   550.211(b)--the operator
 describes how it will ensure            describes how it will ensure
 operational safety;                     operational safety.
------------------------------------------------------------------------

    To the extent that there is not an exact correlation between the 
information required in the IOP and that required in the EP, BOEM and 
BSEE believe that the additional information required in the IOP that 
is not in the EP is not necessary and certainly not necessary in 
advance of the EP.
    Furthermore, the BOEM Anchorage, Alaska OCS Office meets with 
members of the Interagency Working Group on Alaska Energy Permitting 
and other relevant agencies, before an EP is submitted or deemed 
submitted. Although BOEM previously argued that the IOP would not 
delay, but in fact, speed development by encouraging earlier review and 
coordination between regulatory agencies, BOEM no longer believes that 
is the case. While it is true that the IOP might speed up BOEM's review 
and approval of an EP, by encouraging earlier review and coordination 
among agencies, such acceleration would not shorten the overall 
planning process undertaken by the operator to prepare and submit an 
EP. The operator should conduct the same degree of planning with or 
without an IOP, because such planning is necessitated by the EP 
requirements. The IOP merely shifts some of the agency review to 
earlier in the process. With or without a prescriptive requirement for 
an IOP, the operator's thorough advance planning and coordination 
between BOEM, the operator, and other agencies prior to submission, 
will result in fewer unexpected issues overall. In practice, the entire 
planning process from initial concept to actual drilling should be the 
same, with or without an IOP. What is more important in terms of 
timeline, is the detailed work the operator would conduct in preparing 
and submitting a well-crafted EP.
How do I submit the EP, DPP, or DOCD? (Sec.  550.206)
    BOEM proposes to delete all references to the IOP in this section. 
The substantive provisions of this section that relate to EPs, DPPs, 
and DOCDs would remain unchanged.
What must the EP include? (Sec.  550.211)
    BOEM proposes to move existing Sec.  550.204(g) to Sec.  550.211 as 
a new paragraph (b). All other provisions of Sec.  550.211 would remain 
unchanged. The addition of the provision from Sec.  550.204 into Sec.  
550.211 is designed to describe operational safety procedures that the 
operator has developed specific to conditions relevant on the Arctic 
OCS. These requirements were previously included in the IOP and not 
specifically enumerated as part of the requirements for an EP, although 
similar, more general requirements are already part of paragraphs (a), 
Description, objectives, and schedule, and (c), Drilling unit of this 
section. Paragraph (c) requires the operator to describe the drilling 
unit, associated equipment, safety features, and storage of fuels and 
oils.
    Without the current IOP provisions, the applicant would already 
need to have the information required by this paragraph in order to 
comply with BSEE's regulations that currently require operators to 
develop, implement, and maintain a safety and environmental management 
system (SEMS) program (Subpart S, Sec. Sec.  250.1900 to 250.1933), and 
as a result, moving this requirement from Sec. Sec.  550.204 to 550.211 
does not add any burden.
    Retaining this important provision as part of the requirements for 
exploratory drilling on the Arctic OCS ensures consistency with the 
goals of this rulemaking and to better align BOEM's rules with those of 
BSEE. The following is a description of the provision that is being 
retained. The section describes how an operator will ensure operational 
safety while working in Arctic OCS conditions, including but not 
limited to:
    (1) The safety principles that it intends to apply to itself and 
its contractors;
    (2) The accountability structure within its organization for 
implementing such principles;

[[Page 79303]]

    (3) How it will communicate such principles to its employees and 
contractors; and
    (4) How it will determine successful implementation of such 
principles.
    The text of this transferred regulation provision is identical to 
what it was in Sec.  550.204(g). As such, this addition to Sec.  
550.211 will not impose any new burden on lessees or operators. BOEM 
believes that retaining this important safety and environmental 
protection is a necessary part of ensuring that energy exploration and 
development activity is safe and environmentally responsible.
If I propose activities in the Arctic OCS Region, what planning 
information must accompany the EP? (Sec.  550.220)
    BOEM proposes to revise paragraphs (c)(1) and (4), and (c)(6)(ii) 
of Sec.  550.220 to conform to BSEE's proposed changes to Sec.  
250.472, What are the additional well control equipment or relief rig 
requirements for the Arctic OCS?
    Existing paragraph (c)(1) of Sec.  550.220 would be revised to add 
text to account for the text in existing Sec.  550.204(a), which would 
be removed. With the elimination of Sec.  550.204, BOEM proposes to 
combine the requirements of these two sections into a revised Sec.  
550.220(c)(1) that would require the operator to describe how its 
exploratory drilling (including vessels and equipment) would account 
for Arctic OCS conditions, including any allowances or limitations its 
vessels have from a classification society and/or the USCG.
    BOEM is proposing to add a new informational requirement for 
modified vessels. BOEM is seeking to confirm that the operator meets 
the requirements of other entities with authority over vessels, not to 
impose requirements on those vessels. Although this revised paragraph 
would appear to add new requirements, in fact this revision would 
simply clarify and formalize the existing arrangements between BOEM and 
these other entities. This provision is proposed in order to avoid any 
potential confusion that might otherwise arise regarding the 
incorporation of the existing IOP requirements into the EP and how they 
may relate to the regulations and jurisdiction of the United States 
Coast Guard, or the flag state of the vessel. According to this 
proposed revision, for vessel modifications, the operator would 
describe any approvals from the flag state and vessel classification 
society and include in that description any allowances or limitations 
placed upon the vessel by the classification society and/or USCG. 
Vessel modifications may include the suitability of vessels for Arctic 
conditions. These vessels may have or acquire classification from a 
``recognized organization'' under the USCG's Alternative Compliance 
Program (ACP).\52\ This specification provides the operator with 
guidance on what information the EP should contain to show that its 
vessels would be able to operate safely in the Arctic OCS. The 
specification would also show that BOEM is not duplicating regulations 
from USCG by acknowledging that the flag state, USCG, and/or the 
classification society have authority for approvals, allowances, and 
limitations placed upon modified vessels. For these reasons, this 
change would impose no material additional burden on lessee or 
operators beyond that which already exists and which has already been 
accounted for in the information collection burden for this section.
---------------------------------------------------------------------------

    \52\ 33 U.S.C. 3316 and 46 CFR part 8 implement the USCG's ACP.
---------------------------------------------------------------------------

    To ensure consistency with BSEE's proposed regulatory changes, BOEM 
is proposing to revise paragraphs (c)(4) and (c)(6)(ii) by requiring 
the operator to provide a general description of how they will comply 
with Sec.  250.472, including a description of the termination of their 
operations. BSEE is proposing to revise Sec.  250.472 to provide the 
operator with the option to either use an SSID or have access to a 
relief rig, as an additional means to secure the well in the event of a 
loss of well control, if the operator will be conducting exploratory 
drilling operations from a MODU.

III. Additional Comments Solicited

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

[[Page 79304]]

preserving isolation through the winter season without solely relying 
on the elastomer elements of the rams (e.g., by using a well cap) and 
allow re-entry during the following open-water season. BSEE understands 
that the operator is able to achieve long-term isolation by installing 
a well cap (i.e., a metal-to-metal cap) on the SSID before leaving the 
device on the seafloor over the winter season. BSEE would like to know 
if there are means by which isolation would be preserved through the 
winter season in cases where a late-season emergency situation may not 
provide adequate time or ability to access the SSID to install a well 
cap.
    (v) SSID Dual Shear Requirement in Proposed Sec.  
250.472(a)(2)(i)--The NPC 2019 Report describes the SSID used in the 
Kara Sea Project as having dual blind shear rams. BSEE does not propose 
requiring the SSID to be equipped with dual blind shear rams. However, 
BSEE is seeking comment on the advantages or disadvantages between dual 
blind shear rams and using dual shear rams, with ram locks, with one 
ram being a blind shear ram.
    (vi) SSID Redundant Control System Capabilities (Sec.  
250.472(a)(2)(ii))--BSEE proposes to require the SSID to use a 
redundant control system that includes ROV capabilities and a control 
station on the rig that is independent from the BOP control system. 
BSEE is contemplating whether it may be more appropriate to require the 
SSID's redundant control system capabilities to be separate from its 
ROV's capabilities, and to be consistent with the fully redundant 
control system requirements described in API Spec. 16D, Specification 
for Control Systems for Drilling Well Control Equipment and Control 
Systems for Diverter Equipment, Second Edition, July 2004, reaffirmed 
August 2013; incorporated by reference at Sec.  250.198(e)(90); (e.g., 
yellow pod and blue pod). In addition to meeting the ROV requirements 
in existing Sec.  250.734(a)(5), BSEE is also considering whether there 
should be an additional manual method (separate from the redundant 
control system) to close the SSID's rams with the ROV and whether it 
may be appropriate to require a standby or tending vessel with an ROV. 
There could be cases where the SSID's control system on the drilling 
rig is not available (e.g., due to failure or an evacuation of the 
rig).
    (vii) SSID Testing Requirements (Sec.  250.472(a)(5))--BSEE is 
seeking comment on whether it is appropriate to align the SSID's 
proposed testing requirements with BSEE's existing BOP testing 
requirements in Sec.  250.737, What are the BOP system testing 
requirements?, or whether there are more appropriate and reliable 
testing methods for SSIDs. BSEE would like to receive information on 
what testing procedures have been used in the past to test an SSID when 
it was deployed, or what testing procedures are being developed for 
future projects.
    (viii) Relief Rig Staging and Capping Stack Positioning 
Requirements--BSEE proposes to revise the staging and positioning 
requirement for the relief rig and capping stack, respectively, by 
providing an opportunity to the operator to adjust the point in time 
during its operations when it must stage or position these pieces of 
equipment, from ``when drilling below or working below the surface 
casing'' to ``when drilling below or working below the last casing 
point prior to penetrating a zone capable of flowing hydrocarbons in 
measurable quantities.'' If the operator is able to demonstrate to BSEE 
that the operations it plans to conduct below the surface casing would 
not encounter any abnormally high-pressured or other geologic hazards 
before reaching the last casing point prior to penetrating a zone 
capable of flowing hydrocarbons in measurable quantities, then BSEE 
would allow the operator to delay staging of its relief rig or 
positioning of its SCCE until reaching that point. BSEE would like to 
know whether there are more appropriate criteria, other than 
``abnormally high-pressured zones or other geologic hazards,'' that 
should be used to determine whether to allow the operator to delay 
positioning of the capping stack and relief rig. BSEE is also 
requesting comment on what types of information, other than what is 
listed in proposed Sec.  250.471(a) and Sec.  250.472 (b)--risk 
modeling data, off-set well data, analog data, and seismic data, could 
be used to demonstrate the absence of abnormally pressured zones or 
other geologic hazards, and how burden on the operator could change--
increase or decrease--if BSEE were to require submission of that 
information in its APD.
    (ix) Alternative Regulatory Approach to the Relief Rig and Capping 
Stack Positioning Requirements--BSEE is considering an alternative 
regulatory approach in which BSEE would revise the staging and 
positioning requirement for the relief rig and capping stack, 
respectively, by adjusting the point in time during its operations when 
it must stage or position these pieces of equipment, from ``when 
drilling below or working below the surface casing'' to ``when drilling 
below or working below the last casing point prior to penetrating a 
zone capable of flowing hydrocarbons in measurable quantities.'' 
However, there could be cases where the operator or BSEE may not have 
sufficient G&G or analogous well data on a proposed project to 
confidently identify the location of the first formation that the 
operator may encounter that is capable of flowing hydrocarbons in 
measurable quantities. BSEE is soliciting the public's comments about 
this regulatory approach. BSEE is also soliciting comment about the 
need for the operator to verify, on a case-by-case basis, zones not 
capable of flowing hydrocarbons in measurable quantities.
    (x) Installing and Operating an SSID in a Mudline Cellar--BSEE is 
requesting more information about whether there are any operational or 
installation challenges the operator may encounter in attempting to 
operate the SSID when it is installed in a mudline cellar. In areas of 
ice scour, BSEE's current regulations at Sec. Sec.  250.734(a)(13) and 
250.738(h) require placement of subsea BOP systems in mudline cellars. 
In addition, proposed Sec.  250.720(c)(2) requires placement of the 
wellhead in a mudline cellar in areas of ice scour. Proposed Sec.  
250.472(a)(4)(i) would require installation of the SSID below the BOP.
    (xi) Operating an SSID with a Subsea BOP Installed on the 
Seafloor--Historically, drilling in the Beaufort Sea and the Chukchi 
Sea has occurred in waters less than 167 feet deep, and as recent as 
April 2020,\53\ there were active leases in the Beaufort Sea where an 
SSID could have been deployed. If the operator installs all well 
control systems on the seafloor (subsea BOP systems and SSIDs), there 
could be as much as 128 feet of water column taken up by these systems 
and a ship's hull (if a drillship is used). BSEE would like to know 
what challenges operators could face in cases where there is little 
room to operate. BSEE would also like to know how operators addressed 
those challenges in the past, or how such challenges could be addressed 
in future operations.
---------------------------------------------------------------------------

    \53\ In April of 2020, the only leases with potential projects 
that would be subject to the Arctic OCS's SSID requirements were 
relinquished. However, there are other active leases in the Beaufort 
Sea located nearer to shore in shallower waters where exploration 
and development projects are actively being pursued (primarily 
through man-made gravel islands).
---------------------------------------------------------------------------

    (xii) Fail-Safe Mechanisms Used on an SSID--BSEE is seeking comment 
on what fail-safe mechanisms exist that could be applied to an SSID in 
cases where a subsea BOP system is used. BSEE is contemplating whether 
it may be necessary to require mechanisms, such as autoshear or deadman 
for the SSID, to address emergency situations, such as a sunken MODU, 
where the

[[Page 79305]]

subsea BOP system may have failed and the SSID could no longer be 
functioned via the rig or ROV (due to lack of access). BSEE currently 
has fail-safe requirements for subsea BOP systems (autoshear and 
deadman systems), which could be applied to SSIDs. However, there could 
be unintended consequences from applying these fail-safe systems on an 
SSID when a subsea BOP system is used. BSEE is seeking comment on what 
fail-safe mechanisms could be deployed to address cases where the BOP 
fails and the SSID is inaccessible by an ROV or a MODU control station. 
If an autoshear system or a deadman system are appropriate fail-safe 
mechanisms, BSEE is seeking input on what criteria should be used to 
function these systems, to ensure they do not function at the wrong 
time or interfere with or impact the subsea BOP's autoshear and deadman 
systems.
    (xiii) Autoshear and Deadman System Requirements for Surface BOPs--
BSEE is contemplating establishing autoshear and deadman system 
requirements in cases where operators use a surface BOP. BSEE does not 
currently require the use of an autoshear or deadman system with 
surface BOPs. BSEE is seeking comment on what criteria should be 
established to function the autoshear or deadman systems in connection 
with a surface BOP. BSEE welcomes any other comments, unrelated to 
autoshear or deadman systems, which require additional consideration in 
those cases where a surface BOP is used.
    (xiv) Outcome-based Well Control System Requirements--BSEE is 
seeking comment on other appropriate approaches to well-control 
operations in the Arctic. The NPC 2019 Report recommends accepting the 
use of an SSID in place of the requirement for SSRW capability. 
However, it also recommends replacing the relief rig and SSRW 
requirements with requirements that specify desired outcomes (i.e., to 
stop the flow of a well and allow the operator to propose equivalent 
technology and demonstrate its capabilities). BSEE assumes that the NPC 
recommendation would entail a performance-based approach to the 
regulations, in which the operator could propose and demonstrate new 
technologies to meet a stated objective, rather than being required to 
use certain technologies, such as a relief rig.
    (xv) Suspension of Operations--BSEE is considering the option of 
limiting the period during which a suspension would remain in effect to 
the period between one drilling season and the next when the operator 
is prevented from continuing its drilling or other leaseholding 
activities due to seasonal conditions. BSEE is seeking comment on this 
regulatory option for the new SOO provision it is proposing in a new 
paragraph (d) of Sec.  250.175, or any other option that could avoid or 
minimize the additional burdens associated with making requests on an 
annual basis (if the duration of the suspension needs to be longer), 
but still assure diligent lease exploration and development.
    (xvi) Other Solicited Comments--BSEE is also requesting comments on 
the specific costs and operational implications of each of the 
regulatory changes included in this proposed rule.

IV. Procedural Matters

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

    Executive Order 12866 provides that the Office of Information and 
Regulatory Affairs (OIRA) within OMB will review all significant rules. 
This proposed action is an economically significant regulatory action 
that was submitted to OMB for review, as it would have an annual effect 
on the economy of $100 million or more. BSEE and BOEM developed an 
economic analysis to assess the anticipated costs and potential 
benefits of the proposed rule. Due to uncertainty surrounding the 
outcome of ongoing litigation regarding the availability of Arctic OCS 
planning areas for future leasing and energy development, BSEE and BOEM 
developed two baseline activity level forecasts: (1) Activity levels 
expected if the full Beaufort and Chukchi Sea planning areas are 
reopened (i.e., the Full Arctic baseline), and (2) reduced activity 
levels if these areas remain withdrawn from leasing (i.e., the 
Restricted Beaufort baseline). Under either scenario, the proposed 
action would be economically significant as a result of the estimated 
cost savings of this proposed rule. BSEE and BOEM estimate the 
amendments proposed in this rulemaking would provide annualized net 
benefits of $142 million under the Full Arctic baseline, or $121 
million under the Restricted Beaufort baseline, discounted at 7 
percent.
    Details on the estimated cost savings of this proposed rule can be 
found in the rule's Initial Regulatory Impact Analysis (IRIA). The net 
quantified benefits for this proposed rule are based on cost savings 
less forgone benefits. The cost savings to both government and industry 
result from removing regulatory redundancies, reduction in paperwork 
burdens, provision for alternative methods of compliance, and adoption 
of improved industry technology. Forgone benefits result from slight 
increases in the risks to subsistence hunters and fishermen and 
wildlife stemming from an increased probability of small or 
catastrophic oil spills. The cost savings exceed the forgone benefits, 
leading to the net benefits summarized in the following paragraphs.
    This proposed rule would revise regulatory provisions in 30 CFR 
part 250, subparts A, C, D, and G, and 30 CFR part 550, subpart B. BSEE 
and BOEM have reassessed a number of the provisions promulgated through 
the 2016 Arctic Exploratory Drilling Rule and are proposing to revise 
some provisions to reflect performance-based standards rather than 
prescriptive requirements. Other revisions remove redundant regulatory 
oversight provisions and provide regional flexibility in the 
administration of suspensions and associated lease term extensions, 
without significantly impacting the current levels of safety and 
environmental protection. The bureaus sought the best available data 
and information to analyze the economic impact of these changes. The 
IRIA for this rulemaking can be found in the https://www.regulations.gov/ docket (Docket ID: BSEE-2019-0008).
    BSEE and BOEM are proposing to revise certain regulations 
promulgated through the 2016 Arctic Exploratory Drilling Rule based on 
new information generated since the 2016 rule was finalized, and to 
support the goals of the Administration's regulatory reform 
initiatives, while ensuring safety and environmental protection. This 
proposed rule would revise certain existing regulations--Sec. Sec.  
250.105; 250.175; 250.198; 250.300(b); 250.470(b), (f), and (h); 
250.471(a) and (b); 250.472(a), (b), and (c); 250.720(c); 550.200; 
550.204; 550.206; 550.211; and 550.220(c). The bulk of the net benefits 
are derived from cost savings driven by a proposed revision to existing 
Sec.  250.472(b) and (c), which is discussed below. The analysis 
suggests forgone benefits are small compared to the cost savings, and 
the primary forgone benefits are from possible impacts on the 
environment and subsistence hunting and whaling communities, that could 
be caused by an oil spill of greater duration and higher discharge 
volumes in the event the BOP, SSID, and capping stack were to fail in 
sequence, and a containment dome and flow system would be needed to 
capture oil flowing from the well while relief-well drilling operations 
are underway. These, and the other provisions, are discussed in greater 
detail within the IRIA.

[[Page 79306]]

    The largest contributor to net benefits attributable to the 
proposed rule is the proposed revision to existing Sec.  250.472 
paragraphs (a), (b), and (c). As promulgated under the 2016 Arctic 
Exploratory Drilling Rule, this provision currently requires the use of 
a `relief rig' and adoption of a 45-day shoulder season. The relief rig 
is a secondary drilling vessel that is available and capable of 
drilling an SSRW in the event of a loss of well control. The 45-day 
``shoulder season'' was the maximum time permitted by the regulations 
to mobilize the relief rig to an incident, drill a relief well, kill 
and abandon the original well, and abandon the relief well prior to 
expected seasonal ice encroachment at the drill site. This shoulder 
season necessarily compresses the already short Arctic drilling 
timeframe and also limits the ability of operators to drill and 
complete a well in one season. The proposed revisions to Sec.  250.472 
would provide the operator with the option to either use an SSID or 
have access to a relief rig, as an additional means to secure the well 
in the event of a loss of well control, if the operator will be 
conducting exploratory drilling operations from a MODU. The two 
features of this flexibility driving the cost savings are the removal 
of the shoulder season and removal of the requirement for the secondary 
drilling vessel, if the operator elects to install an SSID to comply 
with Sec.  250.472. Because of the relative cost effectiveness of 
procuring, and potential well control advantages of installing an SSID 
versus mobilizing a relief rig and the necessary support vessels and 
personnel, BSEE assumes operators will prefer this option when using 
MODUs. This proposed change would produce an annualized cost savings of 
$142 million under the Full Arctic baseline, or $121 million under the 
Restricted Beaufort baseline, discounted at 7%.
    This proposed rule would reduce the burden imposed on industry, 
while maintaining safety and environmental protection. The forgone 
benefits of adopting the proposed rule include possible impacts on the 
environment, subsistence hunting and whaling communities, and an oil 
spill of greater duration with higher discharge volumes in the event a 
BOP and SSID were to fail. As discussed earlier in the preamble, BSEE 
proposes to require operators to operate an SSID independently from the 
BOP. By having two independent, redundant components (i.e., the BOP and 
the SSID) as part of the well control system, the overall reliability 
and effectiveness of the entire system increases. In the event both 
devices were to fail, the capping stack would still be used as required 
in the permitted timeframe. When a capping stack is used to contain a 
well, the relief well can be drilled without an ongoing active spill 
event. If the capping stack were to fail, the containment dome and flow 
system would be used to capture the oil flowing from the well while 
relief-well drilling operations are underway.
    Given that the proposed rule would remove the arrival timing 
requirement for these pieces of equipment, there may be a delay in 
their arrival, in comparison to the existing regulations. The amount of 
oil flowing from the well during that delayed period, would be the 
contributing factor to the proposed rule's forgone benefits. However, 
as discussed in the IRIA, the probability of a catastrophic spill event 
(as a result of the BOP and SSID systems experiencing total failures) 
is low. Coupled with a scenario in which a BOP, SSID, and capping stack 
were all to fail, the probability of realizing these forgone benefits 
may be even lower. Nonetheless, the possibility exists and if the BOP 
were to fail and the SSID were to function as designed, there would be 
no forgone benefits in comparison to the existing regulations (and 
there might be a gained benefit since the SSID would activate 
immediately).
    As part of the final rule, BSEE and BOEM are contemplating the 
preparation of a sensitivity analysis for the Final RIA and are 
soliciting comments on ways to make the analysis as accurate as 
possible. The information we receive through public input on this 
proposed rule regarding the SSID's performance, reliability, and 
effectiveness may inform the preparation of a sensitivity analysis.
    The timeframe of the present analysis is 24 years, composed of an 
initial 4 years with no activity followed by 20 years of activities 
beginning in 2024. The two tables below summarize BSEE's and BOEM's 
estimates of the total and annual net benefits derived from all 
proposed revisions and additions. Additional information on the time 
horizon, compliance costs, savings, benefits, and forgone benefits may 
be found in the IRIA published in the rule docket.

   20-Year Estimated Annualized Net Benefits Associated With Proposed
 Amendments to 30 CFR Part 250 Subparts A, C, D, and G, and 30 CFR Part
          550, Subpart B Under Full-Arctic Baseline Assumptions
------------------------------------------------------------------------
                                           Discounted to   Discounted to
            Year (2024-2043)                2019 at 3%      2019 at 7%
------------------------------------------------------------------------
Annualized (millions)...................          $149.8          $142.2
------------------------------------------------------------------------


   20-Year Estimated Annualized Net Benefits Associated With Proposed
 Amendments to 30 CFR Part 250 Subparts A, C, D, and G, and 30 CFR Part
      550, Subpart B Under Restricted Beaufort Baseline Assumptions
------------------------------------------------------------------------
                                           Discounted to   Discounted to
            Year (2024-2043)                2019 at 3%      2019 at 7%
------------------------------------------------------------------------
Annualized (millions)...................          $126.0          $120.9
------------------------------------------------------------------------

    This proposed rule would revise multiple provisions in the current 
regulations to implement performance-based provisions based upon 
reasonably obtainable information on safety, technical, economic, and 
other issues. Redundant or unnecessary reporting requirements are also 
being eliminated. BSEE and BOEM are providing industry flexibility, 
when practical, to meet the safety or equipment standards, rather than 
specifying the compliance method. Based on a consideration of the 
qualitative and quantitative safety and environmental factors related 
to the rule, BSEE and BOEM determined that the proposed revisions would 
be consistent with the policies of the applicable E.O.s and the OCSLA.
    Executive Order 13563 reaffirms the principles of E.O. 12866 while 
calling for improvements in the Nation's regulatory system to promote 
predictability, to reduce uncertainty,

[[Page 79307]]

and to use the best, most innovative, and least burdensome tools for 
achieving regulatory ends. The E.O. directs agencies to consider 
regulatory approaches that reduce burdens and maintain flexibility and 
freedom of choice for the public where these approaches are relevant, 
feasible, and consistent with regulatory objectives. E.O. 13563 
emphasizes that regulations must be based on the best available science 
and that the rulemaking process must allow for public participation and 
an open exchange of ideas. Furthermore, it promotes retrospective 
review of existing regulations that may be outmoded, ineffective, 
insufficient, or excessively burdensome. BSEE and BOEM have reviewed 
the existing regulations as amended by the 2016 Rule and have developed 
this proposed rule in a manner consistent with E.O. 13563.
    Executive Order 13771 requires Federal agencies to take proactive 
measures to reduce the costs associated with complying with Federal 
regulations. This proposed rule is an E.O. 13771 deregulatory action.

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

    The Regulatory Flexibility Act (RFA), 5 U.S.C. 601-612, requires 
agencies to analyze the economic impact of regulations when there is 
likely to be a significant economic impact on a substantial number of 
small entities and to consider regulatory alternatives that will 
achieve the agency's goals while minimizing the burden on small 
entities. The proposed rule would affect operators and Federal oil and 
gas lessees that could conduct exploratory drilling on the Arctic OCS. 
The RFA defines small entities as small businesses, small nonprofits, 
and small governmental jurisdictions. No small nonprofits or small 
governmental jurisdictions have been identified that would be impacted 
by this rule.
    Businesses subject to this proposed rule fall under North American 
Industry Classification System (NAICS) codes 211111 (Crude Petroleum 
and Natural Gas Extraction) and 213111 (Drilling Oil and Gas Wells). 
For these classifications, a small business is defined as one with 
fewer than 1,250 employees (NAICS code 211111) and fewer than 1,000 
employees (NAICS code 213111), respectively. A small entity is one that 
is ``independently owned and operated and which is not dominant in its 
field of operation.''
    According to BOEM's list of Arctic OCS leaseholders, four 
businesses currently hold lease interests on the Arctic OCS. This 
proposed rule would directly affect all four Arctic lessees. Based on 
the small entity criterion, none of the four businesses are considered 
a small entity. No small companies hold leases on the Arctic OCS. 
Previously, a single small company with only one lease held acreage on 
the Arctic OCS. This company relinquished its lease in March 2016.
    BSEE and BOEM prepared an Initial Regulatory Flexibility Analysis 
(IRFA), which can be found in Section VII of the IRIA. Given the 
challenging environment and associated costs of drilling in the Arctic 
OCS planning areas, no small entities are expected to operate in these 
areas for the foreseeable future. Therefore, BSEE and BOEM 
preliminarily conclude that no small entities would be affected by 
these proposed amendments, however the agency has prepared an IRFA and 
is seeking public comment on any small business impacts from the 
proposed amendments.
    This proposed rule would meet the E.O. 12866 criteria for an 
economically significant rule because it would likely have an annual 
effect on the economy of $100 million or more in at least one year of 
the 20-year period analyzed, and BSEE/BOEM comply with the RFA and the 
Small Business Regulatory Enforcement Fairness Act by providing a 
regulatory flexibility analysis. The requirements would apply to all 
entities operating on the Arctic OCS regardless of company designation 
as a small business. For more information on the small business 
impacts, see the IRFA section in the IRIA. Small businesses may send 
comments on the actions of Federal employees who enforce, or otherwise 
determine compliance with, Federal regulations to the Small Business 
and Agriculture Regulatory Enforcement Ombudsman, and to the Regional 
Small Business Regulatory Fairness Board. The Ombudsman evaluates these 
actions annually and rates each agency's responsiveness to small 
business. If you wish to comment on actions by employees of BSEE or 
BOEM, call 1-888-REG-FAIR (1-888-734-3247).

C. Unfunded Mandates Reform Act of 1995 (UMRA)

    This proposed rule would not impose an unfunded Federal mandate on 
State, local, or tribal governments and would not have a significant or 
unique effect on State, local, or tribal governments. The requirements 
in this proposed rule would apply to Arctic OCS oil and gas lessees and 
operators, not to State, local, and tribal governments. Thus, the 
proposed rule would not have disproportionate budgetary effects on 
these governments. BSEE and BOEM have determined the proposed changes 
in this rulemaking would result in cost savings annually to regulated 
entities. Therefore, a written statement under the Unfunded Mandates 
Reform Act (2 U.S.C. 1531 et seq.) is not required.

D. Takings Implication Assessment

    Under the criteria in E.O. 12630, this proposed rule would not have 
significant takings implications. The proposed rule is not a 
governmental action capable of interference with constitutionally 
protected property rights. A Takings Implication Assessment is not 
required.

E. Federalism (E.O. 13132)

    Under the criteria in E.O. 13132, this proposed rule would not have 
federalism implications. This proposed rule would not substantially and 
directly affect the relationship between the Federal and State 
Governments. To the extent that State and local governments have a role 
in OCS activities, this proposed rule would not affect that role. A 
Federalism Assessment is not required.

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

    This proposed rule complies with the requirements of E.O. 12988. 
Specifically, this rule:
    1. Meets the criteria of section 3(a) requiring that all 
regulations be reviewed to eliminate errors and ambiguity and be 
written to minimize litigation; and
    2. Meets the criteria of section 3(b)(2) requiring that all 
regulations be written in clear language and contain clear legal 
standards.

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

    Under the criteria in E.O. 13175, Consultation and Coordination 
with Indian Tribal Governments (dated November 6, 2000), DOI's Policy 
on Consultation with Indian Tribes and Alaska Native Corporations (512 
Departmental Manual 4, dated November 9, 2015), and DOI's Procedures 
for Consultation with Indian Tribes (512 Departmental Manual 5, dated 
November 9, 2015), we evaluated the subject matter of this rulemaking 
and determined that it would have tribal implications for Alaska 
Natives. As described earlier, future Arctic OCS exploratory drilling 
activities conducted pursuant to this proposed rule could affect Alaska 
Natives, particularly their ability to engage in subsistence and 
cultural activities. However, as discussed earlier in Section I.

[[Page 79308]]

Background, Subsection E. Partner Engagement in Preparation for This 
Proposed Rule, Item 2. Summary of Comments Received, BOEM's 
environmental studies program has provided nearly $500 million over the 
last 46 years to scientific research on the Alaska OCS, which includes 
the Arctic OCS. Since July 2016, BOEM has completed 35 environmental 
studies and has 23 ongoing studies that cover the Arctic, totaling 
nearly $72 million. While this proposed rule would change how operators 
could explore for OCS resources in the Arctic, there are ample 
opportunities to permit these activities consistent with ESA, MMPA, 
NEPA, and consultation with Alaska Native communities. BOEM's 
environmental studies program provides the information that is used to 
evaluate the potential environmental effects of leasing OCS lands for 
exploration and development and helps ensure BOEM and BSEE have the 
best science available for the public, industry, and federal permitting 
decisions.
    In addition, Alaska Natives may also be beneficiaries of the 
proposed rule, to the extent they are partners in any exploratory 
activities. There are additional unquantified benefits in situations 
where a SSID is available to immediately shut-in a flowing well rather 
than waiting for a relief well to be drilled.
    BSEE and BOEM are committed to regular and meaningful consultation 
and collaboration with Alaska Native Tribes and ANCSA Corporations on 
policy decisions that have tribal implications, including, as an 
initial step, through complete and consistent implementation of E.O. 
13175, together with related orders, directives, and guidance. 
Therefore, BSEE and BOEM engaged in Government-to-Government tribal 
consultations, Government-to-ANCSA Corporations consultations, and 
meetings with municipal leaders (i.e., mayors or their respective 
representatives), to discuss the subject matter of the proposed rule 
and solicit input in the development of the proposed rule.
    On September 20, 2018, BSEE and BOEM began reaching out to leaders 
from Alaska Native Tribes, ANCSA Corporations, and municipalities to 
determine which partners were interested in having conversations with 
BSEE and BOEM about the rulemaking. Consultations entailed meetings in 
Alaska, at locations and times convenient to the Alaska Native 
communities and corporations, to ensure they can have proper 
representation during the meetings. Accordingly, the timing of these 
meetings was critical. BSEE and BOEM scheduled the meetings around 
important traditional subsistence and cultural activities, such as 
whaling, that take place during specific times of the year, 
particularly in the early fall. Between November 29, 2018 and January 
30, 2019, BSEE and BOEM met with a majority of the tribal entities (23 
of 25) originally invited to consult. The following table lists all 25 
invited tribal entities, and the dates and locations of the meetings 
with the 23 entities.

----------------------------------------------------------------------------------------------------------------
         Tribal entity name                 Type of entity             Meeting date              Location
----------------------------------------------------------------------------------------------------------------
Native Village of Utqiagvik........  Tribal Government..........  November 29, 2018.....  Anchorage.
Native Village of Wainwright.......  Tribal Government..........
Olgoonik Native Corporation........  Native Corporation.........
Doyon Limited......................  Native Corporation.........
Arctic Slope Regional Corporation..  Native Corporation.........  December 7, 2018......
Native Village of Kotzebue.........  Tribal Government..........  December 10, 2018.....  Kotzebue.
Northwest Arctic Borough Mayor.....  Municipal Government.......
Native Village of Point Hope.......  Tribal Government..........  December 11, 2018.....  Point Hope.
Tikigaq Native Corporation.........  Native Corporation.........
Point Hope Mayor...................  Municipal Government.......
Alaska Eskimo Whaling Commission...  Non-tribe that consults on   December 13, 2018.....  Anchorage.
                                      tribe's behalf.
Cully Corporation..................  Native Corporation.........  December 14, 2018.....
North Slope Borough Mayor..........  Municipal Government.......  December 17, 2018.....  Utqiagvik.
City of Utqiagvik Mayor............  Municipal Government.......
Native Village of Nuiqsut..........  Tribal Government..........  December 18, 2018.....  Nuiqsut.
Kuukpik Corporation................  Native Corporation.........
Nuiqsut Mayor......................  Municipal Government.......
Inupiat Community of the Arctic      Non-tribe that consults on
 Slope.                               tribe's behalf.
Native Village of Kaktovik.........  Tribal Government..........  December 19, 2018.....  Kaktovik.
Kaktovik Inupiat Corporation.......  Native Corporation.........
Kaktovik Mayor.....................  Municipal Government.......
Tanana Chiefs Conference...........  Tribal Government..........  December 20, 2018.....  Fairbanks.
Native Village of Point Lay........  Tribal Government..........  January 30, 2019......  Conference Call.
                                                                 -----------------------------------------------
Kikiktagruk Corporation............  Native Corporation.........      BSEE and BOEM made multiple attempts to
                                                                      contact these corporations. However, the
                                                                      bureaus did not receive a response from
                                                                                either organization.
                                                                 -----------------------------------------------
NANA Regional Corporation..........  Native Corporation.........
----------------------------------------------------------------------------------------------------------------

    All Alaska Native input provided during the meetings was 
subsequently provided to DOI in writing and has been included in the 
administrative record for this proposed rule.
    As previously discussed in part E of the background section in this 
preamble, BSEE and BOEM heard a variety of perspectives during their 
meetings with Alaska Natives. The most common comment received was a 
concern over food security. Subsistence resources, including bowhead 
and beluga whales, other marine mammals, fish, and birds, are a key 
food source for many people's diets in the native villages. Another 
common comment recommended inclusion of a requirement for an oil and 
gas operator to establish an agreement with those whaling communities 
potentially affected by a planned drilling project. Certain tribal 
representatives and most ANCSA corporations were supportive of this 
proposed rulemaking because it could help attract more economic 
opportunities to their villages. Other comments provided during the 
consultation meetings included a recommendation to provide broader

[[Page 79309]]

outreach by presenting this rulemaking to the tribal assemblies and to 
citizens within the communities. One of the ANCSA corporations also 
recommended that this rulemaking take into account the NPC 2019 Report. 
Please refer to the discussions above in Part E (Partner Engagement in 
Preparation for This Proposed Rule) of the background section of this 
preamble for a description of how BSEE and BOEM are addressing this 
input during the rulemaking process. BSEE and BOEM intend to continue 
consultation with affected tribes and ANCSA Corporations following 
publication of this proposed rule.

H. Effects on Environmental Justice for Minority and Low-Income 
Populations (E.O. 12898)

    E.O. 12898 requires Federal agencies to make achieving 
environmental justice part of their mission by identifying and 
addressing disproportionately high and adverse human health or 
environmental effects of their programs, policies, and activities on 
minority and low-income populations. DOI has determined that this 
proposed rule would not have a disproportionately high or adverse human 
health or environmental effect on native, minority, or low-income 
communities because its provisions are designed to maintain 
environmental protection and minimize any impact of exploration 
drilling on subsistence activities and Alaska Native community 
resources and infrastructure.

I. Paperwork Reduction Act (PRA)

    This proposed rule contains existing and new information collection 
(IC) requirements for both BSEE and BOEM regulations, and a submission 
to OMB for review under the Paperwork Reduction Act of 1995 (44 U.S.C. 
3501 et seq.) is required. Therefore, each bureau will submit an IC 
request to OMB for review and approval. We may not conduct, or sponsor, 
and you are not required to respond to a collection of information 
unless it displays a currently valid OMB control number. OMB has 
previously reviewed and approved the existing information collection 
requirements associated with Outer Continental Shelf drilling permits, 
plans, and related information collection, which would be altered by 
this proposed rule. OMB has assigned the following OMB control numbers 
to the current ICs:
     1014-0025 (BSEE), 30 CFR part 250, Applications for Permit 
to Drill (APD and revised APD) (expires 06/30/2023), and in accordance 
with 5 CFR 1320.10, an agency may continue to conduct or sponsor this 
collection of information while the renewal submission is pending at 
OMB.
     1010-0151 (BOEM), 30 CFR part 550, subpart B Plans and 
Information (exp. 06/30/2021), and in accordance with 5 CFR 1320.10, an 
agency may continue to conduct or sponsor this collection of 
information while the renewal submission is pending at OMB.
    The IC aspects affecting each bureau are discussed separately. 
Additionally, BOEM is seeking to renew these information collections 
for three years with this rulemaking. Instructions on how to comment 
follow those discussions.
    The following table details proposed changes to the annual 
estimated hour burdens and non-hour costs; as well as associated wage 
cost changes for both BSEE and BOEM information submission activities 
described below:

                                                                          BSEE
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                               Existing regulations          Proposed rule                     Total changes
                                                           ---------------------------------------------------------------------------------------------
                        Requirement                          Number of     Number of    Number of     Number of    Change of     Change of    Changes in
                                                             responses   burden hours   responses   burden hours   responses   burden hours   wage cost
--------------------------------------------------------------------------------------------------------------------------------------------------------
Submit signed SSID and Well Design certification Sec.                 0             0            2             6           +2            +6        +$848
 250.470(h)...............................................
Submit request to delay access to your SCCE--Sec.                     0             0            2             2           +2            +2        +$286
 250.471(a) and Sec.   250.472(b).........................
--------------------------------------------------------------------------------------------------------------------------------------------------------

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

                                                                          BOEM
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                               Existing regulations          Proposed rule                     Total changes
                                                           ---------------------------------------------------------------------------------------------
                        Requirement                          Number of     Number of    Number of     Number of    Change of     Change of    Changes in
                                                             responses   burden hours   responses   burden hours   responses   burden hours   wage cost
--------------------------------------------------------------------------------------------------------------------------------------------------------
Submit IOP, including all required information Sec.                   1         2,880            0             0          (1)       (2,880)   ($316,800)
 550.204..................................................
Submit required Arctic-specific information with EP Sec.              1           350            1           400  ...........           +50       +5,500
 550.220..................................................
--------------------------------------------------------------------------------------------------------------------------------------------------------

    There are no changes to non-hour costs for BOEM requirements.
BSEE Information Collection--30 CFR Part 250
    The proposed regulations would establish new and/or revise current 
requirements and the submission of information for safe and 
environmentally responsible Arctic OCS oil and gas exploration in an 
APD. BSEE would use the information in our efforts to protect life and 
the environment, conserve natural resources, and prevent waste.
    The following provides a breakdown of the paperwork and non-hour 
cost burdens for this proposed rule. For the current requirements 
retained in the proposed rule, we used OMB's approved estimated hour 
and non-hour cost burdens.
    As discussed in the Preamble Section-by-Section above, and in the 
supporting statement available at RegInfo.gov, this proposed rule would 
modify language in Sec. Sec.  250.175(d), 250.300(b),

[[Page 79310]]

250.470(f)(3), and 250.720(c)(2); however, there would be no change in 
hour burden or non-hour costs associated with these revisions.
    In Sec.  250.470(h), we would add a requirement to submit with an 
APD a certification signed by a registered professional engineer that 
your SSID and well design (including casing and cementing program) meet 
the design requirements in Sec.  250.472 (+ 2 responses and 6 hours for 
PE Certification).
    In Sec. Sec.  250.471(a) and 250.472(b), we would add a requirement 
for operators to submit, with an APD, documentation demonstrating that 
having access to SCCE and the relief rig can be safely delayed until 
the last casing point prior to penetrating a zone capable of flowing 
hydrocarbons in measurable quantities. BSEE will grant this approval if 
the operator adequately demonstrates to the Bureau that it will not 
encounter any abnormally high-pressured zones or other geological 
hazards before that casing point (+ 2 responses and 2 hours per 
request).
    Because not all APDs submitted to BSEE would involve Arctic OCS 
exploration drilling, we are separating the Arctic-specific 
requirements and burdens from the national APD requirements. The burden 
table below outlines the revised requirements and burdens associated 
with this proposed rulemaking.
    Title of Collection: Revisions to the Requirements for Exploratory 
Drilling on the Arctic Outer Continental Shelf--Application for Permit 
to Drill (APD, Revised APD).
    OMB Control Number: 1014-0025.
    Form Number: BSEE-0123 (APD) and BSEE-0123S (Supplemental APD).
    Type of Review: Revision of a currently approved collection.
    Respondents/Affected Public: Potential respondents comprise Federal 
OCS oil, gas, and sulfur lessees/operators and holders of pipeline 
rights-of-way.
    Total Estimated Number of Annual Respondents: Currently there are 
approximately 60 Oil and Gas Drilling and Production Operators in the 
OCS. Not all the potential respondents would submit information at any 
given time, and some may submit multiple times.
    Total Estimated Number of Annual Responses: 11,331.
    Estimated Completion Time per Response: Varies from 1 hour to 2,800 
hours depending on activity.
    Total Estimated Number of Annual Burden Hours: 77,945.
    Respondent's Obligation: Most responses are mandatory, while others 
are required to obtain or retain benefits.
    Frequency of Collection: Generally, on occasion and as required in 
the regulations.
    Total Estimated Annual Nonhour Burden Cost: $4,400,470.

                                                  Burden Table
                                [Changes due to the proposed rule shown in bold]
----------------------------------------------------------------------------------------------------------------
                                              Reporting or                                        Annual  burden
 Citation 30 CFR 250;  application for       recordkeeping        Hour burden    Average number        hours
         permit to drill  (APD)              requirement *                        of responses       (rounded)
----------------------------------------------------------------------------------------------------------------
                                                                              Non-hour cost burden
----------------------------------------------------------------------------------------------------------------
Subparts A, C, D, E, G, H, P...........  Apply for permit to                 1  190 applications             190
                                          drill, sidetrack,
                                          bypass, or deepen a
                                          well submitted via
                                          Forms BSEE-0123
                                          (APD) and BSEE-0123S
                                          (Supplemental APD).
                                          (This burden
                                          represents only the
                                          filling out of the
                                          forms, the
                                          requirements are
                                          listed separately
                                          below.).
                                                                               ---------------------------------
                                                                                   $2,113 fee x 190 = $401,470
----------------------------------------------------------------------------------------------------------------
Subparts D, E, G.......................  Obtain approval to                  1  730 submittals..             730
                                          revise your drilling
                                          plan or change major
                                          drilling equipment
                                          by submitting a
                                          Revised APD and
                                          Supplemental APD [no
                                          cost recovery fee
                                          for Revised APDs].
                                          (This burden
                                          represents only the
                                          filling out of the
                                          forms, the
                                          requirements are
                                          listed separately
                                          below.).
----------------------------------------------------------------------------------------------------------------
    Subtotal..................................................................  920 responses...             920
----------------------------------------------------------------------------------------------------------------
                                             $401,470 non-hour cost burdens
----------------------------------------------------------------------------------------------------------------
                                                    Subpart A
----------------------------------------------------------------------------------------------------------------
125....................................  Submit evidence of      Exempt under 5 CFR 1320.3(h)(1)               0
                                          your fee for
                                          services receipt.
----------------------------------------------------------------------------------------------------------------
197....................................  Written                 Exempt under 5 CFR 1320.5(d)(2)               0
                                          confidentiality
                                          agreement.
----------------------------------------------------------------------------------------------------------------
                                                    Subpart C
----------------------------------------------------------------------------------------------------------------
300(b)(1), (2).........................  Obtain approval to                150  1 request.......             150
                                          add petroleum-based
                                          substance to
                                          drilling mud system
                                          or approval for
                                          method of disposal
                                          of drill cuttings,
                                          sand, & other well
                                          solids, including
                                          those containing
                                          Naturally Occurring
                                          Radioactive Material
                                          (NORM).
----------------------------------------------------------------------------------------------------------------
    Subpart C subtotal........................................................  1 response......             150
----------------------------------------------------------------------------------------------------------------

[[Page 79311]]

 
                                                    Subpart D
----------------------------------------------------------------------------------------------------------------
408; 414(h)............................  Request approval of     Burden covered under subpart A,               0
                                          alternate procedures              1014-0022
                                          or equipment during
                                          drilling operations.
----------------------------------------------------------------------------------------------------------------
409....................................  Request departure                   1  370 approvals...             370
                                          approval from the
                                          drilling
                                          requirements
                                          specified in this
                                          subpart; identify
                                          and discuss.
----------------------------------------------------------------------------------------------------------------
410(b); 417(b); 713....................  Reference well and                  8  1 submittal.....               8
                                          site-specific
                                          information in case
                                          it is not approved
                                          in your Exploration
                                          Plan, Development
                                          and Production Plan,
                                          Development
                                          Operations
                                          Coordination
                                          Document. Burdens
                                          pertaining to EPs,
                                          DPPs, DOCDs are
                                          covered under BOEM
                                          1010-0151.
----------------------------------------------------------------------------------------------------------------
410(d).................................  Submit to the                     0.5  380 submittals..             190
                                          District Manager: An           R-0.5  380 submittals..             190
                                          original and two
                                          complete copies of
                                          APD and Supplemental
                                          APD; separate public
                                          information copy of
                                          forms per Sec.
                                          250.186.
----------------------------------------------------------------------------------------------------------------
411; 412...............................  Submit plat showing                 2  380 submittals..             760
                                          location of the
                                          proposed well and
                                          all the plat
                                          requirements
                                          associated with this
                                          section.
----------------------------------------------------------------------------------------------------------------
411; 413; 414; 415; 420................  Submit design                      15  707 submittals..          10,605
                                          criteria used and
                                          all description
                                          requirements;
                                          drilling prognosis
                                          with description of
                                          the procedures you
                                          will follow; and
                                          casing and cementing
                                          program requirements.
----------------------------------------------------------------------------------------------------------------
411; 416; 731..........................  Submit diverter and                11  380 submittals..           4,180
                                          BOP systems
                                          descriptions and all
                                          the regulatory
                                          requirements
                                          associated with this
                                          section.
----------------------------------------------------------------------------------------------------------------
411; 713...............................  Provide information                10  682 submittals..           6,820
                                          for using a MODU and
                                          all the regulatory
                                          requirements
                                          associated with this
                                          section.
----------------------------------------------------------------------------------------------------------------
411; 418...............................  Additional                         20  380 submittals..           7,600
                                          information required
                                          when providing an
                                          APD include, but not
                                          limited to, rated
                                          capacities of
                                          drilling rig and
                                          equipment if not
                                          already on file;
                                          drilling fluids
                                          program, including
                                          weight materials;
                                          directional plot;
                                          H2S contingency
                                          plan; welding plan;
                                          and information we
                                          may require per
                                          requirements, etc.
----------------------------------------------------------------------------------------------------------------
414(c).................................  Request preapproval                 1  15 requests.....              15
                                          to use alternative
                                          equivalent downhole
                                          mud weight prior to
                                          submitting APD.
----------------------------------------------------------------------------------------------------------------
420(a)(7)..............................  Include signed                      3  1,034                      3,102
                                          registered                             certifications.
                                          professional
                                          engineer
                                          certification and
                                          related information.
----------------------------------------------------------------------------------------------------------------
423(c).................................  Submit for approval                 3  527 procedures &           1,581
                                          casing pressure test                   criteria.
                                          procedures and
                                          criteria. On casing
                                          seal assembly ensure
                                          proper installation
                                          of casing or liner
                                          (subsea BOP's only).
----------------------------------------------------------------------------------------------------------------
428(b).................................  Submit to District                125  1 submittal.....             125
                                          Manager for approval
                                          revised casing
                                          setting depths or
                                          hole interval
                                          drilling depth;
                                          include
                                          certification by PE.
----------------------------------------------------------------------------------------------------------------
428(k).................................  Submit a description              125  1 submittal.....             125
                                          of the plan to use a
                                          valve(s) on the
                                          drive pipe during
                                          cementing operations
                                          for the conductor
                                          casing, surface
                                          casing, or liner.
----------------------------------------------------------------------------------------------------------------

[[Page 79312]]

 
432....................................  Request departure                   8  53 requests.....             424
                                          from diverter
                                          requirements; with
                                          discussion and
                                          receive approval.
----------------------------------------------------------------------------------------------------------------
460(a).................................  Include your                       17  2 plans.........              34
                                          projected plans if
                                          well testing along
                                          with the required
                                          information.
----------------------------------------------------------------------------------------------------------------
462(c).................................  Submit a description              125  1 submittal.....             125
                                          of your source
                                          control and
                                          containment
                                          capabilities to the
                                          Regional Supervisor
                                          and receive
                                          approval; all
                                          required information.
----------------------------------------------------------------------------------------------------------------
470(h).................................  Submit certification                3  2 certs.........               6
                                          signed by PE that
                                          SSID and well design
                                          meet requirements of
                                          Sec.   250.472.
                                          (Alaska only).
----------------------------------------------------------------------------------------------------------------
471(a); 472(b).........................  Submit, to Regional                 1  2 requests......               2
                                          Supervisor, a
                                          request to delay
                                          access to your SCCE
                                          and relief rig, if
                                          applicable,
                                          including adequate
                                          documentation (such
                                          as, but not limited
                                          to, risk modeling
                                          data, off-set well
                                          data, analog data,
                                          seismic data).
                                          Demonstrate you will
                                          not encounter any
                                          abnormally high-
                                          pressured zones or
                                          other geologic
                                          hazards. (Alaska
                                          only).
----------------------------------------------------------------------------------------------------------------
490(c).................................  Request to classify                 3  91 requests.....             273
                                          an area for the
                                          presence of H2S.
                                        ------------------------------------------------------------------------
                                         Support request with                3  73 submittals...             219
                                          available
                                          information such as
                                          G&G data, well logs,
                                          formation tests,
                                          cores and analysis
                                          of formation fluids.
                                        ------------------------------------------------------------------------
                                         Submit a request for                1  4 requests......               4
                                          reclassification of
                                          a zone when a
                                          different
                                          classification is
                                          needed.
----------------------------------------------------------------------------------------------------------------
Alaska Region: 410; 412 thru 418; 420;   Due to the                      2,800  1 request.......           2,800
 442; 444; 449; 456; 470; 471; 472.       difficulties of
                                          drilling in Alaska,
                                          along with the
                                          shortened time
                                          window allowed for
                                          drilling, Alaska
                                          hours are done here
                                          as stand-alone
                                          requirements. Also,
                                          note that these
                                          specific hours are
                                          based on the first
                                          APD in Alaska in
                                          more than 10 years.
----------------------------------------------------------------------------------------------------------------
    Subpart D subtotal........................................................  5,467 responses.          39,558
----------------------------------------------------------------------------------------------------------------
                                                    Subpart E
----------------------------------------------------------------------------------------------------------------
513....................................  Obtain written                      3  288 requests....             864
                                          approval to begin                R-3  1 request.......               3
                                          well completion
                                          operations. If
                                          completion is
                                          planned and the data
                                          are available you
                                          may submit on forms.
                                        ------------------------------------------------------------------------
                                         Submit description of            18.5  295 submittals..           5,458
                                          well-completion,                R-26  1 submittal.....              26
                                          schematics, logs,
                                          any H2S..
----------------------------------------------------------------------------------------------------------------
    Subpart E subtotal........................................................  585 responses...           6,351
----------------------------------------------------------------------------------------------------------------
                                                    Subpart G
----------------------------------------------------------------------------------------------------------------
701; 720...............................  Identify and discuss    Burden covered under subpart A,               0
                                          your proposed                     1014-0022
                                          alternate procedures
                                          or equipment.
----------------------------------------------------------------------------------------------------------------
702....................................  Identify and discuss    Burden covered under subpart A,               0
                                          departure requests..              1014-0022
----------------------------------------------------------------------------------------------------------------
713(b).................................  Submit plat of the                125  1 submittal.....             125
                                          rig's anchor pattern
                                          for a moored rig
                                          approved in your EP,
                                          DPP, or DOCD.
----------------------------------------------------------------------------------------------------------------

[[Page 79313]]

 
713(e).................................  Provide contingency                10  682 submittals..           6,820
                                          plan for using
                                          dynamically
                                          positioned MODU and
                                          all the regulatory
                                          requirements
                                          associated with this
                                          section.
----------------------------------------------------------------------------------------------------------------
713(g).................................  Describe specific                  45  1 submittal.....              45
                                          current speeds when
                                          implementing rig
                                          shutdown and/or move-
                                          off procedures for
                                          water depths > 400
                                          meters; discussion
                                          of specific measures
                                          you will take to
                                          curtail rig
                                          operations/move-off
                                          location.
----------------------------------------------------------------------------------------------------------------
720(b).................................  Request approval to                 5  518 approval               2,590
                                          displace kill-weight                   requests.
                                          fluid; include
                                          reasons why along
                                          with step-by-step
                                          procedures.
----------------------------------------------------------------------------------------------------------------
721(g)(4)..............................  Submit test                   2.5 R-4  355 submittals,            8,884
                                          procedures and                         1 change.
                                          criteria for a
                                          successful negative
                                          pressure test for
                                          approval. If any
                                          change, submit
                                          changes for approval.
----------------------------------------------------------------------------------------------------------------
731....................................  Submit complete                   114  129 submittals..          14,706
                                          description of BOP
                                          system and
                                          components;
                                          schematic drawings;
                                          certification by ITP
                                          (additional I3P if
                                          BOP is subsea, in
                                          HPHT, or surface on
                                          floating facility);
                                          autoshear, deadman,
                                          EDS systems.
                                                               -------------------------------------------------
                                                                      $31,000 x 129 submittal = $3,999,000
----------------------------------------------------------------------------------------------------------------
733(b).................................  Describe annulus                   67  1 submittal.....              67
                                          monitoring plan; and
                                          how the well will be
                                          secured if leak is
                                          detected.
----------------------------------------------------------------------------------------------------------------
734(b).................................  Submit verification              R-64  1 report........              64
                                          report from ITP
                                          documenting repairs
                                          and that BOP is fit
                                          for service.
----------------------------------------------------------------------------------------------------------------
734(c).................................  Submit revision,                 R-66  1 submittal.....              66
                                          including all
                                          verifications
                                          required, before
                                          drilling out surface
                                          casing.
----------------------------------------------------------------------------------------------------------------
737(a).................................  Request approval from               1  358 casing/liner             358
                                          District Manager to                    info.
                                          omit BOP pressure
                                          test. Indicate which
                                          casing strings and
                                          liners meet the
                                          criteria for this
                                          request.
----------------------------------------------------------------------------------------------------------------
737(b)(2)..............................  Request approval of                 2  353 requests....             706
                                          test pressures (RAM
                                          BOPs).
----------------------------------------------------------------------------------------------------------------
737(b)(3)..............................  Request approval of                 2  380 requests....             760
                                          pressure test
                                          (annular BOPs).
----------------------------------------------------------------------------------------------------------------
737(d)(2)..............................  Submit test                       2.5  507 submittals..           1,268
                                          procedures for
                                          approval for surface
                                          BOP.
----------------------------------------------------------------------------------------------------------------
737(d)(3); (d)(4)......................  Submit test                         2  507 submittals..           1,014
                                          procedures,
                                          including how you
                                          will test each ROV
                                          intervention
                                          function, for
                                          approval (subsea
                                          BOPs only).
----------------------------------------------------------------------------------------------------------------
737(d)(12).............................  Submit test                       2.5  507 submittals..           1,268
                                          procedures
                                          (autoshear and
                                          deadman systems) for
                                          approval. Include
                                          documentation of the
                                          controls/circuitry
                                          system used for each
                                          test; describe how
                                          the ROV will be
                                          utilized during this
                                          operation.
----------------------------------------------------------------------------------------------------------------
738(b).................................  Submit a revised                   .5  50 submittals...              25
                                          permit with a
                                          written statement
                                          from an independent
                                          third party
                                          documenting the
                                          repairs,
                                          replacement, or
                                          reconfiguration and
                                          certifying that the
                                          previous
                                          certification in
                                          Sec.   250.731(c)
                                          remains valid.
----------------------------------------------------------------------------------------------------------------
738(m).................................  Request approval to                66  1 request.......              66
                                          use additional well
                                          control equipment,
                                          including BAVO
                                          report; as well as
                                          other information
                                          required by District
                                          Manager.
----------------------------------------------------------------------------------------------------------------

[[Page 79314]]

 
738(n).................................  Submit which pipe/                 64  1 submittal.....              64
                                          variable bore rams
                                          have no current
                                          utility or well
                                          control purposes.
----------------------------------------------------------------------------------------------------------------
    Subpart G subtotal........................................................  4,177 response..          16,396
----------------------------------------------------------------------------------------------------------------
                                                    Subpart H
----------------------------------------------------------------------------------------------------------------
807(a).................................  Submit detailed                    13  1 submittal.....              13
                                          information that
                                          demonstrates the
                                          SSSVs and related
                                          equipment are
                                          capable of
                                          performing in HPHT.
----------------------------------------------------------------------------------------------------------------
    Subpart H subtotal........................................................  1 response......              13
----------------------------------------------------------------------------------------------------------------
                                                    Subpart P
----------------------------------------------------------------------------------------------------------------
Note that for Sulfur Operations, while there may be 49 burden hours listed, we have not had any sulfur leases
 for numerous years, therefore, we have submitted minimal burden..
----------------------------------------------------------------------------------------------------------------
1605(b)(3).............................  Submit information on               6  1 submittal.....               6
                                          the fitness of the
                                          drilling unit.
----------------------------------------------------------------------------------------------------------------
1617...................................  Submit fully                       40  1 submittal.....              40
                                          completed
                                          application (Form
                                          BSEE-0123) include
                                          rated capacities of
                                          the proposed
                                          drilling unit and of
                                          major drilling
                                          equipment; as well
                                          as all required
                                          information listed
                                          in this section.
----------------------------------------------------------------------------------------------------------------
1622(b)................................  Submit description of               3  1 submittal.....               3
                                          well-completion or
                                          workover procedures,
                                          schematic, and if
                                          H2S is present.
----------------------------------------------------------------------------------------------------------------
    Subpart P subtotal........................................................  3 responses.....              49
----------------------------------------------------------------------------------------------------------------
        Total Burden for APD..................................................  11,331 Responses          77,945
                                        ------------------------------------------------------------------------
                                            $4,400,470 Non Hour Cost Burden
----------------------------------------------------------------------------------------------------------------
* In the future, BSEE may require electronic filing of some submissions.

    In addition, the PRA requires agencies to estimate the total annual 
reporting and recordkeeping non-hour cost burden resulting from the 
collection of information, and we solicit your comments on this item. 
For reporting and recordkeeping only, your response should split the 
cost estimate into two components: (1) Total capital and startup cost 
component and (2) annual operation, maintenance, and purchase of 
service component. Your estimates should consider the cost to generate, 
maintain, and disclose or provide the information. You should describe 
the methods you use to estimate major cost factors, including system 
and technology acquisition, expected useful life of capital equipment, 
discount rate(s), and the period over which you incur costs. Generally, 
your estimates should not include equipment or services purchased: (1) 
Before October 1, 1995; (2) to comply with requirements not associated 
with the information collection; (3) for reasons other than to provide 
information or keep records for the Government; or (4) as part of 
customary and usual business or private practices.
    As part of our continuing effort to reduce paperwork and respondent 
burdens, we invite the public and other Federal agencies to comment on 
any aspect of this information collection, including:
    (1) Whether the collection of information is necessary, including 
whether the information will have practical utility;
    (2) The accuracy of our estimate of the burden for this collection 
of information;
    (3) Ways to enhance the quality, utility, and clarity of the 
information to be collected; and
    (4) Ways to minimize the burden of the collection of information on 
respondents.
    Send your comments and suggestions on this information collection 
by the date indicated in the DATES section to the Desk Officer for the 
Department of the Interior at OMB-OIRA at (202) 395-5806 (fax) or via 
the RegInfo.gov portal (online). You may view the information 
collection request(s) at https://www.reginfo.gov/public/do/PRAMain. 
Please provide a copy of your comments to the BSEE Information 
Collection Clearance Officer (see the ADDRESSES section). You may 
contact Kye Mason, BSEE Information Collection Clearance Officer at 
(703) 787-1607 with any questions. Please reference Revisions to the 
Requirements for Exploratory Drilling on the Arctic Outer Continental 
Shelf (OMB Control No. 1014-0025), in your comments.
BOEM Information Collection--30 CFR Part 550
    This proposed rule would add and remove requirements related to 
submitting exploration plans and other information before conducting 
oil and gas exploration drilling activities on the Arctic OCS. If final 
regulations become effective, the information collection burdens for 
this rulemaking would be

[[Page 79315]]

consolidated into the existing collection for Subpart B, Control Number 
1010-0151, and will be adjusted as necessary. BOEM is requesting OMB 
approve the modified collections of information for OMB Control Number 
1010-0151 with the final rule publication.
    Pertaining to this proposed rulemaking, BOEM would collect the 
information to ensure that planned operations will be safe; will not 
adversely affect the marine, coastal, or human environments; will 
respond to the special conditions on the Arctic OCS; and will conserve 
the resources of the Arctic OCS. BOEM would use the information to 
ensure, through advanced planning, that operators are capable of safely 
operating in the unique environmental conditions of the Arctic and to 
make informed decisions on whether to approve EPs as submitted or 
whether modifications are necessary.
    BOEM proposes to remove the Integrated Operations Plan (IOP) 
regulations by deleting Sec.  550.204 and removing the corresponding 
references to the IOP from Sec. Sec.  550.200 and 550.206. BOEM's 
existing requirement to submit the IOP at least 90 days before the 
lessee or operator files an EP would be eliminated. The data and 
information requested in the IOP is largely unnecessary in light of the 
information already collected in the EP. The current approval for OMB 
Control Number 1010-0151 counts the similar burdens associated with 
IOPs and EPs in both. Therefore, BOEM would remove the burdens 
attributed to the IOPs, and keep the burdens attributed to EPs. 
Removing the IOP provision would decrease the annual burden hours by 1 
response and 2,880 hours (- 1 response and 2,880 annual burden hours).
    The proposed rule would add a requirement to Sec.  550.211(b) to 
describe operational safety procedures that the operator has developed 
specific to conditions relevant on the Arctic OCS in the EP. These 
requirements were previously included in the IOP requirements that are 
removed from this rulemaking. Retaining this provision would lessen the 
2,880-burden hour decrease by 50 annual burden hours (i.e., by 
retaining 50 annual burden hours).
    BOEM proposes to revise Sec.  550.220(c)(1) to require a 
description of how exploratory drilling will be designed and conducted, 
including how all vessels and equipment will be designed, built, and/or 
modified, to account for Arctic OCS conditions and how such activities 
will be managed and overseen as an integrated endeavor, and in the 
description of vessel modifications, a description of any approvals 
from the flag state and the vessel classification society, including 
any allowances or limitations placed upon the vessel by the 
classification society and/or the USCG. Vessel modifications may 
include the suitability of vessels for Arctic conditions. These vessels 
may have or acquire classification from a ``recognized organization'' 
under the USCG's Alternative Compliance Program (ACP).\54\ BOEM is 
seeking to confirm that the operator meets the requirements of other 
entities with authority over vessels, not to impose requirements on 
those vessels. BOEM believes that this change would not impose any 
material additional burdens on the lessees or operators. BOEM is also 
proposing to revise Sec.  550.220(c)(4) and (6) by requiring the 
operator to provide a general description of how they will comply with 
Sec.  250.472, including a description of the termination of their 
operations.
---------------------------------------------------------------------------

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

    BOEM estimates that the proposed revisions would remove 2,880 
annual burden hours that correlate to the removal of the existing IOP 
requirement. These changes would result in a net decrease of 2,830 
annual burden hours.
    Because not all EPs submitted to BOEM would involve Arctic OCS 
exploration drilling, we are separating the burden associated with the 
Arctic-specific requirements and burdens from the national EP 
requirements. The burden table that follows this paragraph outlines the 
revised requirements and burdens associated with this rulemaking. BOEM 
has not identified any non-hour cost burdens associated with these 
proposed requirements.
    Title of Collection: Revisions to the Requirements for Exploratory 
Drilling on the Arctic Outer Continental Shelf--30 CFR part 550, 
subpart B, Plans and Information.
    OMB Control Number: 1010-0151.
    Form Number:
     BOEM-0137, OCS Plan Information Form
     BOEM-0138, EP Air Quality Screening Checklist
     BOEM-0139, DOCD/DPP Air Quality Screening Checklist.
     BOEM-0141, ROV Survey Report.
     BOEM-0142, Environmental Impact Analysis Worksheet.
    Type of Review: Revision of a currently approved collection.
    Respondents/Affected Public: Respondents are Federal oil and gas or 
sulfur lessees or operators.
    Total Estimated Number of Annual Response: 4,265 respondents.
    Total Estimated Number of Annual Burden Hours: 433,608 hours.
    Respondent's Obligation: Some responses to the information 
collection are required to obtain or retain a benefit, and some are 
mandatory.
    Frequency of Collection: The frequency of the response varies, but 
primarily responses are required only on occasion.
    Total Estimated Annual Nonhour Burden Cost: $3,939,435.

                                                Burden Breakdown
           [Current requirements in regular font; proposed expanded requirements shown in italic font]
----------------------------------------------------------------------------------------------------------------
                                          Reporting &
  Citation 30 CFR 550  subpart B         recordkeeping         Hour burden    Average number of    Burden hours
             and NTLs                     requirement                          annual responses
----------------------------------------------------------------------------------------------------------------
                                                           Non-hour costs
----------------------------------------------------------------------------------------------------------------
200 thru 206.....................  General requirements for     Burden included with specific                  0
                                    plans and information;           requirements below.
                                    fees/refunds, etc.
----------------------------------------------------------------------------------------------------------------
201 thru 206; 211 thru 228: 241    BOEM posts EPs/DPPs/       Not considered IC as defined in 5                0
 thru 262.                          DOCDs on FDMS and                 CFR 1320.3(h)(4).
                                    receives public
                                    comments in preparation
                                    of EAs.
----------------------------------------------------------------------------------------------------------------
    Subtotal...............................................................  0..................               0
----------------------------------------------------------------------------------------------------------------

[[Page 79316]]

 
                                              Ancillary Activities
----------------------------------------------------------------------------------------------------------------
208; NTL 2009-G34 *..............  Notify BOEM in writing,               11  61 notices.........             671
                                    and if required by the
                                    Regional Supervisor
                                    notify other users of
                                    the OCS before
                                    conducting ancillary
                                    activities.
----------------------------------------------------------------------------------------------------------------
208; 210(a)......................  Submit report                          2  61 reports.........             122
                                    summarizing & analyzing
                                    data/information
                                    obtained or derived
                                    from ancillary
                                    activities.
----------------------------------------------------------------------------------------------------------------
208; 210(b)......................  Retain ancillary                       2  61 records.........             122
                                    activities data/
                                    information; upon
                                    request, submit to BOEM.
----------------------------------------------------------------------------------------------------------------
    Subtotal...............................................................  183 responses......              91
----------------------------------------------------------------------------------------------------------------
                                       Contents of Exploration Plans (EP)
----------------------------------------------------------------------------------------------------------------
209; 231(b); 232(d); 234; 235;     Submit new, amended,                 150  345 changed plans3.          51,750
 281; 283; 284; 285; NTL 2015-N01.  modified, revised, or
                                    supplemental EP, or
                                    resubmit disapproved
                                    EP, including required
                                    information; withdraw
                                    an EP.
----------------------------------------------------------------------------------------------------------------
209; 211 thru 228; NTL 2015-N01..  Submit EP and all                    600  163................          97,800
                                    required information
                                    (including, but not
                                    limited to, submissions
                                    required by BOEM Forms
                                    0137, 0138, 0142; lease
                                    stipulations; reports,
                                    including shallow
                                    hazards surveys, H2S,
                                    G&G, archaeological
                                    surveys & reports (Sec.
                                      550.194) ***, in
                                    specified formats.
                                    Provide notifications.
                                                            ----------------------------------------------------
                                                                 $3,673 x 163 EP surface locations = $598,699
----------------------------------------------------------------------------------------------------------------
210; 220(a)-(c); 291; 292........  For existing Arctic OCS              700  1..................             700
                                    exploration activities:
                                    revise and resubmit
                                    Arctic-specific
                                    information, as
                                    required.
----------------------------------------------------------------------------------------------------------------
202; 211; 216; 219, 220(a)-(c);    For new Arctic OCS                   400  1..................             400
 224, 227;.                         exploration activities:
                                    submit required Arctic-
                                    specific information
                                    with EP.
----------------------------------------------------------------------------------------------------------------
    Subtotal...............................................................  510 responses......         150,650
                                  ------------------------------------------------------------------------------
                                            $598,699 Non-hour costs
----------------------------------------------------------------------------------------------------------------
                                     Review and Decision Process for the EP
----------------------------------------------------------------------------------------------------------------
235(b); 272(b);..................  Appeal State's objection   Burden exempt as defined in 5 CFR                0
281(d)(3)(ii)....................                                     1320.4(a)(2), (c).
----------------------------------------------------------------------------------------------------------------
   Contents of Development and Production Plans (DPP) and Development Operations Coordination Documents (DOCD)
----------------------------------------------------------------------------------------------------------------
209; 266(b); 267(d); 272(a); 273;  Submit amended,                      235  353 changed plans..          82,955
 281; 283; 284; 285; NTL 2015-N01.  modified, revised, or
                                    supplemental DPP or
                                    DOCD, including
                                    required information,
                                    or resubmit disapproved
                                    DPP or DOCD.
----------------------------------------------------------------------------------------------------------------
241 thru 262; 209; NTL 2015-N01..  Submit DPP/DOCD and                  700  268................         187,600
                                    required/supporting
                                    information (including,
                                    but not limited to,
                                    submissions required by
                                    BOEM Forms 0137, 0139,
                                    0142; lease
                                    stipulations; reports,
                                    including shallow
                                    hazards surveys,
                                    archaeological surveys
                                    & reports (Sec.
                                    550.194)), in specified
                                    formats. Provide
                                    notification.
----------------------------------------------------------------------------------------------------------------
                                                                  $4,238 x 268 DPP/DOCD wells = $1,135,784.
----------------------------------------------------------------------------------------------------------------
    Subtotal...............................................................  621 responses......         270,555
                                  ------------------------------------------------------------------------------
                                           $1,135,784 Non-hour costs
----------------------------------------------------------------------------------------------------------------

[[Page 79317]]

 
                                 Review and Decision Process for the DPP or DOCD
----------------------------------------------------------------------------------------------------------------
267(a)...........................  Once BOEM deemed DPP/      Not considered IC as defined in 5                0
                                    DOCD submitted;                   CFR 1320.3(h)(4).
                                    Governor of each
                                    affected State, local
                                    government official;
                                    etc., submit comments/
                                    recommendations.
----------------------------------------------------------------------------------------------------------------
267(b)...........................  General public comments/   Not considered IC as defined in 5                0
                                    recommendations                   CFR 1320.3(h)(4).
                                    submitted to BOEM
                                    regarding DPPs or DOCDs.
----------------------------------------------------------------------------------------------------------------
269(b)...........................  For leases or units in                 3  1 response.........               3
                                    vicinity of proposed
                                    development and
                                    production activities
                                    RD may require those
                                    lessees and operators
                                    to submit information
                                    on preliminary plans
                                    for their leases and
                                    units.
----------------------------------------------------------------------------------------------------------------
    Subtotal...............................................................  1 response.........               3
----------------------------------------------------------------------------------------------------------------
                              Post-Approval Requirements for the EP, DPP, and DOCD
----------------------------------------------------------------------------------------------------------------
280(b)...........................  In an emergency, request    Burden included under 1010-0114.                0
                                    departure from your
                                    approved EP, DPP, or
                                    DOCD.
----------------------------------------------------------------------------------------------------------------
281(a)...........................  Submit various BSEE        Burdens included under appropriate               0
                                    applications for          subpart or form (1014-0003; 1014-
                                    approval and submit          0011; 1014-0016; 1014-0018).
                                    permits.
----------------------------------------------------------------------------------------------------------------
282..............................  Retain monitoring data/                4  150 records........             600
                                    information; upon
                                    request, make available
                                    to BOEM.
                                  ------------------------------------------------------------------------------
                                   Prepare and submit                     2  6 plans............              12
                                    monitoring plan for
                                    approval.
----------------------------------------------------------------------------------------------------------------
282(b)...........................  Prepare and submit                     3  12 reports.........              36
                                    monitoring reports and
                                    data (including BOEM
                                    Form 0141 used in GOMR).
----------------------------------------------------------------------------------------------------------------
284(a)...........................  Submit updated info on                 4  56 updates.........             224
                                    activities conducted
                                    under approved EP/DPP/
                                    DOCD.
----------------------------------------------------------------------------------------------------------------
    Subtotal...............................................................  224 responses......             872
----------------------------------------------------------------------------------------------------------------
                                                   Submit CIDs
----------------------------------------------------------------------------------------------------------------
296(a); 297......................  Submit CID and required/             375  14 documents.......           5,250
                                    supporting information;
                                    submit CID for
                                    supplemental DOCD or
                                    DPP.
                                                            ----------------------------------------------------
                                                                           $27,348 x 14 = $382,872
----------------------------------------------------------------------------------------------------------------
296(b); 297......................  Submit a revised CID for             100  13 revisions.......           1,300
                                    approval.
----------------------------------------------------------------------------------------------------------------
    Subtotal...............................................................  27 responses.......           6,550
                                  ------------------------------------------------------------------------------
                                            $382,872 Non-hour costs
----------------------------------------------------------------------------------------------------------------
                  Seismic Survey Mitigation Measures and Protected Species Observer Program NTL
----------------------------------------------------------------------------------------------------------------
NTL 2016-G02; 211 thru 228; 241    Submit to BOEM observer        1.5 hours  2 sets of material.               3
 thru 262.                          training requirement
                                    materials and
                                    information.
                                  ------------------------------------------------------------------------------
                                   Training certification            1 hour  1 new trainee......               1
                                    and recordkeeping.
                                  ------------------------------------------------------------------------------
                                   During seismic                 1.5 hours  344 reports........             516
                                    acquisition operations,
                                    submit daily observer
                                    reports semi-monthly.
                                  ------------------------------------------------------------------------------
                                   If used, submit to BOEM          2 hours  6 submittals.......              12
                                    information on any
                                    passive acoustic
                                    monitoring system prior
                                    to placing it in
                                    service.
                                  ------------------------------------------------------------------------------

[[Page 79318]]

 
                                   During seismic                 1.5 hours  1,976 reports......           2,964
                                    acquisition operations,
                                    submit to BOEM marine
                                    mammal observation
                                    report(s) semi-monthly
                                    or within 24 hours if
                                    air gun operations were
                                    shut down.
                                  ------------------------------------------------------------------------------
                                   During seismic                 1.5 hours  344 reports........             516
                                    acquisition operations,
                                    when air guns are being
                                    discharged, submit
                                    daily observer reports
                                    semi-monthly.
                                  ------------------------------------------------------------------------------
                                   Observation Duty (3         3 observers x 8 hrs x 365 days = 8,760 hours x 4
                                    observers fulfilling an    vessels observing = 35,040 man-hours x $52/hr =
                                    8-hour shift each for                        $1,822,080.
                                    365 calendar days x 4
                                    vessels = 35,040 man-
                                    hours). This
                                    requirement is
                                    contracted out; hence
                                    the non-hour cost
                                    burden.
----------------------------------------------------------------------------------------------------------------
    Subtotal...............................................................  2,673 responses....           4,012
                                  ------------------------------------------------------------------------------
                                           $1,822,080 Non-hour costs
----------------------------------------------------------------------------------------------------------------
                       Vessel Strike Avoidance and Injured/Protected Species Reporting NTL
----------------------------------------------------------------------------------------------------------------
NTL 2016-G01; 211 thru 228; 241    Notify BOEM within 24             1 hour  1 notice...........               1
 thru 262.                          hours of strike, when
                                    your vessel injures/
                                    kills a protected
                                    species (marine mammal/
                                    sea turtle).
----------------------------------------------------------------------------------------------------------------
    Subtotal...............................................................  1 response.........               1
----------------------------------------------------------------------------------------------------------------
                                                General Departure
----------------------------------------------------------------------------------------------------------------
200 thru 299.....................  General departure and                  2  25 requests........              50
                                    alternative compliance
                                    requests not
                                    specifically covered
                                    elsewhere in Subpart B
                                    regulations.
----------------------------------------------------------------------------------------------------------------
    Subtotal...............................................................  25 responses.......              50
----------------------------------------------------------------------------------------------------------------
        Total Burden.......................................................  4,265 responses....         433,608
                                  ------------------------------------------------------------------------------
                                           $3,939,435 Non-hour costs
----------------------------------------------------------------------------------------------------------------
* The identification number of NTLs may change when NTLs are reissued periodically to update information.

    In addition, the PRA requires agencies to estimate the total annual 
reporting and recordkeeping non-hour cost burden resulting from the 
collection of information, and we solicit your comments on this item. 
For reporting and recordkeeping only, your response should split the 
cost estimate into two components: (1) Total capital and startup cost 
component and (2) annual operation, maintenance, and purchase of 
service component. Your estimates should consider the cost to generate, 
maintain, and disclose or provide the information. You should describe 
the methods you use to estimate major cost factors, including system 
and technology acquisition, expected useful life of capital equipment, 
discount rate(s), and the period over which you incur costs. Generally, 
your estimates should not include equipment or services purchased: (1) 
Before October 1, 1995; (2) to comply with requirements not associated 
with the information collection; (3) for reasons other than to provide 
information or keep records for the Government; or (4) as part of 
customary and usual business or private practices.
    As part of our continuing effort to reduce paperwork and respondent 
burdens, we invite the public and other Federal agencies to comment on 
any aspect of this information collection, including:
    (1) Whether the collection of information is necessary, including 
whether the information will have practical utility;
    (2) The accuracy of our estimate of the burden for this collection 
of information;
    (3) Ways to enhance the quality, utility, and clarity of the 
information to be collected; and
    (4) Ways to minimize the burden of the collection of information on 
respondents.
    Send your comments and suggestions on this information collection 
by the date indicated in the DATES section to the Desk Officer for the 
Department of the Interior at OMB-OIRA at (202) 395-5806 (fax) or via 
the portal at RegInfo.gov (online). You may view the information 
collection request(s) at https://www.reginfo.gov/public/do/PRAMain. 
Please provide a copy of your comments to the BOEM Information 
Collection Clearance Officer (see the ADDRESSES section). You may 
contact Anna Atkinson, BOEM Information Collection Clearance Officer at 
(703) 787-1025 with any questions. Please reference Revisions to the 
Requirements for Exploratory Drilling on the Arctic Outer Continental 
Shelf (OMB Control No. 1014-0151), in your comments.

J. National Environmental Policy Act of 1969 (NEPA)

    BSEE and BOEM developed a draft Environmental Assessment (EA) to

[[Page 79319]]

determine whether this proposed rule would have a significant impact on 
the quality of the human environment under the NEPA. The draft EA is 
available for review in conjunction with this proposed rule at 
www.regulations.gov (in the Search box, enter BSEE-2019-0008).

K. Data Quality Act

    In developing this proposed rule, we did not conduct or use a 
study, experiment, or survey requiring peer review under the Data 
Quality Act (44 U.S.C. 3516 note).

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

    Although this proposed rule is a significant regulatory action 
under E.O. 12866, it is not a significant energy action under the 
definition of that term in E.O. 13211 because:
    1. It is not likely to have a significant adverse effect on the 
supply, distribution or use of energy; and
    2. It has not been designated as a significant energy action by the 
Administrator of OIRA.
    Thus, a Statement of Energy Effects is not required.
    While offshore Arctic OCS oil and gas studies indicate the 
potential of vast resources, there is currently little exploration 
activity and very little production of oil and gas on the Arctic OCS, 
largely due to the inherent practical difficulties of exploration and 
production in the area. The only existing oil production from the 
Arctic OCS is through the Northstar Island facility.

M. Clarity of Regulations

    We are required by E.O. 12866, E.O. 12988, and by the Presidential 
Memorandum of June 1, 1998, to write all rules in plain language. This 
means that each rule we publish must:
    1. Be logically organized;
    2. Use the active voice to address readers directly;
    3. Use clear language rather than jargon;
    4. Be divided into short sections and sentences; and
    5. Use lists and tables wherever possible.
    If you believe we have not met these requirements, send us comments 
by one of the methods listed in the ADDRESSES section. To better help 
us revise the rule, your comments should be as specific as possible. 
For example, you should tell us the numbers of the sections or 
paragraphs that you find unclear, which sections or sentences are too 
long, or the sections where you believe lists or tables would be 
useful.

List of Subjects

30 CFR Part 250

    Administrative practice and procedure, Continental shelf, 
Environmental impact statements, Environmental protection, Government 
contracts, Incorporation by reference, Investigations, Oil and gas 
exploration, Penalties, Pipelines, Public lands-mineral resources, 
Public lands--rights of-way, Reporting and recordkeeping requirements, 
Sulphur.

30 CFR Part 550

    Administrative practice and procedure, Continental shelf, 
Environmental impact statements, Environmental protection, Mineral 
resources, Oil and gas exploration, Pipelines, Reporting and 
recordkeeping requirements, Sulfur.

Katharine MacGregor,
Deputy Secretary, U.S. Department of the Interior.

    For the reasons stated in the preamble, BSEE and BOEM amend 30 CFR 
parts 250 and 550 as follows:

Title 30--Mineral Resources

CHAPTER II--BUREAU OF SAFETY AND ENVIRONMENTAL ENFORCEMENT, DEPARTMENT 
OF THE INTERIOR

SUBCHAPTER B--OFFSHORE

PART 250--OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER 
CONTINENTAL SHELF

0
1. The authority citation for 30 CFR part 250 continues to read as 
follows:

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

0
2. Amend Sec.  250.105 by revising the definition of ``Capping stack'' 
to read as follows:


Sec.  250.105  Definitions.

* * * * *
    Capping stack means a mechanical device that can be installed on 
top of a subsea or surface wellhead or blowout preventer to stop the 
uncontrolled flow of fluids into the environment.
* * * * *
0
3. Amend Sec.  250.175 by adding paragraph (d) to read as follows:


Sec.  250.175  When may the Regional Supervisor grant an SOO?

* * * * *
    (d) For leases or units on the Arctic OCS, you may request, and the 
Regional Supervisor may grant, an SOO when you have conducted 
leaseholding operations during the drilling season immediately 
preceding the period for which you are seeking a suspension, and you 
satisfy one of the following conditions:
    (1) You are conducting drilling operations from a Mobile Offshore 
Drilling Unit (MODU), but you are not able to safely continue 
leaseholding operations due to the presence of seasonal ice;
    (2) You are conducting drilling operations from an artificial 
gravel island or a gravity-based structure, but you are not able to 
safely continue leaseholding operations due to temporary seasonal 
restrictions in your approved oil spill response plan; or
    (3) You are conducting drilling operations from an artificial ice 
island, but you are not able to safely continue leaseholding operations 
due to seasonal temperature changes.
0
4. Amend Sec.  250.198 by revising paragraph (e)(73) to read as 
follows:


Sec.  250.198  Documents incorporated by reference.

* * * * *
    (e) * * *
    (73) API RP 17H, Remotely Operated Tools and Interfaces on Subsea 
Production Systems, Second Edition, June 2013; Errata, January 2014; 
incorporated by reference at Sec. Sec.  250.472(a) and 250.734(a);
* * * * *
0
5. Amend Sec.  250.300 by revising paragraphs (b)(1) and (2) to read as 
follows:


Sec.  250.300  Pollution prevention.

* * * * *
    (b)(1) The District Manager may restrict the rate of drilling fluid 
discharges or prescribe alternative discharge methods. The District 
Manager may also restrict the use of components that could cause 
unreasonable degradation to the marine environment. No petroleum-based 
substances, including diesel fuel, may be added to the drilling mud 
system without prior approval of the District Manager. For Arctic OCS 
exploratory drilling, you must capture all petroleum-based mud to 
prevent its discharge into the marine environment.
    (2) You must obtain approval from the District Manager of the 
method you plan to use to dispose of drill cuttings, sand, and other 
well solids. For Arctic OCS exploratory drilling, you must capture all 
cuttings from operations that use petroleum-based mud to prevent their 
discharge into the marine environment.
* * * * *
0
6. Amend Sec.  250.470 by:
0
a. Revising paragraphs (b)(11) and (12);
0
b. Adding paragraph (b)(13);
0
c. Revising paragraph (f)(3); and

[[Page 79320]]

0
d. Adding paragraph (h).
    The revisions and additions read as follows:


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

* * * * *
    (b) * * *
    (11) Pick up the oil spill prevention booms and equipment;
    (12) Offload the drilling crew; and
    (13) Recover the subsea isolation device (SSID), where applicable.
* * * * *
    (f) * * *
    (3) Where applicable, proof of contracts or membership agreements 
with cooperatives, service providers, or other contractors who will 
provide you with the necessary SCCE or related supplies and services if 
you do not possess them. The contract or membership agreement must 
include provisions for ensuring the availability of the personnel and/
or equipment on a 24-hour per day basis while you are drilling below or 
working below the surface casing, or before the last casing point prior 
to penetrating a zone capable of flowing hydrocarbons in measurable 
quantities, as approved by the Regional Supervisor.
* * * * *
    (h) If you plan to install a subsea isolation device (SSID) on your 
well in accordance with Sec.  250.472(a), a certification signed by a 
registered professional engineer that your SSID and well design 
(including casing and cementing program) meet the design requirements 
in Sec.  250.472 and the design is appropriate for the purpose for 
which it is intended under expected wellbore conditions.
0
7. Amend Sec.  250.471 by revising paragraph (a) introductory text, and 
paragraphs (a)(2) and (3) and (b) to read as follows:


Sec.  250.471  What are the requirements for Arctic OCS source control 
and containment?

* * * * *
    (a) If you use a MODU, you must have access to the SCCE as 
described in paragraphs (a)(1) through (3) of this section capable of 
controlling and containing the flow from an out-of-control well when 
drilling below or working below the surface casing. However, the 
Regional Supervisor will approve delaying access to your SCCE until 
your operations have reached the last casing point prior to penetrating 
a zone capable of flowing hydrocarbons in measurable quantities, 
provided that you submit adequate documentation (such as, but not 
limited to, risk modeling data, off-set well data, analog data, seismic 
data), with your APD, demonstrating that you will not encounter any 
abnormally high-pressured zones or other geologic hazards. The Regional 
Supervisor will base the determination on any documentation you provide 
as well as any other available data and information.
* * * * *
    (2) A cap and flow system that can be deployed as directed by the 
Regional Supervisor pursuant to paragraph (h) of this section. The cap 
and flow system must be designed to capture at least the amount of 
hydrocarbons equivalent to the calculated worst case discharge rate 
referenced in your BOEM-approved EP; and
    (3) A containment dome that can be deployed as directed by the 
Regional Supervisor pursuant to paragraph (h) of this section. The 
containment dome must have the capacity to pump fluids without relying 
on buoyancy.
    (b) You must conduct a monthly stump test of dry-stored capping 
stacks.
* * * * *
0
8. Revise Sec.  250.472 to read as follows:


Sec.  250.472  What are the additional well control equipment or relief 
rig requirements for the Arctic OCS?

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

                        Table 1 to Paragraph (a)
------------------------------------------------------------------------
          Your SSID must
------------------------------------------------------------------------
(1) Be designed to:...............  (i) Close and seal the wellbore,
                                     independent of the BOP;
                                    (ii) Perform under the maximum
                                     environmental and operational
                                     conditions anticipated to occur at
                                     the well;
                                    (iii) Be left on the wellhead in the
                                     event the drilling rig is moved off
                                     location (e.g., due to storms, ice
                                     incursions, or emergency
                                     situations);
                                    (iv) Preserve isolation through the
                                     winter season without relying on
                                     the elastomer elements of the rams
                                     (e.g., by using a well cap) and
                                     allow re-entry during the following
                                     open-water season; and
                                    (v) In the event of a loss of well
                                     control, preserve isolation until
                                     other methods of well intervention
                                     may be completed, including the
                                     need to drill a relief well.
(2) Include the following           (i) Dual shear rams, including ram
 equipment:                          locks; one ram must be a blind
                                     shear ram;
                                    (ii) A redundant control system,
                                     independent from the BOP control
                                     system, that includes ROV
                                     capabilities and a control station
                                     on the rig;
                                    (iii) Independent, dedicated subsea
                                     accumulators with the capacity to
                                     function all components of the
                                     SSID; and
                                    (iv) Two side inlets for
                                     intervention; one inlet must be
                                     located below the lowest ram on the
                                     SSID.
(3) Include ROV intervention        (i) Be able to close each shear ram
 equipment and capabilities. Your    under MASP conditions, as defined
 ROV equipment and capabilities      for the operation;
 must:
                                    (ii) Include an ROV panel that is
                                     compliant with API RP 17H (as
                                     incorporated by reference in Sec.
                                     250.198);
                                    (iii) Meet the ROV requirements in
                                     Sec.   250.734(a)(5); and
                                    (iv) Have the ability to function
                                     the SSID in any environment (e.g.,
                                     when in a mudline cellar).

[[Page 79321]]

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

    (b) Relief Rig. If you choose to satisfy this requirement by having 
access to a relief rig, you must have access to your relief rig at all 
times when you are drilling below or working below the surface casing 
during Arctic OCS exploratory drilling operations. However, the 
Regional Supervisor will approve delaying access to your relief rig 
until your operations have reached the last casing point prior to 
penetrating a zone capable of flowing hydrocarbons in measurable 
quantities, provided that you submit adequate documentation (such as, 
but not limited to, risk modeling data, off-set well data, analog data, 
seismic data), with your APD, demonstrating that you will not encounter 
any abnormally high-pressured zones or other geologic hazards. The 
Regional Supervisor will base the determination on any documentation 
you provide as well as any other available data and information. Your 
relief rig must be different from your primary drilling rig, staged in 
a location, such that it would be available to arrive on site, drill a 
relief well, kill and abandon the original well, and abandon the relief 
well no later than 45 days after the loss of well control.
    (1) Your relief rig must comply with all other requirements of this 
part pertaining to drill rig characteristics and capabilities, and it 
must be able to drill a relief well under anticipated Arctic OCS 
conditions.
    (2) In the event of a loss of well control, the Regional Supervisor 
may direct you to drill a relief well using a relief rig that is able 
to kill and permanently plug an out-of-control well as described in 
your APD.
0
9. Amend Sec.  250.720 by revising paragraph (c)(2) to read as follows:


Sec.  250.720   When and how must I secure a well?

* * * * *
    (c) * * *
    (2) In areas of ice scour, you must use a well mudline cellar or an 
equivalent means of minimizing the risk of damage to the well head and 
wellbore. You may request, and the Regional Supervisor may approve, an 
alternate procedure or equipment in accordance with Sec. Sec.  250.141 
and 250.408.
* * * * *

CHAPTER V--BUREAU OF OCEAN ENERGY MANAGEMENT, DEPARTMENT OF THE 
INTERIOR

SUBCHAPTER B--OFFSHORE

PART 550--OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER 
CONTINENTAL SHELF

0
10. The authority citation for 30 CFR part 550 continues to read as 
follows:

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


Sec.  550.220  [Amended]

0
11. Amend Sec.  550.200 by removing the words ``IOP means Integrated 
Operations Plan.'' in paragraph (a).
0
12. Remove and reserve Sec.  550.204.


Sec.  550.204  [Reserved]

0
13. Amend Sec.  550.206 by revising the section heading, paragraph (a) 
introductory text, and paragraphs (a)(3), (b), and (c) to read as 
follows:


Sec.  550.206  How do I submit the EP, DPP, or DOCD?

    (a) Number of copies. When you submit an EP, DPP, or DOCD to BOEM, 
you must provide:
* * * * *
    (3) Any additional copies that may be necessary to facilitate 
review of the EP, DPP, or DOCD by certain affected States and other 
reviewing entities.
    (b) Electronic submission. You may submit part or all of your EP, 
DPP, or DOCD and its accompanying information electronically. If you 
prefer to submit your EP, DPP, or DOCD electronically, ask the Regional 
Supervisor for further guidance.
    (c) Withdrawal after submission. You may withdraw your proposed EP, 
DPP, or DOCD at any time for any reason. Notify the appropriate BOEM 
Regional Office if you do.
0
14. Amend Sec.  550.211 by redesignating paragraphs (b) through (d) as 
paragraphs (c) through (e), respectively, and adding new paragraph (b) 
to read as follows:


Sec.  550.211  What must the EP include?

* * * * *
    (b) A description of how you will ensure operational safety while 
working in Arctic OCS conditions, including but not limited to:
    (1) The safety principles that you intend to apply to yourself and 
your contractors;
    (2) The accountability structure within your organization for 
implementing such principles;
    (3) How you will communicate such principles to your employees and 
contractors; and
    (4) How you will determine successful implementation of such 
principles.
* * * * *
0
15. Amend Sec.  550.220 by revising the section heading, paragraphs 
(c)(1) and (4), and (c)(6)(ii) to read as follows:


Sec.  550.220  If I propose activities in the Arctic OCS Region, what 
planning information must accompany the EP?

* * * * *
    (c) * * *
    (1) A description of how your exploratory drilling will be designed 
and conducted, (including how all vessels and equipment will be 
designed, built, and/or modified) to account for Arctic OCS conditions 
and how such activities will be managed and overseen as an integrated 
endeavor. In your description of vessel modifications, describe any 
approvals from the flag state and the vessel classification society, 
including any allowances or limitations placed upon the vessel by the 
classification society and/or the United States Coast Guard.
* * * * *
    (4) Additional well control equipment requirements for the Arctic 
OCS. A general description of how you will comply with Sec.  250.472 of 
this title.
    (6) * * *
    (ii) The termination of drilling operations consistent with the 
well control planning requirements under Sec.  250.472 of this title.

[FR Doc. 2020-25818 Filed 12-8-20; 8:45 am]
BILLING CODE 4310-VH-P; 4310-MR-P

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