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DEPARTMENT OF THE INTERIOR Identifier Number (RIN) 1082–AA01 as (907) 334–5300. For technical questions an identifier in your message. For related to regulatory changes BOEM is Bureau of Safety and Environmental comments specifically related to the proposing in Part 550, contact Joel Enforcement draft Environmental Assessment (EA) Immaraj, BOEM, Alaska Regional Office, conducted under the National [email protected], (907) 334– 30 CFR Part 250 Environmental Policy Act of 1969 5238. For procedural questions contact (NEPA), please refer to NEPA in the Bryce Barlan, BSEE, Regulations and Bureau of Ocean Energy Management heading of your message. See also Standards Branch, [email protected], (703) Public Availability of Comments under 787–1126. 30 CFR Part 550 Procedural Matters. SUPPLEMENTARY INFORMATION: • Federal eRulemaking Portal: http:// [Docket ID: BSEE–2019–0008, EEEE500000, Executive Summary 21XE1700DX, EX1SF0000.EAQ000] www.regulations.gov. In the entry entitled, ‘‘Enter Keyword or ID,’’ enter In response to BSEE- and BOEM- RIN 1082–AA01 BSEE–2019–0008, then click search. initiated environmental and safety reviews of potential oil and gas Oil and Gas and Sulfur Operations on Follow the instructions to submit public comments and view supporting and operations on the Arctic OCS, the Outer Continental Shelf—Revisions experiences gained from Shell’s 2012 to the Requirements for Exploratory related materials available for this rulemaking. BSEE and BOEM may post and 2015 Arctic operations, and Drilling on the Arctic Outer Continental concerns expressed by environmental Shelf all submitted comments. • Mail or hand-carry comments to the organizations and Alaska Natives, BSEE AGENCIES: Bureau of Safety and DOI, BSEE and BOEM: Attention: and BOEM published the 2016 Arctic Environmental Enforcement (BSEE); Regulations and Standards Branch, Exploratory Drilling Rule (see 81 FR Bureau of Ocean Energy Management 45600 Woodland Road, VAE–ORP, 46478, July 15, 2016). The rule was (BOEM), Interior. Sterling VA 20166. Please reference RIN narrowly focused, applying solely to exploratory drilling operations ACTION: Proposed rule. 1082–AA01, ‘‘Oil and Gas and Sulfur Operations on the Outer Continental conducted during the Arctic OCS open- SUMMARY: The Department of the Shelf—Revisions to the Requirements water drilling season by drilling vessels Interior (DOI or Department), acting for Exploratory Drilling on the Arctic and ‘‘jack-up rigs’’ (collectively known through BOEM and BSEE, has reviewed Outer Continental Shelf,’’ in your as mobile units or and is proposing to revise its existing comments, and include your name and MODU) in the Beaufort Sea and regulations for exploratory drilling and return address. Chukchi Sea Planning Areas. The related operations on the Arctic Outer • Send comments on the information regulations were intended to ensure that Continental Shelf (OCS), to reduce collection in this rule to: Interior Desk Arctic OCS exploratory drilling unnecessary burdens on stakeholders Officer 1082–AA01, Office of operations are conducted in a safe and while ensuring that energy exploration Management and Budget; 202–395–5806 responsible manner, while taking into on the Arctic OCS is safe and (fax); or via the online portal at account the unique conditions of the environmentally responsible. In RegInfo.gov. Please also send a copy to Arctic OCS, as well as Alaska Natives’ particular, this proposed rule would BSEE and BOEM by one of the means cultural traditions and their need for revise certain requirements promulgated previously described. access to subsistence resources. BSEE through the rule entitled, Oil and Gas • Public Availability of Comments— and BOEM have since reviewed the and Sulfur Operations on the Outer Before including your address, phone 2016 Arctic Exploratory Drilling Rule Continental Shelf-Requirements for number, email address, or other taking into account a Congressional declaration of purposes in the Outer Exploratory Drilling on the Arctic Outer personal identifying information in your Continental Shelf Lands Act (OCSLA) to Continental Shelf (‘‘2016 Arctic comment, you should be aware that ‘‘establish policies and procedures for Exploratory Drilling Rule’’). This your entire comment—including your managing the oil and natural gas proposed rule would also add new personal identifying information—may resources of the Outer Continental Shelf provisions to BSEE’s regulations be made publicly available at any time. which are intended to result in pertaining to suspensions of operations For BSEE and BOEM to withhold from expedited exploration and development (SOO), and BOEM’s Exploration Plan disclosure your personal identifying of the Outer Continental Shelf in order (EP) and Development and Production information, you must identify any to achieve national economic and Plan (DPP) regulations. information contained in the submittal energy policy goals, assure national DATES: Submit comments by February 8, of your comments that, if released, security, reduce dependence on foreign 2021. BSEE and BOEM may not fully would constitute a clearly unwarranted sources, and maintain a favorable consider comments received after this invasion of your personal privacy. You balance of payments in world trade.’’ 1 date. You may submit comments to the must also briefly describe any possible The bureaus have also reviewed new Office of Management and Budget harmful consequence(s) of the information about technological (OMB) on the information collection disclosure of information, such as developments in an ice environment. burden in this proposed rule by January embarrassment, injury, or other harm. Based on that review, BSEE and BOEM 8, 2021. The deadline for comments on While you can ask us in your comment are proposing revisions in this proposed the information collection burden does to withhold your personal identifying rule that are consistent with OCSLA, not affect the deadline for the public to information from public review, we and would reduce unnecessary burdens comment to BSEE and BOEM on the cannot guarantee that we will be able to on stakeholders while still maintaining proposed regulations. do so. safety and environmental protection. ADDRESSES: You may submit comments FOR FURTHER INFORMATION CONTACT: For Since publication of the 2016 Arctic on BSEE’s or BOEM’s sections of the technical questions related to regulatory Exploratory Drilling Rule, new rulemaking by any of the following changes BSEE is proposing in Part 250, methods. For comments on this contact Mark E. Fesmire, BSEE, Alaska 1 Outer Continental Shelf Lands Act, Public Law proposed rule, please use the Regulation Regional Office, [email protected], 95–372, sec. 102 (Sept. 8, 1978), 43 U.S.C. 1802(1)).

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

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

LIST OF ACRONYMS AND REFERENCES

Report to the Secretary of the Interior, review of Shell’s 2012 Alaska Offshore Oil and 60-Day report 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 ...... Preventer. Bratslavsky and SolstenXP, 2018 ...... Suitability of Source Control and Containment Equipment versus Same Season Relief Well in the Alaska Outer Continental Shelf Region, October 2018. BSEE ...... Bureau of Safety and Environmental Enforcement. BLM ...... Bureau of Land Management. CAA ...... Conflict Avoidance Agreement. CFR ...... Code of Federal Regulations. CZMA ...... Coastal Zone Management Act. CWA ...... Clean Water Act. Department ...... Department of the Interior. DNV GL ...... Det Norske Veritas and Germanischer Lloyd. DOCD ...... Development Operations Coordination Document. DOI ...... Department of the Interior. DPP ...... Development and Production Plan. EA ...... Environmental Assessment. EIA ...... Environmental Impact Analysis. EIS ...... Environmental Impact Statement. E.O...... Executive Order. EP ...... Exploration Plan. EPA ...... Environmental Protection Agency. ESA ...... Endangered Species Act. G&G ...... Geological and geophysical. IC ...... Information Collection. ICAS ...... Inupiat Community of the Arctic Slope. IOP ...... Integrated Operations Plan. IRIA ...... Initial Regulatory Impact Analysis. IWC ...... International Whaling Commission. LMRP ...... Lower Marine Riser Package. MASP ...... Maximum Anticipated Surface Pressures. MMPA ...... Marine Mammal Protection Act. MMS ...... Minerals Management Service. MODU ...... Mobile Offshore Drilling Unit.

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LIST OF ACRONYMS AND REFERENCES—Continued

Report to the Secretary of the Interior, review of Shell’s 2012 Alaska Offshore Oil and 60-Day report Gas Exploration Program

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 the Prudhoe Bay State #1 well. BP percent of that amount.4 Currently, the Exploration drilled a confirmation well only offshore Federal production in the A. Overview of the Alaska Arctic Region the following year. However, production Arctic OCS 5 is Hilcorp’s Northstar field, 1. History of Arctic Oil and Gas did not come online until June 20, 1977, which includes both State and Federal Development after the TAPS was completed and other acreage in the 8(g) Zone.6 Located in the Although Alaska’s first oil production companies with lease holdings in the Beaufort Sea about 12 miles northwest is attributable to the 1957 Swanson area undertook a host of activities to of Prudhoe Bay, this prospect has been River discovery on the Kenai Peninsula, delineate the reservoir, resolve equity producing since 2001. Over 150 million oil and gas resources have been known participation, and put together initial barrels of oil have been produced to to exist in the Arctic since as early as infrastructure for the field. After over 40 date at Northstar. In 2019, the Federal 1839. Early explorers had reported that years of production, Prudhoe Bay Government received nearly $5 million Alaska Natives on the Arctic coast used remains the largest oil field in North in royalty payments from oil production on Federal leases at Northstar, and from oil-soaked tundra for fuel. The oil came America and is the 18th largest field 2003 to 2018, royalty payments ranged from natural oil seeps on the ground. ever discovered worldwide.3 According However, the extent of the resource, as to data maintained by the Alaska as the State’s overall oil and gas 4 http://aogweb.state.ak.us/DataMiner3/Forms/ and Gas Conservation Commission, Production.aspx. endowment, would not be realized until Alaska’s North Slope has produced over 5 There are Federal OCS leases that do not have the discovery of the Arctic’s Prudhoe 17.3 billion barrels of oil, with Prudhoe ongoing production in the Cook Inlet, which is not Bay oil field on the North Slope and Bay contributing approximately 68 considered part of the Arctic. completion of the Trans-Alaska Pipeline 6 Section 8(g) of the OCSLA requires the Federal System (TAPS) in 1977. Government to share with the State of Alaska 27% 3 https://dec.alaska.gov/spar/ppr/response/sum_ of revenue from leases in the 8(g) Zone (the first The Prudhoe Bay field was discovered fy06/060302301/factsheets/060302301_factsheet_ three nautical miles of the Outer Continental Shelf). on March 12, 1968, with the drilling of PB.pdf. 43 U.S.C. 1337(g).

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from $3 million to over $20 million in revenue to the State’s budget since 2012 due to a confluence of events, including any given year. In 2019, the Federal is due primarily to declining oil decreased demand from coronavirus Government disbursed just over $1.5 production in the North Slope, but also effects, as well as production output million to the State of Alaska for due to a general downward trend in oil negotiations between OPEC and Russia. Northstar Federal leases in the 8(g) prices. These events caused the to Zone.7 Aside from annual State operating slide to 17-year lows. While prices have The construction of TAPS enhanced and capital budgets, several Statewide already partially recovered and the significance of the Arctic’s government programs established for stabilized, this could affect interest and production to the State of Alaska. TAPS the benefit of the people of Alaska are activity in the region if the low-price is an 800-mile-long pipeline system that largely dependent on oil and gas-related environment continues into the future, was designed to accommodate the revenues, most notably the Alaska as drilling and other exploration transport of over 2 million barrels of oil Permanent Fund. In 1976, Alaska’s State activities in the Arctic are more per day. The pipeline begins at Prudhoe constitution was amended to establish expensive than other regions. Given the Bay and stretches south to Valdez in the Alaska Permanent Fund, which long period of time before exploratory southern Alaska, which is the provides that at least 25 percent of all drilling in the Arctic is expected to start northernmost ice-free port in North mineral lease rentals, royalties, royalty and the short-term nature of the America. TAPS is one of the world’s sale proceeds, Federal mineral revenue underlying price events, the Bureaus largest pipeline systems, an engineering sharing payments, and bonuses received expect that prices will continue to icon that was the biggest privately by the State are to be placed in a rebound. The events in 2020 also funded construction project when it was permanent fund, known as the Alaska underscore the importance of ensuring constructed in the 1970s. At peak flow Permanent Fund, the principal of which that BOEM and BSEE regulations are no in 1988, 11 pump stations helped to is used only for income-producing more burdensome than necessary to move 2.1 million barrels of oil a day.8 investments. All income generated from protect safety and the environment. the permanent fund is available for 2. Budgetary Economic Impact on the 3. Arctic Resource Potential and People of Alaska distribution to all Alaskan residents— Geology adults and children—on an annual basis North Slope Alaska oil and gas through the State’s Permanent Fund The Arctic region is characterized by exploration and production has been a Dividend (PFD) program.11 Since 1978, its extensive oil and gas resources. The significant economic driver, not only to this fund has grown to a total fund value Arctic Alaska Petroleum Province, the State of Alaska and Alaskan Native of $60 billion as of March 2020.12 which consists of up to 43 geologic communities, but also to the national Individual distributions to Alaskans plays between the Chukchi Sea and the domestic energy supply. The State’s oil from the fund have ranged from $386 Beaufort Sea planning areas, extends and gas endowments have provided per person to as high as $2,072 per about 684 miles from the United States- greater economic prosperity to its person.13 These annual payments are Canadian border westward to the people than other important resources estimated to have lifted between 15,000 maritime boundary with Russia, and in the State. Specifically, Alaska relies and 25,000 Alaskans above the Federal from 62 to 372 miles northward from on revenues generated from oil and gas poverty line.14 the Brooks Range to the approximate resources, along with other revenue- Much of the North Slope Borough’s edge of the Continental Shelf. Although generating streams, to fund a major economy is tied to the oil and gas the edge of the Continental Shelf portion of the State’s operating and industry, primarily in the greater provides a well-defined physiographic capital budgets. This has allowed Prudhoe Bay region. Some borough boundary for the province, this edge Alaska to be the only State in the United residents have rotational work in the does not represent a geologic limit to States that does not have either a State oilfields or in a position supporting the potential petroleum resources. The sales tax or personal income tax. Oil and oil industry, but the greatest offshore part of the province is gas revenues are generated by means of contribution to the economy is through characterized by a relatively narrow (62- a variety of taxes, royalties, and other tax revenue. The borough assesses mile-wide) shelf in the Beaufort Sea and charges related to oil and gas property taxes on infrastructure, the a broad (372-mile-wide) shelf in the development and production. Other primary funding source for the Chukchi Sea. The province is bounded examples of revenue-generating streams borough’s operations and capital onshore on the south by the Brooks for Alaska include corporate income, projects, which include building roads, Range-Herald mountain range and fuel, alcohol, and tobacco taxes. In 2016, operating schools, and funding for other offshore to the north by the passive 72 percent of Alaska’s unrestricted public services, such as health clinics continental margin of the Canada general funds, which come from the 16 and fire departments.15 Basin. In general, the formations are State’s overall revenue-generating In March and April of 2020, global oil fairly continuous across the Arctic stream, were derived from oil and gas prices experienced significant volatility Alaska Petroleum Province. revenues and were available to the Although most of the Arctic’s oil 9 State’s budget. In 2012, as much as 93 11 https://apfc.org/frequently-asked-questions/ production to date is attributed to the percent of Alaska’s unrestricted general #why-did-alaskans-create-the-fund. North Slope, most of the undiscovered funds were derived from oil and gas 12 https://apfc.org/our-performance/. resources are located off the Arctic revenues and were also available to the 13 https://pfd.alaska.gov/Division-Info/Summary- coast, within the Chukchi Sea and State’s budget.10 The reduced of-Applications-and-Payments. Beaufort Sea Planning Areas. According contribution of oil and gas-generated 14 Berman, Matt., Random Reamy. ‘‘Permanent to BOEM’s 2016 Assessment of Fund Dividends and Poverty in Alaska.’’ Institute of Social and Economic Research, University of Undiscovered Technically Recoverable 7 https://revenuedata.doi.gov/downloads/ Alaska Anchorage. (November 2016), available Oil and Gas Resources of the Nation’s disbursements/. online at: https://iseralaska.org/static/legacy_ 8 _ _ https://www.alyeska-pipe.com/TAPS. publication links/2016 12-PFDandPoverty.pdf. p. 16 Houseknecht, D.W., and Bird, K.J., 2006, Oil 9 https://www.legfin.akleg.gov/, Budget History 25 of pdf. and gas resources of the Arctic Alaska petroleum Data (Excel) (posted 1–15–2020), Row 59. 15 http://www.north-slope.org/assets/images/ province: U.S. Geological Survey Professional Paper 10 https://www.legfin.akleg.gov/, Budget History uploads/13_Economic_Development_-_NSB_ 1732–A, 11 p., available online at: http:// Data (Excel) (posted 1–15–2020), Row 55. Comprehensive_Plan.pdf. pubs.usgs.gov/pp/pp1732/pp1732a/.

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OCS (mean estimates available at http:// the NPR–A. In addition, USGS’s be developed using existing field- www.boem.gov/National-Assessment- assessment of the 1002 Area 17 of the proven technology, which was 2016/), there are approximately 23.6 ANWR estimated (mean estimates reaffirmed by the NPC 2019 Report billion barrels of undiscovered available at https://pubs.usgs.gov/of/ (NPC 2015 Report at 28). technically recoverable oil and about 2005/1217/pdf/2005-1217.pdf) there are As identified by the NPC, targeted 104.4 trillion cubic feet (TCF) of 7.6 billion barrels of technically potential reservoirs in the Arctic OCS technically recoverable natural gas recoverable oil and 7.04 18 TCF of may be shallow and normally (mean estimates) in the combined technically recoverable natural gas. pressured.20 However, this condition is Beaufort Sea and Chukchi Sea Planning Efforts are already underway to bring not consistent throughout all areas in Areas. BOEM re-assessed its Beaufort some of these new onshore resources the Arctic OCS that have already been Sea Planning Area estimates due to online. Collectively, these offshore and explored. For example, a study recent onshore discoveries in the onshore assets are enormous, and most published by the American Rock National Petroleum Reserve-Alaska of the resources are located offshore.19 Mechanics Association 21 analyzed (NPR–A) from two formations that However, the Arctic OCS’s vast wells drilled in the Chukchi Sea in extended offshore. In December 2017, potential has yet to be realized. order to provide an improved BOEM published its updated re- In the Arctic, the circumstances interpretation and delineation of pore assessment (mean estimates available at associated with drilling from a MODU pressure in the Chukchi shelf region. A https://www.boem.gov/2016a-National- can be different than those in the Gulf majority of the wells contained Assessment-Fact-Sheet/), which of Mexico. The geological pressures in significant overpressure at depths estimated that there are approximately the hydrocarbon bearing zones in the ranging from 1,098 to 2,317 meters (i.e., 24.3 billion barrels of technically shallow seas of Alaska’s Arctic are, in 3,602 to 7,601 feet) subsea. In the recoverable oil and about 104. TCF of many cases, likely to be substantially Beaufort Sea, the Alaska Department of technically recoverable natural gas in lower than those encountered during Natural Resources (ADNR) noted that, as the combined Beaufort Sea and Chukchi the Deepwater Horizon incident, part of its findings to support Beaufort 22 Sea Planning Areas; an increase of about reducing certain risk factors of a major Sea areawide oil and gas lease sales, 680 million barrels of oil and 100 billion blowout. As reviewed by the NPC, operators may reasonably expect to cubic feet of natural gas. Of the 24.3 through the NPC 2019 Report, encounter extremely high pore billion barrels of oil, the Chukchi Sea subsurface conditions (below the pressures along the central Beaufort Sea Planning Area makes up about 63% of seafloor) for the Arctic OCS—geology, region where ‘‘ . . . Cenozoic strata the estimate, while the Beaufort Sea pressure, resource depth, and drilling (sedimentary layers) are very thick, such Planning Area makes up 37%. With depth—are much simpler as compared as in the Kaktovik, Camden, and Nuwuk respect to gas, the Chukchi Sea Planning to other areas, such as the deepwater Basins,’’ and suggests that challenges Area makes up about 73% of the 104.5 OCS. The NPC 2019 from over pressured areas could be TCF of gas and the Beaufort Sea Report states that the targeted Arctic reduced by ‘‘. . . identifying locations Planning Area makes up 27% of the potential reservoirs are shallow and of overpressured sediments via seismic estimate. These estimates represent normally pressured, but that exploration data analysis, and then adjusting the about one-quarter of the technically and development are dominated by mud mixture accordingly as the well is recoverable oil resources and one-third other challenges, such as water depth, drilled.’’ In the Point Thomson area, for of the technically recoverable gas ice conditions, and the length of the example, where drilling has taken place from an onshore facility into a reservoir resources on the OCS. open-water season, which make the Arctic unique (NPC 2019 Report at 10). located primarily offshore, the pore While not as large, the Arctic’s The NPC 2015 Report found, however, pressure gradients were measured as onshore undiscovered oil and gas that most of the U.S. Arctic offshore high as 0.8 pounds per square inch per resources are also considerable. In conventional oil and gas potential can foot (psi/ft) at depths of 2.5 miles January 2020, the United States (13,200 feet). A pore pressure gradient Geological Survey (USGS) published an 17 The Alaska National Interest Lands of 0.433 psi/ft is considered normal in assessment of undiscovered oil and gas Conservation Act (ANILCA) of 1980 required this area.23 resources in the central portion of the ANWR to be managed as a protected wilderness. Section 1002 of ANILCA, however, deferred a Alaska North Slope, (mean estimates 20 ‘‘Normally pressured’’ is not defined in the decision regarding future management of a 1.5 NPC 2019 Report. However, as a general matter, available at https://pubs.usgs.gov/fs/ million-acre coastal plain portion of ANWR (known 2020/3001/fs20203001.pdf). The normal pressure generally refers to the hydrostatic as the ‘‘1002’’ area) in order to continuously study pressure within a well. ‘‘Normally pressured’’ refers assessment estimated that there are the various natural resources on the coastal plain, to conditions present when formation pressures are approximately 3.6 billion barrels of and analyze how oil and gas exploration, predictable at any given depth and follow a normal development, and production could potentially formation pressure gradient or ‘‘hydrostatic undiscovered technically recoverable oil impact those resources. Section 20001 of the Tax and about 8.9 TCF of undiscovered pressure gradient.’’ Normal formation pressure, at Cuts and Jobs Act of 2017 lifted a provision in any given depth, equals the normal formation technically recoverable natural gas Section 1003 of ANILCA that prohibits oil and gas pressure gradient multiplied by the depth. The resources on State and Native lands, and leasing and production in the 1002 area, and the normal pressure is expressed in pounds per square State waters, east of the NPR–A and BLM is in the process of developing an oil and gas inch (psi). leasing program for that area. 21 west of the Arctic National Wildlife Elowe, K.E., & Sherwood, K.W., 2017, 18 This value represents the combined estimates ‘‘Abnormal Formation Pressure in the Chukchi Refuge (ANWR). According to a 2017 of natural gas that could technically be produced Shelf, Alaska,’’ American Rock Mechanics USGS assessment of undiscovered oil from gas fields as well as associated gas that could Association Conference Paper, Document ID and gas resources in the Alaska North be produced from oil fields. ARMA–2017–0194, available online at https:// 19 D.L. Gautier et al., ‘‘Circum-Arctic Resource www.onepetro.org/conference-paper/ARMA-2017- Slope, (mean estimates available at Appraisal: Estimates of Undiscovered Oil and Gas 0194. https://pubs.usgs.gov/fs/2017/3088/ North of the Arctic Circle,’’ U.S. Geological Survey, 22 Alaska Department of Natural Resources, 2019, fs20173088.pdf), there are USGS Fact Sheet 2008–3049, 2008. M.E. Brownfield ‘‘Beaufort Sea Areawide Oil and Gas Lease Sales,’’ approximately 8.8 billion barrels of et al., ‘‘An Estimate of Undiscovered Conventional p. 3–20, available online at https://aws.state.ak.us/ undiscovered technically recoverable oil Oil and Gas Resources of the World,’’ U.S. OnlinePublicNotices/Notices/View.aspx?id=193811. Geological Survey, USGS Fact Sheet 2012–3024, 23 Craig, J.D., K.W. Sherwood, and P.P. Johnson. and about 39 TCF of undiscovered 2012, available at https://pubs.usgs.gov/fs/2008/ 1985. Geologic report for the Beaufort Sea planning technically recoverable natural gas in 3049/fs2008-3049.pdf. Continued

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While these reports’ findings do not oil-bearing zones were located.26 The offshore oil exploration and fully align with the NPC’s findings, Bureaus have the means, through access development on the bowhead whale. there are other sources of information to relevant geological and geophysical Whalers observed how bowhead whales confirming that, to a certain degree, (G&G) data and drilling application were responding to the presence of typical geologic conditions in the Arctic regulatory reviews, to confirm that ocean-going oil and gas industry OCS are normally pressured. For operators identify and plan for these exploration vessels, which were making example, a BOEM report that studied potential risks. For example, the the whales skittish and affecting the the Chukchi Sea’s Burger gas discovery bureaus confirm that operators have whalers’ ability to effectively meet the calculated the pore pressure gradient for properly designed well casing and quotas for their communities. In one of the Chukchi Sea wells in the drilling programs and ensure that response, the AEWC worked with study to be 0.44 psi/ft up to 4,850 feet operators have access to properly industry stakeholders to establish the subsea, which the report determined to designed equipment that is readily ‘‘Oil/Whaler Agreement,’’ which was a be normally pressured. However, available to quickly respond to an communication plan between whalers beneath 4,850 feet, the pore pressure incident, such as the availability of a and exploration vessels that was gradient became over-pressurized capping stack in advance of drilling into intended to prevent direct threats to the having a pore pressure gradient of 0.88 the targeted productive zones. whalers’ safety from industry vessels. psi/ft.24 For the Beaufort Sea, a USGS The AEWC and industry stakeholders report analyzed pressure data from five 4. Partnership With Alaska Natives in eventually turned the ‘‘Oil/Whaler offshore wells and found that the Northern Alaska Agreement’’ into a framework for pressures in the area where the wells The bowhead whale provides the understanding and addressing indirect were located were normally pressured largest subsistence resource available to interference with hunting activities, (i.e., at hydrostatic pressure) up to 2,000 the native villages of Alaska’s northern resulting from behavioral changes in feet subsea, and increased only slightly shores. In 1977, Eskimo whalers from bowhead whales as they react to the above hydrostatic pressure deeper into these villages established the Alaska noise and other pollutants the well. By 10,000 feet, however, the Eskimo Whaling Commission (AEWC), accompanying oil and gas work. This pressure in all five wells were over- whose mission is to safeguard the framework of understanding eventually pressured, 1.5 times higher than the bowhead whale and its habitat, defend formed the basis of what is now known hydrostatic pressure.25 Over-pressure the Aboriginal Subsistence Whaling as a CAA.27 While DOI does not require started to occur at around 6,700 feet Rights of their members, and preserve executing a CAA, BSEE and BOEM subsea. the cultural and traditional values of highly encourage operators to work with While it is not possible to confirm their villages. Eskimo whalers the AEWC to establish CAAs, since that all targeted potential reservoirs established the AEWC in response to these agreements essentially would be shallow and normally actions taken by the International acknowledge, within CAA provisions, pressured in all exploratory drilling Whaling Commission (IWC) that that both subsistence hunting activities situations, BSEE and BOEM will have resulted in the IWC’s assumption of and oil and gas development can and access to the relevant geologic and direct jurisdiction over the Alaskan should coexist. See discussion in geophysical information to help identify Native bowhead whale subsistence Section I.E.3, History and Background hydrocarbon bearing zones and zones hunt, without Alaska Native input. The on the Conflict Avoidance Agreement, with potential geologic risk, such as IWC assumed direct jurisdiction over of this preamble describing the over-pressurized zones, that may be Alaska Native’s bowhead whale provisions typically included in a CAA. encountered during drilling operations. subsistence in response to the IWC’s This longstanding process allows for These higher pressured, hydrocarbon concerns regarding the decline in the industry representatives to sit, in zones are, in fact, the targeted western Arctic bowhead whale stock. council, with members of the AEWC, formations the industry has attempted The IWC’s only mechanism for local tribes, and village and regional to produce. For example, the BOEM protecting whale stocks is the setting of corporations to determine cultural report analyzing the Chukchi Sea’s hunting quotas. Therefore, the IWC’s circumstances and situations that could Burger gas discovery illustrated the only recourse for addressing its cause conflict—and thus avoid them. regional geology of all the wells concerns was to prohibit the Alaska For example, during whale (or walrus) included in the study, and showed that Native bowhead whale subsistence hunting seasons in the spring and fall, the higher pressured zones in the wells hunt. This action devastated local the CAA may include provisions occurred at the same point where the communities, creating immediate and whereby industry will avoid severe food shortages. In response, in construction or production noise and area, Alaska: Regional geology, , 1981, the AEWC was able to establish an related activities during those times environmental geology. U.S. Department of the Interior, Minerals Management Service, Alaska OCS agreement with the Federal Government when whales are transiting nearby, and Region, OCS Report MMS 85–0111. Anchorage, to co-manage the bowhead whale the hunters are in the area. With this Alaska. https://www.boem.gov/BOEM-Newsroom/ _ hunting quotas. early initiative, direct collaboration with Library/Publications/1985/85 0111.aspx. Although the AEWC was able to local hunters, specifically the whaling 24 Craig, J.D., & Sherwood, K.W., 2001 (revised 2004), ‘‘Economic Study of the Burger Gas regain control of its bowhead whale captains and their representative Discovery, Chukchi Shelf, Northwest Alaska,’’ U.S. hunting quotas, the organization shared organization, the AEWC, became a Department of the Interior, Minerals Management a similar concern with the IWC critical element of offshore industrial Service, p. 67, available online at https:// regarding the potential effects of www.boem.gov/sites/default/files/boem-newsroom/ development planning and management Library/Publications/2004/Economic-Study-of-the- in the Alaskan Arctic. Burger-Gas-Discovery.pdf. 26 Craig, J.D., & Sherwood, K.W., 2001 (revised Today, the AEWC includes registered 25 Hayba, D.O., Houseknecht, D.W., and Rowan, 2004), ‘‘Economic Study of the Burger Gas whaling captains and their crews from E., 1999, ‘‘Stratigraphic, Hydrogeologic, and Discovery, Chukchi Shelf, Northwest Alaska,’’ U.S. eleven whaling communities of the Thermal Evolution of the Canning River Region, Department of the Interior, Minerals Management North Slope, Alaska,’’ U.S. Department of the Service, p. 72, available online at https:// Interior, U.S. Geological Survey, p. FF–21, available www.boem.gov/sites/default/files/boem-newsroom/ 27 Conflict Avoidance Agreements are contracts online at https://pubs.usgs.gov/of/1998/ofr-98- Library/Publications/2004/Economic-Study-of-the- signed by the operators and the Alaska native 0034/FF.pdf. Burger-Gas-Discovery.pdf. communities to which BOEM is not a party.

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Arctic Alaska coast: Gambell, Savoonga, field) was made in State waters, the day.30 The price of oil increased steadily Wales, Little Diomede, Kivalina, Point Department, acting through the Bureau through 2007 from approximately $50 to Hope, Point Lay, Wainwright, Barrow 28 of Land Management (BLM), held the $90 per barrel by the time the most (Utquiavik), Nuiqsut, and Kaktovik. The first oil and gas lease sale in the Arctic recent Arctic sale, Lease Sale 193, was AEWC often represents the Inupiat OCS, offering tracts adjacent to Prudhoe held in February of 2008.31 These Community of the Arctic Slope (ICAS) Bay in the Beaufort Sea Planning Area. market factors may have contributed to in matters pertaining to energy That sale resulted in 24 leases, covering the outcome of Lease Sale 193, one of exploration or development specifically 85,776 acres, being issued. Although it the most successful in Arctic OCS for the OCS. The ICAS is a unique was the first sale ever conducted for the history, based on multiple metrics—the federally recognized tribal entity. ICAS Arctic OCS, the revenues generated number of bids received, the number of membership is based on an individual’s from that sale, over $491 million, make tracts receiving bids, and the total ancestral lineage to a village tribe; it it the 4th largest sale in Arctic OCS amount of bonus bids received from the includes the peoples of eight Native history. That dollar amount would sale. The MMS received a total of 667 Villages: Kaktovik, Atqasuk, Nuiqsut, represent almost $1.9 billion dollars in bids on 488 blocks; both record-setting Anaktuvuk Pass, Barrow, Wainwright, 2019 after adjusting for inflation. numbers for the Arctic OCS. A total of Point Lay, and Point Hope. Each village Between 1979 and 2008, the 487 leases, covering over 2.7 million tribe acts independently but will Department, acting through the BLM acres, were issued, and the sale interact with ICAS and its membership and Minerals Management Service generated over $2.6 billion in bonus 29 as it relates to Federal and State energy (MMS), held 13 oil and gas lease sales, bids, which went to the U.S. Treasury. issues. and issued nearly 1,800 leases, covering Since 2008, however, the Department Conflict avoidance tools are often over 9.7 million acres, on the Arctic has not conducted any new lease sales incorporated into leasing stipulations OCS. These sales generated over $6.8 for the Arctic OCS. A description of the billion in bonus bids. As many as 23 addressing consultation with status of active leases in the Artic OCS companies/bidders have participated in subsistence communities, and will is discussed in further detail below an Alaska OCS lease sale and, while the continue to be essential to help satisfy within this subsection, prior to the number of companies/bidders the need to provide a secure source of subheading entitled, Global Arctic participating from one sale to the next energy for the Nation while at the same Exploration Activities. time protecting the subsistence varied, an average of 10 companies/ resources and uses of the local bidders participated in each sale. Sale 193 was significant, not only in communities where these energy By 2008, U.S. oil production had been number of tracts sold and the amount resources are located. steadily declining for 5 years to an received from the sale, but in that the average of 5 million barrels per day, industry’s interest spurred a flurry of 5. Industry Interest in the Arctic OCS while U.S. consumption of crude oil activities on the Arctic OCS prior to and In 1979, a year after the first Arctic and petroleum products reached an all- after the sale. The following table lists offshore discovery (i.e., the Endicott oil time high of 20.68 million barrels per 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; ; Shell; ConocoPhillips; 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 geo- physical 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 lo- cated in the Chukchi Sea Planning Area.

28 Although the Alaska Native tribe is based in group of whaling captains collectively by the table entitled, ‘‘U.S. Product Supplied of Crude Oil Utquiavik, at any given time, the whaling may broader term ‘‘Barrow.’’ and Petroleum Products (Thousand Barrels per involve members of the Apugauti and Nalukatq 29 MMS was the predecessor agency of BSEE and Day)’’. tribes, whose native lands do not border the coast. BOEM. 31 https://www.eia.gov/dnav/pet/hist/ 30 For this reason, the AEWC prefers to refer to this https://www.eia.gov/dnav/pet/hist/ LeafHandler.ashx?n=PET&s=F000000__3&f=M. LeafHandler.ashx?n=PET&s=MTTUPUS2&f=A,

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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 Bu- reau 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 identi- fied 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 pub- lic 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 plan- ning 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 information into a Supplemental EIS per day in 2015 and 12.2 million barrels length of time taken to authorize Shell’s that was published in February 2015 in 2019.33 Demand for oil remained exploration drilling activities was a and affirmed the sale as held. Only relatively stable between 2008 and 2019, lawsuit filed by the Native Village of thereafter were BOEM and BSEE able to with only a minor increase in 2019 over Point Hope challenging the complete their formal review of Shell’s 2008—approximately a 4% increase.34 Department’s decision to hold Sale 193. exploration plan for the Chukchi Sea On September 28, 2015, Shell See Native Village of Point Hope v. and approve the drilling activities that announced that it would cease further Salazar, 730 F. Supp.2d 1009 (D. Ak., took place in the summer of 2015. exploration activity in offshore Alaska 2010); see also Native Village of Point Between 2008 and 2019, oil prices for the foreseeable future. Shell stated Hope v. Jewell, 740 F.3d 489 (9th Cir., remained unstable, increasing to an all- that its decision was based on the time high of almost $96 per barrel in results of their Burger J well, which 2014). The original Environmental 2013 to $44 per barrel in 2015, which found indications of oil and gas, but Impact Statement (EIS) for Sale 193 was increased to $56 per barrel in 2019.32 were insufficient to warrant further published in 2007, and the lease sale Domestic oil production had grown was held, but subsequent legal since 2008, in part due to developments 33 https://www.eia.gov/todayinenergy/ challenges and Federal court decisions in onshore and Gulf of Mexico detail.php?id=4910. 34 remanded the lease sale to BOEM for production, to about 9.4 million barrels https://www.eia.gov/dnav/pet/hist/ further analysis. In response to the court LeafHandler.ashx?n=PET&s=MTTUPUS2&f=A, table titled ‘‘U.S. Product Supplied of Crude Oil remand, BOEM conducted additional 32 https://www.eia.gov/dnav/pet/hist/ and Petroleum Products (Thousand Barrels per analysis and incorporated that LeafHandler.ashx?n=PET&s=F000000__3&f=M. Day).

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exploration in the Burger prospect. The icebergs that may impact their requirements from these countries that company also stated that its decision exploration operations. Operators also pertain to relief wells, SCCE, and was motivated by the high costs have contingency plans that may require approval of alternative technologies. associated with the project, and the disconnecting their drilling rig from the The study did not include Russia in its challenging and unpredictable Federal well and moving off location to avoid review because the country’s regulations regulatory environment offshore contact with icebergs. could not be accessed. Here is a Alaska.35 On November 17, 2015, Statoil Canada—In the Jeanne d’Arc, Orphan, summary of that review: announced its decision to exit Alaska and Flemish Pass oil and gas basins on • Relief Wells—All the Arctic and relinquish its leases acquired from the Grand Banks of Newfoundland, countries that were reviewed Sale 193. All leaseholders that acquired operators have conducted exploration specifically require relief wells, but leases in Sale 193 eventually drilling from MODUs in shallow and regulations among them differ. For relinquished their leases. deep waters. Like Greenland, the areas example, Canada simply requires a Despite these setbacks, industry with oil and gas potential are located in ‘‘same-season’’ relief well capacity, interest in the Arctic OCS and other sub-Arctic regions that experience some whereby the operator demonstrates its areas of the Arctic, globally, has shown seasonal sea ice and significant iceberg capability to drill a relief well and kill to be consistent amidst fluctuating incursions. In these areas, operators also an out-of-control well in the same commodity prices and concerns about employ strong ice management and drilling season. Whereas the U.S. regulatory challenges. Since 1998, contingency plans. requires the ability to bring in a nineteen geological and geophysical Norway—In Norway’s portion of the relief-drilling rig and complete the plug seismic surveys were permitted and Barents Sea, which is located entirely and abandonment within 45 days, completed for the Beaufort Sea and within the Arctic, exploration activities Norway and Greenland require a Chukchi Sea Planning Areas. The data have taken place since 1980. Most of the relief-drilling rig to be on site within 12 from these surveys provide information area is free of sea ice year-round, but days. • to both industry and the government for drilling has taken place in areas that do SCCE—Canada is the only country use in lease sales and for design and experience challenging Arctic OCS besides the U.S. that has specific SCCE evaluation of activities described in EPs conditions. As late as 2014, exploration requirements. Canada’s requirements, and DPPs. Several different companies drilling took place in Norway’s northern however, are less prescriptive in that participated in each of the four Beaufort portion of the Barents Seas in what is they include a more general requirement Sea Planning Area lease sales and the known as the Hoop area. Those for ‘‘cap and containment methods and one Chukchi Sea Planning Area lease exploration operations entailed the use same- methods,’’ as sale indicating on-going industry of winterized semisubmersible rigs and compared to the U.S. requirement for interest in the area. Companies the availability of a capping stack. access to specific SCCE equipment Russia—Russia’s latest drilling submitted EPs, three in the Beaufort and within a specified time period. operations also took place in 2014 when • one in the Chukchi Sea. These plans, Alternative Technologies—With ExxonMobil drilled a well in the South and their revisions, received evaluation respect to approval of alternative Kara Sea. The operation took place in an and conditional approval. BOEM technologies in lieu of a relief rig or area of the Arctic where drilling could approved two DPPs, both for the SCCE, the U.S. has specific regulations not take place during the winter Beaufort Sea. Currently, there are 19 oil that allow for potential substitutions months, similar to the Chukchi and and gas leases in the Arctic OCS, all of and accommodations for innovative Beaufort Seas. Exploration activities which are located in the Beaufort Sea technologies. Canada also provides for took place during the summer, when Planning Area. Exploratory drilling and the approval of alternative technologies little to no sea ice was present at the development on these leases have taken through specific approval processes. drilling location and were completed in place from gravel islands in State Norway’s regulations, in general, are mid-fall. The operation was similar to waters. largely performance-based. As such, the operations from the other countries their regulations allow for the Global Arctic Exploration Activities just described—a winterized MODU and consideration of different technologies In addition to the Arctic OCS robust ice management and contingency at the onset when planning a project. plans. However, unique to this project activities just described, global interest B. BSEE and BOEM Statutory and and development has taken place in was the use of a subsea isolation device (SSID). (NPC Report 2015 at 6–17 and Regulatory Authority and other parts of the Arctic. Countries, such Responsibilities as Russia, Norway, Canada, and 6–18, and NPC Report 2019 at C–10). The Outer Continental Shelf Lands Greenland have been diligently The Kara Sea project is discussed in Act, 43 U.S.C. 1331 et seq., was first exploring their oil and gas resources in more detail below in Section II. Section- enacted in 1953 and substantially or near the Arctic. by-Section Discussion of Proposed Greenland—Since the 1970s, Changes, Subsection A. Key Revisions amended in 1978. In amending OCSLA, exploration activities have taken place Proposed by BSEE, under the Congress established a national policy on the offshore waters of western subheading entitled, Supplemental of making the OCS ‘‘available for Greenland. While these exploration Assessment to the 2015 Report on Arctic expeditious and orderly development, activities have taken place in sub-Arctic Potential: Realizing the Promise of U.S. subject to environmental safeguards, in regions, operators do experience some Arctic Oil and Gas Resources (NPC 2019 a manner which is consistent with the of the key challenges present in the Report). maintenance of competition and other national needs.’’ (43 U.S.C. 1332(3)). Arctic. It is not uncommon for icebergs Global Arctic Exploration Requirements to pose dangers to drilling operations. OCSLA authorizes the Secretary of the Norway, Canada, and Greenland have Operators use ice management plans to Interior (Secretary) to lease the OCS for similar regulatory requirements to the identify, monitor, and tow away any mineral development and to regulate oil United States for Arctic offshore drilling and gas exploration, development, and 35 https://www.shell.com/media/news-and-media- operations performed from a MODU. production operations on the OCS. releases/2015/shell-updates-on-alaska- The Bratslavsky and SolstenXP study On May 19, 2010, Secretary Ken exploration.html. also included a review of the regulatory Salazar issued S.O. 3299, which

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restructured and divided the former activities within BOEM’s activities and exploratory drilling. After BOEM MMS’s responsibilities under OCSLA areas of responsibility. approves the EP, the operator must among three new bureaus: (i) BOEM; (ii) Secretary’s Order 3299 made BSEE submit to BSEE an APD, which BSEE BSEE; and the (iii) Office of Natural responsible for safety and must approve before an operator may Resources Revenue (ONRR). S.O. 3299 environmental enforcement functions, drill a well (43 U.S.C. 1340(d); delegated those responsibilities for oil including, but not limited to, the § 250.410). Among other things, the and gas operations to BSEE and BOEM, authority to permit activities, inspect, APD must be consistent with the both of which are charged with investigate, summon witnesses and approved EP and include information administering and regulating aspects of produce evidence: Levy penalties; on the well location, the drilling design the Nation’s OCS oil and gas program cancel or suspend activities; and and procedures, casing and cementing (see 30 CFR parts 250 and 550). oversee safety, and oil spill response programs, the diverter and blowout and removal preparedness. BSEE’s preventer (BOP) systems, MODU (if one On June 18, 2010, Secretary Salazar mission is to promote safety, protect the is to be used), and any additional issued S.O. No. 3302, which announced environment, and conserve resources information requested by the BSEE the name change of part of the former through vigorous regulatory oversight District Manager. MMS to the Bureau of Ocean Energy and enforcement. BSEE’s functions Management, Regulation and include evaluating permit applications C. Executive and Secretary’s Orders Enforcement (BOEMRE). This name, for post-lease oil and natural gas On March 28, 2017, the President BOEMRE, would remain in effect until exploration and development activities issued E.O. 13783—Promoting Energy BOEM and BSEE were officially created on the OCS and conducting inspections Independence and Economic Growth under S.O. 3299, effective October 1, to ensure compliance with laws, (82 FR 16093). The E.O. directed 2011. regulations, lease terms, and approved Federal agencies to review all existing On October 1, 2010, the revenue- plans and permits. regulations and other similar agency collection functions of the former MMS BOEM evaluates EPs, and BSEE, actions, which potentially burden the were transferred to ONRR, reporting to thereafter, evaluates Applications for development or use of domestically the Assistant Secretary for Policy, Permits to Drill (APDs) and other produced energy resources with the goal Management and Budget. permits and applications, to determine of ‘‘avoiding regulatory burdens that whether the operator’s proposed unnecessarily encumber energy S.O. 3299 assigned BOEM the activities meet OCSLA’s standards and production, constrain economic growth, responsibility for managing the each Bureau’s regulations governing and prevent job creation.’’ It made it development of the Nation’s offshore OCS exploration. Based on their U.S. policy for agencies to ‘‘review conventional and renewable energy respective evaluations, BSEE and BOEM existing regulations that potentially resources. BOEM’s mission is to manage will either approve the operator’s EP burden the development or use of the development of the OCS energy and and APD, require the operator to modify domestically produced energy resources mineral resources in an environmentally its submissions, or disapprove the EP or and appropriately suspend, revise, or and economically responsible way. APD (§ 250.410, How do I obtain rescind those that unduly burden the BOEM’s functions include: Leasing; EP approval to drill a well?). The review development of domestic energy administration; DPP administration; and approval of these activities is resources beyond the degree necessary permitting of geological and geophysical outlined below in the following section. to protect the public interest or activities; environmental analyses in otherwise comply with the law.’’ compliance with NEPA; environmental 1. BOEM Approval of the EP On April 28, 2017, the President studies; compliance with relevant laws As promulgated through the 2016 issued E.O. 13795—Implementing an (e.g., the Endangered Species Act (ESA), Arctic Exploratory Drilling Rule, America-First Offshore Energy Strategy the Marine Mammal Protection Act, the § 550.204, When must I submit my IOP (82 FR 20815), which directed the Magnuson-Stevens Fishery for proposed Arctic exploratory drilling Secretary to ‘‘take all steps necessary to Conservation and Management Act, and operations and what must the IOP review’’ the 2016 Arctic Exploratory the Coastal Zone Management Act 36 include?, requires that a lessee submit Drilling Rule and, ‘‘if appropriate, [to,] (CZMA)); resource evaluation; oil spill an IOP at least 90 days before filing an as soon as practicable and consistent worst case discharge (WCD) EP with BOEM, if that EP would involve with law, publish for notice and determination; economic analysis and exploration for oil and gas on the Arctic comment a proposed rule suspending, fair market value bid/lease evaluations; OCS. While the IOP is not subject to revising, or rescinding this rule.’’ The management of the OCS renewable approval, the submission was intended policy underlying E.O. 13795 is ‘‘to energy and marine mineral programs; to facilitate the prompt sharing of encourage energy exploration and and consultation with other entities at information among the relevant Federal production, including on the Outer the local (e.g., North Slope Borough, agencies that may be involved in Continental Shelf, in order to maintain Native Villages), tribal (e.g., Federally overseeing exploratory drilling the Nation’s position as a global energy recognized tribes and Alaska Native operations conducted from MODUs. The leader and foster energy security and Claims Settlement Act Corporations), operator may then submit an EP to resilience for the benefit of the State, and Federal levels (e.g., National BOEM for approval. An EP must include American people, while ensuring that Oceanic and Atmospheric information such as a schedule of any such activity is safe and Administration (NOAA) Fisheries, U.S. anticipated exploration activities, environmentally responsible.’’ These Coast Guard (USCG)) related to equipment to be used, the general E.O.s did not dictate outcomes; rather, location of each well to be drilled, and they provided direction for review in 36 BOEM is not subject to the requirements of the any other information deemed pertinent accordance with all relevant laws. CZMA in Alaska as it is on the rest of the OCS, by BOEM (§§ 550.211 through 550.228). To further implement E.O. 13795, on where it is required to provide opportunities to the May 1, 2017, the Secretary issued S.O. coastal State to review the proposed Federal actions 2. BSEE Approval of the APD for consistency with the state’s federally approved 3350, America-First Offshore Energy coastal management program. More specifically, on Approval of an EP does not, by itself, Strategy, directing BSEE and BOEM to July 1, 2011, Alaska repealed its CZMA program. permit the operator to proceed with review the 2016 Arctic Exploratory

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Drilling Rule ‘‘for consistency with the there is also a greater probability for safe addressed by the 2016 Arctic policy set forth in section 2 of E.O. deployment of a relief rig versus SCCE. Exploratory Drilling Rule, they are 13795’’ and to prepare a report In the Beaufort Sea, the probability for unique to the Arctic OCS and, therefore, ‘‘summarizing the review and providing safely deploying relief wells and SCCE are appropriate to address as part of this recommendations on whether to is the same. This is because the Beaufort proposed rulemaking. suspend, revise, or rescind the rule.’’ Sea has fewer ice-free days than the BSEE and BOEM recognize that the Consistent with E.O.s 13783 and Chukchi and ice helps maintain calm 2016 Arctic Exploratory Drilling Rule 13795, and S.O. 3350, BSEE and BOEM sea state conditions. addressed specific operational and reviewed the regulations promulgated The study also determined that water environmental conditions that are through the 2016 Arctic Exploratory depth in the Arctic OCS is also a factor unique to the Arctic OCS. While this Drilling Rule and are proposing limiting the safe deployment of SCCE. proposed rule would leave most of the revisions to those regulations to reduce According to the Bratslavsky and regulations promulgated by the 2016 unnecessary burdens on industry while SolstenXP study, safe deployment of rule unaltered, certain of these maintaining safety and environmental SCCE is likely to be impaired in water regulations are worth reconsidering to protection. depths shallower than 984 feet because accommodate technological innovation the equipment would potentially and encourage energy exploration on D. Purpose and Summary of the encounter a gas boil at the surface the Arctic OCS. Based on the new Rulemaking caused by a subsea blowing well scientific information gathered from the BSEE and BOEM promulgated the (Bratslavsky and SolstenXP at 143). Bratslavsky and SolstenXP study, and 2016 Arctic Exploratory Drilling Rule Water depths in the majority of the global practical experience gained in based on experiences gained from Chukchi Sea and Beaufort Sea where recent years, as described in the NPC Shell’s 2012 and 2015 Arctic operations, exploration has historically occurred are Reports, the bureaus believe that these internal reviews conducted on potential relatively shallow—167 feet or less (id. proposed revisions reduce unnecessary oil and gas operations on the Arctic at 7 to 9). This water depth range limits regulatory burdens on stakeholders and OCS, and concerns expressed by the fleet of support vessels that could be increase the ability to review and apply environmental organizations and Alaska used for the safe deployment of SCCE. advancing technological innovations, Natives. The NPC also published its NPC 2019 while ensuring safety and Since publication of the 2016 Arctic Report as a supplemental assessment to environmental protection. Exploratory Drilling Rule, however, the NPC 2015 Report. The NPC prepared The following paragraphs briefly BSEE and BOEM have become aware of the NPC 2019 Report in response to an summarize the key elements of this additional information informing and April 2018 request from the Secretary of proposed rule, which are more fully warranting the bureaus’ reconsideration Energy. The Secretary of Energy explained in Section II. Section-by- of certain regulatory provisions requested that the NPC provide Section Discussion of Proposed Changes promulgated through that rule. BSEE recommendations for enhancing the of this preamble: commissioned a Technology Nation’s regulatory environment by 1. Seasonal Conditions SOO—The Assessment Program study (Bratslavsky improving reliability, safety, efficiency, unique seasonal conditions in the Arctic and SolstenXP, 2018) that entailed a and environmental stewardship of oil make it difficult or physically historical statistical analysis of recent and gas activities on the OCS. That impossible for operators to explore their Alaska Arctic OCS drilling seasons (5- report specifically addressed the leases for a significant portion of each year period between 2012 and 2016), in regulatory burdens associated with U.S. year. To facilitate the proper which meteorology and physical Arctic OCS development. development of Arctic leases in oceanographic (‘‘metocean’’) and Key findings from the NPC’s accordance with OCSLA sec. 5,37 BSEE operational conditions would support supplemental assessment that helped proposes to add a new provision to its the safe deployment of SCCE, the inform the preparation of this proposed regulations that would provide those drilling of a relief well, or both. The rule include the NPC’s determination operators that are conducting drilling study included a comprehensive review that the requirement to drill an SSRW operations, but are prevented from and gap analysis of U.S. and to mitigate the risk of a late season well completing those leaseholding international regulations, standards, control event continuing over the winter operations due to seasonal constraints recommended practices, specifications, season is ‘‘outdated.’’ The report unique to the Arctic, with the technical reports, and common industry concluded that SSIDs and capping opportunity to obtain an SOO. If methods regarding the safe deployment stacks are superior solutions that could granted, this type of SOO would of SCCE, as compared to the stop the flow of oil and allow suspend the running of the lease term effectiveness of drilling a relief well in intervention through the original and effectively extend the term of the Arctic conditions. borehole before a relief well could be affected lease by a period equivalent to The Bratslavsky and SolstenXP study completed (NPC 2109 Report at 19). the period of such suspension. This determined that metocean conditions Details in the report regarding Russia’s would provide operators that are prevalent in the Chukchi Sea and 2014 drilling operation that included otherwise ready and able to conduct Beaufort Sea (i.e., rough sea states and the use of an SSID in the South Kara Sea drilling operations with additional time sea ice conditions, primarily) are key also informs this proposed rule. to diligently explore their leases, factors that limit the ability to safely In this proposed rule, the Bureaus without facing lease expiration due to deploy SCCE throughout the Arctic also address other issues in addition to OCS. The study determined that, when those addressed in the 2016 Arctic 37 OCSLA sec. 5 (as amended) provides in operating in the presence of sea ice in Exploratory Drilling Rule, including pertinent part: ‘‘The regulations prescribed by the Secretary . . . shall include . . . provisions . . . for the Chukchi Sea and the Beaufort Sea, seasonal weather-related constraints in the suspension . . . of any operation or activity there is a greater probability for safe the Arctic that severely impact an . . . at the request of a lessee, in the national relief well deployment versus SCCE operator’s ability to safely perform interest, [or] to facilitate proper development of a deployment. When operating in open leaseholding operations for a significant lease . . . and for the extension of any permit or lease affected by [such] suspension . . . by a period water conditions (i.e., those prone to portion of the term on a lease. While equivalent to the period of such suspension . . . .’’ rough sea states) in the Chukchi Sea, these issues are in addition to the issues 43 U.S.C. 1334(a)(1).

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

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

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lease stipulations.38 See discussion in communities. Such a requirement for habitat, bowhead whale migration, and Section I.E.3, History and Background lessees and operators to execute an ice coverage), BOEM’s environmental on the Conflict Avoidance Agreement, agreement could give a third-party studies program both adds to our of this preamble describing the history power to set conditions for, or veto, OCS understanding and tracks these changes and background of the CAA. In activities over which they otherwise to have the best science available for the addition, under the MMPA, the taking have no authority. public, industry, and federal permitting of marine mammals without a permit or For those reasons, BOEM has decisions. While BOEM has observed exception is prohibited in order to concluded that a regulation would not changes through these studies, these prevent the decline of species and result in any additional protections of changes follow the trajectory that BOEM populations. To avoid liability for take, subsistence whaling beyond those has been studying and documenting for operators must obtain an Incidental provided by its longstanding practice of several decades. While this proposed Take Authorization or Incidental addressing the issue in a lease rule would change how operators could Harassment Authorization for activities stipulation. BOEM has included as a explore for OCS resources in the Arctic, related to offshore exploration, lease stipulation for all Arctic OCS lease there are ample opportunities to permit development and production. sales since 1991 that the lessee must these activities consistent with ESA, Implementation of the MMPA is shared make every reasonable effort, including MMPA, NEPA, and consultation with between NMFS and USFWS. such mechanisms as a CAA, to assure Alaska Native communities. Section 7(a)(2) of the ESA requires that exploration, development, and every Federal agency to ensure that any production activities are compatible 3. History and Background on the action they authorize, fund, or carry out with whaling and other subsistence Conflict Avoidance Agreement is not likely to jeopardize the continued hunting activities and will not result in In 1977, the IWC expressed concern existence of a listed species or result in unreasonable interference with over the low bowhead whale the adverse modification of designated subsistence harvests. Implementation of population. Its report specifically critical habitat. When any exploration or the stipulation must be described in an mentioned that the future expansion of development plan, or G&G permit EP under § 550.222. In addition, either offshore oil and gas extraction in the application, is submitted to BOEM, BOEM or BSEE may require additional Arctic posed a potential risk to the BOEM evaluates the proposal, and mitigation measures at the EP or the bowhead whale population. At that consults with NMFS and USFWS on APD stages, as necessary, to time, Inuit subsistence hunters knew species listed under the ESA. During appropriately address potential that bowhead whales were sensitive to this process, mitigation measures (e.g., interference with subsistence activities. anthropogenic noise, movements, and vessel speed restrictions, rig lighting For example, because subsistence even smells. There were concerns that specifications, and protected species hunters are concerned that the effects of increased activity would affect their observer requirements) are developed to offshore oil and gas exploration might hunt. Traditional hunters had noticed reduce impacts to protected species. displace migrating bowhead whales and that boat traffic, seismic exploration, These measures are then included in other marine mammals (like beluga and drilling were causing migrating BOEM’s conditions of approval for the whales), the Bureaus will meet with the whales to deflect away from the shore EP, DPP, or G&G permit. AEWC and its whaling captains to help and beyond the hunters’ reach. BOEM did not include any regulatory document traditional knowledge Beginning in 1986, offshore changes in this proposed rule pertaining to bowhead whales, stakeholders, such as representatives specifically designed to respond to this including movement and behavior. from whaling villages, the AEWC, and comment. BOEM cannot require Given the importance of subsistence oil and gas companies, have all met to whaling communities to establish activities and related socio-cultural identify sources of potential conflict, agreements with operators, since BOEM activities to the Alaska Native and have relied on local traditional has no jurisdiction over such communities, BOEM has long knowledge as well as other information. encouraged operators to work directly CAAs were developed first in the 1980s 38 Every BOEM Arctic lease contains a variant of with interested parties to help mitigate to address these sources of potential the following stipulation: ‘‘Prior to submitting an potential impacts to subsistence conflict and have been referenced in exploration plan or development and production activities. In addition, BOEM funds and lease stipulations since 1991. plan (including associated oil-spill contingency supports studies to better understand plans) to MMS for activities proposed during the Since 1991, all leases in the Arctic bowhead whale migration period, the lessee shall the potential impacts from OCS issued by BOEM or its predecessors consult with the directly affected subsistence operations on marine mammals and have included a stipulation requiring communities, Barrow, Kaktovik, or Nuiqsut, the subsistence activities. Over the last 46 the operator to coordinate their North Slope Borough (NSB), and the AEWC to years, the environmental studies discuss potential conflicts with the siting, timing, activities with potentially affected and methods of proposed operations and safeguards program has provided more than $1.2 Alaska native communities. While the or mitigating measures which could be billion nationally for scientific research text of these stipulations has varied implemented by the operator to prevent on the OCS. Nearly $500 million of that from time to time, all of them have unreasonable conflicts. Through this consultation, amount has funded studies in Alaska to included certain important components. the lessee shall make every reasonable effort, produce more than 1,000 technical including such mechanisms as a conflict avoidance The following is an extract from such a agreement, to assure that exploration, development, reports and innumerable peer reviewed stipulation, incorporated into the leases and production activities are compatible with publications. BOEM uses information issued from the Oil and Gas Lease Sale whaling and other subsistence hunting activities from the studies program to evaluate the Number 202, issued on April 18, 2007: and will not result in unreasonable interference potential environmental effects of with subsistence harvests. Prior to submitting an exploration plan or A discussion of resolutions reached during this leasing OCS lands for exploration and development. Since July 2016, BOEM development and production plan (including consultation process and plans for continued associated oil-spill contingency plans) to consultation shall be included in the exploration has completed 35 environmental studies MMS for activities proposed during the plan or the development and production plan. In and has 23 ongoing studies that cover particular, the lessee shall show in the plan how its bowhead whale migration period, the lessee activities, in combination with other activities in the Arctic, totaling nearly $72 million. shall consult with the directly affected the area, will be scheduled and located to prevent While environmental conditions change subsistence communities, Barrow, Kaktovik, unreasonable conflicts with subsistence activities.’’ and continue to change (e.g., walrus or Nuiqsut, the North Slope Borough (NSB),

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and the Alaska Eskimo Whaling Commission stacks are similar to SSIDs. Accordingly, would list the factors upon which BSEE (AEWC) to discuss potential conflicts with this modification in the 2016 final rule may rely when determining whether to the siting, timing, and methods of proposed effectively allows the operator to install grant an SOO and include when an operations and safeguards or mitigating an SSID below a subsea BOP and would measures which could be implemented by operator: the operator to prevent unreasonable be in compliance with the capping stack (1) Has conducted operations on the conflicts. Through this consultation, the requirement in the existing § 250.471, lease during the drilling season lessee shall make every reasonable effort, What are the requirements for Arctic immediately preceding the period for including such mechanisms as a conflict OCS source control and containment? which the operator is seeking a avoidance agreement, to assure that Existing § 250.471(a)(1), specifically suspension; exploration, development, and production requires the operator, when drilling (2) is drilling from: A MODU, an activities are compatible with whaling and below or working below the surface artificial gravel island or a gravity-based other subsistence hunting activities and will casing, to have access to a capping stack structure, or an artificial ice island; and not result in unreasonable interference with subsistence harvests. that is positioned to ensure that it will (3) is not able to safely continue its be able to arrive at the well location operations due to the presence of Because this stipulation was provided within 24 hours after a loss of well seasonal ice, temporary seasonal drilling for in the lease sale notice and included control. Typically, an operator would restrictions in its approved oil spill in the lease agreements resulting from comply with this requirement by having response plan, or seasonal temperature the lease sale, its requirements became one or more support vessels capable of changes (respectively, for each facility binding for all leases issued as a result handling and deploying the capping type). of that particular lease sale. stack down to the subsea wellhead, Currently, BOEM issues Alaska OCS The intent of this stipulation is for the when needed. Installing an SSID below leases with the maximum 10-year operator to make a reasonable effort to the subsea BOP allows the operator to primary lease term allowed under establish a CAA with potentially comply with § 250.471(a)(1) and forgo OCSLA.40 However, operators may be affected whaling or subsistence hunting the need to provide support vessels and precluded from properly developing communities. It is the operator’s a capping stack on standby at the leases because it is not possible to responsibility to attempt to reach surface. conduct leaseholding operations for agreement on a CAA with those However, BSEE is proposing to significant portions of those 10-year communities. eliminate this language because a pre- terms. Offshore drilling locations on the II. Section-by-Section Discussion of positioned capping stack is a piece of Arctic OCS are inaccessible for a Proposed Changes equipment that, as previously significant portion of each year, due to mentioned, aligns closely with an SSID. This section provides explanations of seasonal changes that make operating The Bureau is currently proposing and justifications for each of the specific conditions unsafe or otherwise preclude distinct SSID requirements under regulatory changes proposed in this operations. Moreover, it is difficult to § 250.472, What are the additional well document. Since this is a joint BSEE predict precisely when sea ice will control equipment or relief rig and BOEM proposed rulemaking, this persist or break-up. requirements for the Arctic OCS? This MODUs—For example, drilling Section-by-Section discussion is proposed revision would provide clarity operations performed from a MODU organized according to the order in concerning the capping stack may occur only during the open-water which the relevant provisions would requirements under § 250.471, drilling season (generally late June to appear in the CFR. BSEE’s and BOEM’s specifically that installation of an SSID early November), when sea ice is non- regulations are found in the CFR at Title under § 250.472 does not constitute existent or minimal. This practical 30—Mineral Resources, Volume 2; compliance with the capping stack limitation, without considering other BSEE’s regulations are in Chapter II, and requirements under § 250.471. For logistical problems unique to the Arctic BOEM’s regulations are in Chapter V. purposes of BSEE’s proposed OCS, could mean that during a A. Key Revisions Proposed by BSEE regulations, an SSID is not considered to consecutive 10-year period, a lease may be the same as, or to satisfy the Title 30, Chapter II, Subchapter B, Part be unavailable for operations for requirement to have, a capping stack. 250 approximately 70 percent of the time. The new SSID option that BSEE is Artificial Gravel Islands or Gravity- Subpart A—General proposing under § 250.472 does not, and based Structures—Drilling from Definitions. (§ 250.105) is not intended to, replace any of the artificial gravel islands and gravity- SCCE requirements in proposed based structures is prohibited during the BSEE proposes to revise the definition § 250.471(a), where BSEE’s capping spring/summer ice break-up and the of Capping Stack by deleting the phrase stack requirement is addressed. fall/early winter freeze-up periods, ‘‘including one that is pre-positioned’’ because of the potential impact of from the definition. BSEE included this When may the Regional Supervisor weather and ice conditions on potential phrase as part of the 2016 Arctic grant an SOO? (§ 250.175) oil spill response and cleanup efforts. In Exploratory Drilling Rule in response to BSEE proposes to revise § 250.175 by particular, response and cleanup a suggestion that the definition in the adding a new paragraph (d), which techniques for a large spill are not as 2015 Arctic Proposed Rule should be would allow an operator to request an effective when sea ice is broken and expanded to allow pre-positioned SOO under certain situations that may unconsolidated around the drilling capping stacks to be used below subsea be present in the Arctic OCS. This location. By contrast, response and BOPs when deemed technically and proposed revision is consistent with operationally appropriate. Recognizing OCSLA’s requirement that the Secretary 40 OCSLA sec. 8, as amended, states in part: ‘‘An that the comment was helpful, BSEE promulgate suspensions regulations that oil and gas lease issued pursuant [OCSLA] shall be agreed with the suggestion and added ‘‘facilitate proper development of a lease for an initial period of (A) five years; or (B) not to the phrase ‘‘including one that is pre- 39 exceed ten years where the Secretary finds that ....’’ The proposed regulation such longer period is necessary to encourage positioned’’ to the capping stack exploration and development in areas because of definition (see 81 FR 46492). As a 39 OCSLA sec. 5, as amended, codified at 43 unusually deep water or other unusually adverse practical matter, pre-positioned capping U.S.C. 1334(a)(1). conditions . . . .’’ 43 U.S.C. 1337(b).

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

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oversight and enforcement in the same reference, or by sending a request by and the Chukchi Sea. Those general manner as other regulatory email to [email protected]. permits additionally prohibit the requirements. discharge of oil-based and non-aqueous Subpart C—Pollution Prevention and based muds and cuttings. The EPA must API Recommended Practice 17H— Control issue an NPDES general permit before Remotely Operated Tools and Interfaces an operator may seek coverage under on Subsea Production Systems Pollution prevention. (§ 250.300) that general permit. Compliance with This recommended practice provides BSEE proposes to revise paragraphs (b)(1) and (2) of § 250.300 by eliminating the CWA, including gaining coverage general recommendations and overall under an applicable NPDES general guidance for the design and operation of the existing language that states the Regional Supervisor may require the permit, is necessary before an operator remotely operated tools (ROT) and may discharge pollutants from its remotely operated vehicle (ROV) tooling capture of all water-based mud, and associated cuttings, from operations exploratory drilling operations. used on offshore subsea systems. ROT Before issuing an NPDES permit, EPA after completion of the hole for the and ROV performance is critical to must make specific determinations to conductor casing to prevent its ensuring safe and reliable subsea ensure that issuance of a permit will not operations and this document provides discharge into the marine environment. lead to unreasonable degradation of the general performance guidelines for this While this proposed rule would marine environment. EPA’s and associated equipment. This second eliminate the language regarding the determination is guided by an Ocean edition also includes provisions on high Regional Supervisor’s discretionary Discharge Criteria Evaluation (ODCE). flow Type D hot stabs. authority to require the capture of The ODCE requires the agency to The American Petroleum Institute water-based muds and cuttings, it consider multiple environmental (API) provides free online public access would maintain the existing factors, such as potential impacts on to view read only copies of its key requirement in § 250.300(b)(1) and (2) human health through direct and industry standards, including a broad that operators capture all petroleum- indirect pathways, and the importance range of technical standards. All API based mud and associated cuttings of the receiving water area to the standards that are safety-related and that while operating on the Arctic OCS. surrounding biological community. Existing § 250.300(b)(1) and (2) state are incorporated into Federal These factors take into consideration that the BSEE Regional Supervisor may regulations are available to the public how discharges could impact exercise his or her discretionary for free viewing online in the subsistence activities, marine resources, authority to restrict discharges of water- Incorporation by Reference Reading and coastal areas. The most relevant based muds and associated cuttings Room on API’s website at: http:// NPDES permits issued for offshore oil [1] from Arctic OCS exploratory drilling publications.api.org . In addition to and gas exploration activities conducted based on various factors, such as: the free online availability of these from a MODU on the Arctic OCS are Proximity of drilling operations to standards for viewing on API’s website, two 2012 general permits that covered subsistence hunting and fishing hardcopies and printable versions are oil and gas exploration facilities locations; the extent to which available for purchase from API. The conducting operations in Federal waters discharged water-based mud or cuttings API website address to purchase of the Beaufort Sea and the Chukchi may cause marine mammals to alter standards is: https://www.api.org/ Sea. The Beaufort Sea permit 41 does not their migratory patterns in a manner products-and-services/standards/ allow the discharge of water-based that impedes subsistence users’ access purchase. muds and cuttings during the fall [1] to or use of those resources, or increases To view these standards online, go bowhead whale hunt. However, the to the API publications website at: the risk of injury to subsistence users; or Chukchi Sea permit 42 did not include a http://publications.api.org. You must the extent to which discharged mud or similar restriction. According to the cuttings may adversely affect marine then log-in or create a new account, ODCE for the Chukchi Sea permit, the mammals, fish, or their habitat. BSEE accept API’s ‘‘Terms and Conditions,’’ restriction was not necessary because promulgated the existing provisions in click on the ‘‘Browse Documents’’ the migration of bowhead whales would response to concerns raised by Alaska button, and then select the applicable be over before discharge-related category (e.g., ‘‘Exploration and Native Tribes during preparation of the activities would begin.43 Production’’) for the standard(s) you 2015 Arctic Proposed Rule. These Under this proposed rule, BSEE wish to review. concerns included how water-based would preserve the requirements in For the convenience of the viewing muds or cuttings could adversely affect § 250.300(b)(1) and (2) that the operator public who may not wish to purchase or marine species (e.g., whales and fish) capture all petroleum-based mud and view the incorporated documents and their habitats and compromise the associated cuttings. This requirement is online, the documents may be inspected effectiveness of subsistence hunting consistent with a longstanding, OCS- at BSEE’s offices at: 3801 Centerpoint activities. wide regulatory authority that existed Dr, Anchorage, Alaska, 99503 (phone: BSEE re-examined the language in prior to the promulgation of the 2016 907–334–5300); 1919 Smith Street, paragraphs (b)(1) and (2) of this section Arctic Exploratory Drilling Rule. BSEE Suite 14042, Houston, Texas 77002 in light of EPA’s authority to address must preserve the petroleum-based (phone: 1–844–259–4779); or 45600 water-based muds and cuttings muds and cuttings requirement since it Woodland Road, Sterling, Virginia discharges. The Clean Water Act (CWA) is not unusual for petroleum-based 20166 (email: [email protected]), by (Section 301(a), 33 U.S.C. 1311(a)) appointment only. BSEE will make provides EPA with the authority to issue 41 https://www.epa.gov/sites/production/files/ documents incorporated in the rule National Pollutant Discharge 2017-12/documents/r10-npdes-beaufort-oil-gas-gp- available for viewing at the time and Elimination System (NPDES) general akg282100-final-permit-2012.pdf. date agreed upon for the appointment. permits, which authorize certain 42 https://www.epa.gov/sites/production/files/ Additional information on where these discharges, including certain restricted 2017-12/documents/r10-npdes-chukchi-oil-gas-gp- akg288100-final-permit-2012.pdf. documents can be inspected or discharges of water-based muds and 43 https://www.epa.gov/sites/production/files/ purchased can be found at 30 CFR cuttings, from oil and gas exploratory 2017-12/documents/r10-npdes-chukchi-oil-gas-gp- 250.198, Documents incorporated by facilities on the OCS in the Beaufort Sea akg288100-odce-2012.pdf, pp. 6–14 to 6–17.

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muds to contain constituents that are environmentally responsible manner with ‘‘use’’ to improve the readability of toxic and harmful to the environment. pursuant to OCSLA. Therefore, the the regulation. Although water-based muds may not be proposed rule would not alter the Subpart D—Oil and Gas Drilling a feasible option for all drilling longstanding regulation at Operations operations, such as when drilling § 250.300(b)(1), under which the District through hydrophobic geologic Manager (or Regional Supervisor) What additional information must I formations that could be damaged by retains the ability to restrict the rate of submit with my APD for Arctic OCS water-based muds, its use is a more discharges or prescribe exploratory drilling operations? environmentally benign approach in alternative discharge methods where (§ 250.470) comparison to the use of petroleum- warranted. Pursuant to § 250.300(b)(1), BSEE proposes to revise paragraph (b) based muds. However, BSEE’s proposed BSEE would be able to determine of § 250.470 by adding paragraph (b)(13) revisions reflect the Bureau’s whether there is a need to require to include ‘‘Recover the subsea isolation understanding that the express capture of water-based muds and device (SSID), where applicable.’’ This statements regarding the Regional cuttings on a case-by-case basis, if the revision is necessary to address the Supervisor’s discretionary authority to EPA has not done so. In particular, the SSID alternative proposed in § 250.472, require the capture of water-based muds District Manager would consider and and to ensure the operator’s permit and cuttings in existing § 250.300(b)(1) determine whether such a requirement addresses how it would recover the and (2) are not necessary. In particular, would be appropriate for any facility. SSID, if one is used. For operations the EPA already addresses the goals of The District Manager would make this relying on an SSID, the SSID is a critical protecting water quality through the piece of equipment. Therefore, BSEE NPDES program, protecting marine determination on a case-by-case basis, must understand how the operators will species and their habitats, as well as the in conjunction with the EP and APD handle it, prior to and after drilling effectiveness of subsistence hunting approval process. This process includes operations. We also propose minor, non- activities, through the exercise of that coordinating with BOEM, particularly at agency’s authorities. Thus, BSEE does the EP stage, when BOEM conducts an substantive edits to paragraphs (b)(11) not expect the Regional Supervisor to environmental review to identify the and (12) to accommodate this addition. In cases where an operator obtains need to exercise the discretionary direct, indirect, and cumulative SCCE capabilities through contracting, authority under existing § 250.300(b)(1) environmental effects that may be paragraph (f)(3) currently requires the and (2) in the foreseeable future. expected as a result of implementing the Furthermore, BSEE understands, and EP. That environmental review also operator to provide proof of contracts or did so even while it was preparing the incorporates input about potential membership agreements with 2016 Arctic Exploratory Drilling rule, environmental effects that may be cooperatives, service providers, or other that the references to the BSEE Regional obtained through consultations and contractors. This includes information Supervisor’s authority in existing review by interested parties, Federal demonstrating the availability of the paragraphs (b)(1) and (2) created some agencies (e.g., EPA), State or local personnel and/or equipment on a 24- uncertainty for the regulated industry agencies, Tribes, or the public. Nothing hour per day basis during operations because it appeared to overlap with would change BSEE’s position from the below the surface casing. BSEE proposes EPA’s jurisdiction and, if implemented, 2016 rule to communicate with other to revise paragraph (f)(3) by replacing might result in BSEE issuing duplicative agencies responsible for oversight of the ‘‘below the surface casing’’ language or conflicting requirements. BSEE discharges related to oil and gas in this paragraph with the phrase addressed this concern by explaining exploration drilling in the Arctic. This ‘‘below the surface casing, or before the that the amendments were meant to communication will help ensure that last casing point prior to penetrating a clarify the Regional Supervisor’s conflicts do not arise (81 FR 46504). zone capable of flowing hydrocarbons in authority to impose operational BSEE expects that such input from EPA measurable quantities, as approved by measures that complement EPA’s would address whether that agency has the Regional Supervisor.’’ This change discharge limitations by considering issued or plans to issue a permit for the would make the requirement in potential impacts to specific same exploratory drilling facilities, and paragraph (f)(3) consistent with the components of the Arctic environment, whether that agency believes that changes BSEE is proposing to § 250.471, such as subsistence activities, marine capture of water-based muds in a which houses the substance of the Arctic OCS SCCE requirements. This resources, and coastal areas (81 FR specific case is warranted. Through proposed change is discussed in further 46505). Given the policy in E.O. 13783 BSEE’s longstanding authority under detail in connection with that provision. to review existing regulations that § 250.300(b)(1), the District Manager Finally, BSEE proposes to add a new potentially burden the development or could require an operator to restrict the use of domestically produced energy paragraph (h) to complement the rate of drilling fluid discharges or proposed revisions to § 250.472, which resources and the general principles in prescribe alternative discharge methods. Section 1 of E.O. 13563—Improving would provide the operator with the Such a restriction on the discharge of option to use an SSID or have access to Regulation and Regulatory Review (76 water-based muds and cuttings might be FR 3821)—to promote predictability and a relief rig, as an additional means to appropriate if identified in the EP secure the well in the event of a loss of reduce uncertainty, BSEE believes it is environmental review process. appropriate to propose eliminating the well control, if the operator will be water-based mud, and associated In addition to the proposed revisions conducting exploratory drilling cuttings, provisions in § 250.300(b)(1) just described, BSEE proposes a minor operations from a MODU (that change is and (2). modification to the second sentence in discussed in further detail in connection This proposed regulatory change does existing paragraph (b)(2), which requires with that provision). Under proposed not suggest any change in BSEE’s the operator to capture all cuttings from paragraph (h), if the operator elects to recognition that it is responsible for operations that ‘‘utilize’’ petroleum- use an SSID, BSEE would require the ensuring that oil and gas exploration based mud to prevent their discharge operator to provide a certification, and production activities on the OCS into the marine environment. BSEE signed by a registered professional are conducted in a safe and proposes to replace the word ‘‘utilize’’ engineer, confirming that its SSID and

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

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

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its capping stack positioned before whether it is appropriate to delay proposed change would remove the drilling below or working below the last positioning of the capping stack at a requirement to have a cap and flow casing point prior to penetrating a zone point in time when operations are system or a containment dome capable of flowing hydrocarbons in taking place below the surface casing positioned to ensure the equipment will measurable quantities. resides with BSEE. BSEE, ultimately, be available to arrive at the well location Under this regulatory option, BSEE may decide not to allow the operator to within 7 days after the loss of well would evaluate the geologic and delay positioning of the capping stack if control, while preserving the existing engineering information/analysis that the Bureau reasonably assesses that requirement to deploy those pieces of the operator must submit as part of its potential risks below the surface casing equipment as directed by BSEE. APD, while also taking into exist that may require immediate BSEE proposes to allow the operator consideration any other available G&G deployment of this device. However, the to adjust the point in time during information the Bureau may have (e.g., distinction under this regulatory option operations when it must position its off-set well data, such as well logs and is that the operator would not need to capping stack under paragraph (a), from pressure testing information, or specifically demonstrate that ‘‘when drilling or working below the geophysical information, such as abnormally high-pressured zones or surface casing’’ to ‘‘when drilling below seismic data). Based on these different other geologic hazards would be or working below last casing point prior sources of information, BSEE would encountered above last casing point to penetrating a zone capable of flowing determine whether there may be a need prior to penetrating a zone capable of hydrocarbons in measurable quantities’’ for the operator to position the capping flowing hydrocarbons in measurable if the operator is able to demonstrate stack at a point in time during quantities. The presumption would be that it will not encounter any operations earlier than last casing point that all zones above the last casing point abnormally high-pressured zones or prior to penetrating a zone capable of prior to penetrating a zone capable of other geologic hazards before that casing flowing hydrocarbons in measurable flowing hydrocarbons are safe unless point. Only the 7-day arrival timing quantities. BSEE determines otherwise. In addition, related to the ‘‘flow’’ part of the cap and There may be cases where the under BSEE’s proposed regulatory flow system would be altered as a result operator or BSEE may not have change, it would be clear that the of BSEE’s proposed modification to sufficient G&G or analogous well data Bureau may request additional paragraph (a)(2) of § 250.471.44 during the permit review process on a information from the operator and The changes proposed in paragraphs proposed project to provide an adequate would provide that BSEE may consider (a)(2) and (3) to remove the requirement level of certainty regarding anticipated other available data and information. for the cap and flow system and the formations that may be encountered BSEE is specifically soliciting containment dome to arrive at the well prior to reaching the targeted productive comments about the benefits or location within 7 days after a loss of formation. Therefore, BSEE is also disadvantages of this regulatory option. well control would not change other considering, as part of this regulatory BSEE is also soliciting comments about existing requirements throughout option, a clarification that the Regional the need for the operator to verify on a § 250.471 for the operator to ensure: Supervisor may require the operator to case-by-case basis those zones incapable (i) Access to a containment dome and have access to a capping stack in of flowing hydrocarbons in measurable cap and flow system; advance of drilling below or working quantities. Operators verify these zones (ii) that the cap and flow system is below the last casing point prior to by analyzing G&G data to evaluate the designed to capture at least the amount penetrating a zone capable of flowing formations that are expected to be of hydrocarbons equivalent to the hydrocarbons in measurable quantities encountered during drilling operations calculated WCD rate referenced in the if BSEE determines there is insufficient and confirm that there are no operator’s BOEM-approved EP; G&G or analogous well data. hydrocarbons present. Operators must (iii) that the containment dome has For example, there may be use available offset well data in the capacity to pump fluids without insufficient G&G or analogous well data conjunction with the G&G data. BSEE relying on buoyancy; in cases where there have been a limited requests comment on other methods (iv) that tests or exercises are number of wells drilled within operators use to verify the hydrocarbon conducted for the SCCE, as directed by proximity to the planned well. In most zones, or abnormally high-pressured the Regional Supervisor; cases, G&G and analogous well data are zones or other geologic hazards (such as (v) that records pertaining to the gathered from multiple sources. fractured or high permeability zones), testing, inspection, maintenance, and However, the same sets and amounts of they anticipate encountering for a use of the SCCE are maintained and data and information may not be proposed drilling project and how made available to BSEE upon request; available for each area, well, or project. frequently the data would be lacking at (vi) that all SCCE identified in There is no single set of criteria for the point of preparing information to § 250.471 are transported to the well determining the sufficiency of G&G or submit as part of an APD. upon a loss of well control; and analogous well data. The more data that • Revisions to the Cap and Flow (vii) that SCCE is deployed as directed are available from sources near to the System, and Containment Dome by the Regional Supervisor. proposed drilling location, the greater Requirements BSEE proposes to remove the cap and confidence BSEE will have in the G&G As described at the beginning of this flow system and containment dome 7- interpretations. BSEE wants to ensure section-by-section discussion, § 250.471, day arrival timing requirements based the operator has the most accurate data BSEE is also proposing to revise on the Bratslavsky and SolstenXP study. to make determinations about where the paragraphs (a)(2) and (3) of existing The Bratslavsky and SolstenXP study zones capable of flowing hydrocarbons § 250.471, which refers to the timing of determined that the time periods when in measurable quantities are located. the arrival of a cap and flow system and SCCE may be safely deployed This alternative regulatory option containment dome, respectively, by throughout the Arctic OCS is limited would maintain the same level of safety removing the phrase ‘‘positioned to based on typical Arctic conditions. In and environmental protection in ensure that it will arrive at the well comparison to BSEE’s proposed location within 7 days after a loss of 44 Existing § 250.105 defines Cap and flow system regulatory change. The decision on well control’’ from each paragraph. This and Capping stack.

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the Chukchi Sea, this means that safe the historically active exploration area Since publication of the 2016 rule, SCCE deployment could only occur and in the other areas of the Beaufort however, BSEE has sought to better between August and October in the Sea. (id. at 98,102) understand the ability to safely deploy historically active exploration area. Water depth is also an important SCCE (and relief rigs) in Arctic OCS Moving north from the historically factor to consider for the safe conditions, through a study it active exploration area of the Chukchi deployment of SCCE. Deployment is commissioned to Bratslavsky Consulting Sea, the ability to safely deploy SCCE likely to be impaired in water depths Engineers, Inc., and SolstenXP, Inc. diminishes significantly (id. at 100). The shallower than 984 feet because the According to the Bratslavsky and study mentions there are more equipment would potentially be subject SolstenXP study, the time periods when opportunities for safe deployment of to a gas boil at the surface from a subsea SCCE may be safely deployed SCCE in other portions of the Chukchi blowing well (id. at 143). A gas boil is throughout the Arctic OCS is limited in Sea (June through December). However, a forceful release of hazardous gases comparison to relief-well drilling it is only in the southwestern extent of which can present human-health operations, based on typical Arctic the Chukchi Sea Planning Area; outside hazards to workers, fire hazards, and conditions. BSEE did not have the of the historically active exploration potential stability problems for support benefit of having the Bratslavsky and area. vessels and the vessel deploying the SolstenXP study when finalizing the In the Beaufort Sea, the study noted SCCE directly above the blowing well. 2016 Arctic Exploratory Drilling Rule. that sea ice concentrations tend to be Water depths in the majority of the BSEE’s proposed changes to greater year-round as compared to the Chukchi Sea and Beaufort Sea where § 250.471(a)(2) and (3) for the Chukchi Sea (id. at 75). Accordingly, exploration has historically occurred are containment dome and cap and flow safe SCCE deployment could occur from relatively shallow—167 feet or less system responds to the information it ice capable vessels between early has gathered from the study. (Table 1–1 and Table 1–2, id. at 7 to 9). August and October in the historically In light of these findings, BSEE As recently as April of 2020,45 active exploration area of the Beaufort there proposes the revisions under § 250.471 Sea (i.e., the southern portion of the were active leases in the Arctic OCS to the containment dome and cap and Beaufort Sea Planning Area). However, where SCCE may be deployed. These flow system deployment requirements moving north beyond the historically leases were located in the Beaufort Sea in paragraphs (a)(2) and (3) because it is active exploration area, time windows in water depths less than approximately not reasonable to impose such for safe SCCE deployment decrease 170 feet deep. This water depth range universal, prescriptive requirements for significantly (id. at 104). limits the fleet of support vessels that equipment that may not be safely In the case of open water operations can be used for the safe deployment of deployed (moved to the location, in both the Chukchi and Beaufort Seas, SCCE. A possible solution that could equipment put into place, and activated) the study points out that sea state is an enable SCCE deployment in the and effectively used under certain important limiting factor for safe SCCE presence of a gas boil is the use of Arctic OCS conditions. The deployment deployment. Rough sea states—high offset-deployment technology to and arrival schedules of the cap and waves and longer wave periods—can remotely position SCCE over the flow system and the containment dome affect the safety and operating limits of blowing well in shallow water (id. at A– will be directed by the BSEE Regional SCCE deployment. The vessel carrying 35). Supervisor on a case-by-case basis. the SCCE can become very unstable in When BSEE proposed its original However, as previously described, rough sea states and the heave action on Arctic OCS SCCE requirements in 2015, BSEE proposes only to adjust, rather the deck can therefore increase the Bureau explained that there is than eliminate, the reference to the significantly beyond the vessel’s limited ability in the Arctic region to point in time during operations when tolerance levels for conducting summon additional source control and the operator must have access to a operations, which may negatively affect containment resources. Accordingly, the capping stack that is positioned to be the ability to safely deploy the SCCE. Bureau required operators to plan for able to arrive at the well location within Rough sea states are most likely to occur response redundancies and planning 24 hours after a loss of well control. The when there is less sea ice coverage and complexities not required elsewhere (80 Bratslavsky and SolstenXP study shows larger open water areas to generate large FR 9938). BSEE determined that the that the time periods when SCCE waves, which is more of an issue in the provisions finalized in 2016 provided (capping stack, containment dome, and Chukchi Sea, where there are larger for the necessary redundancy and cap and flow system) may safely be open water areas throughout the open sequencing of the responses, based on deployed and effectively used are water season (id. at 11). the time necessary to deploy, and limited. Metocean conditions (i.e., When operating in open water therefore provided sufficient safety and rough sea states and sea ice conditions, sea states generally dictate environmental protection to allow for concentrations) prevalent in the Arctic that safe SCCE deployment could occur exploratory drilling on the Arctic OCS. OCS can exceed the operating limits of only between late September and At that time, BSEE believed that the the vessels that transport and deploy the October in the historically active technologies identified in its SCCE SCCE. In addition, SCCE deployment is exploration area of the Chukchi Sea, and requirements represented the optimal likely impaired in water depths that window diminishes significantly approach to well control capabilities shallower that 984 feet, where gas boils moving north of the historically active available for the Arctic OCS (81 FR could form above a blowing well. Water exploration area. In the Beaufort Sea, 46520). depths in the majority of the Chukchi where there is less open water Sea and Beaufort Sea where exploration throughout the operating season, sea 45 In April of 2020, the only leases with potential has historically occurred are relatively states would generally permit safe projects that would be subject to the Arctic OCS’s shallow—167 feet or less. However, deployment of SCCE between late- SCCE requirements were relinquished. However, BSEE’s independent observation outside August and early-to mid-October in the there are other active leases in the Beaufort Sea of the study is that the chances for located nearer to the shore in shallow waters where historically active exploration area. exploration and development projects are being successfully deploying a capping stack Beyond that, the probability for safe pursued (primarily through man-made gravel under Arctic OCS conditions is greater SCCE deployment decreases rapidly in islands). in comparison to the containment dome

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and cap and flow system. More capping stack positioning requirement. What are the additional well control specifically, in comparison to the BSEE invites comments on any equipment or relief rig requirements for containment dome, the capping stack technological upgrades or methods that the Arctic OCS? (§ 250.472) has proven to be a more effective exist for SCCE that would meet the Paragraph (b) of § 250.472 currently technology when successfully deployed objective of being a redundant system requires the operator to have access to and has a different function compared that could control or contain a WCD. a relief rig (different from the primary to a containment dome. The capping Although BSEE is proposing to drilling rig), when drilling or working stack latches on to a connector or pipe remove the requirement in existing below the surface casing. In addition, stub located on or in the well to achieve when drilling or working below the a pressure tight seal to capture or stop paragraphs (a)(2) and (3) to ensure that the cap and flow system and surface casing, paragraph (b) requires all fluids flowing out of the well. A the operator to stage the relief rig so that containment dome, which removes oil containment dome will be available to it could arrive on site, drill a relief well, and gas from the water column, will arrive at the well location within 7 days kill and permanently plug the out-of- likely capture only a portion of the after a loss of well control, BSEE would control well, and abandon the relief hydrocarbon flow due to the non-sealing maintain the provisions under the same well prior to expected seasonal ice design. In addition, the use of a paragraphs that require that the operator encroachment at the drill site, and in no containment dome may be constrained identify and have access to a event later than 45 days after the loss of by the drilling unit itself. Certain containment dome and cap and flow well control. drilling rigs, such as jackups and system capable of deployment as BSEE proposes to revise the existing submersible drilling vessels, are directed by BSEE. BSEE would also relief rig and SSRW requirements in unlikely to provide adequate structural maintain the requirement under existing § 250.472 by: clearance for deployment of a paragraph (g) to initiate transit of all (i) Providing the operator with an containment dome without moving the SCCE identified under § 250.471 upon a option to either use an SSID or have rig off the drill site. (id. at 33). loss of well control. Collectively, the access to a relief rig, if the operator will Furthermore, containment domes have proposed revisions to paragraphs (a)(2), conduct exploratory drilling operations limited field application to prove their (a)(3), and existing paragraph (g) would from a MODU; capabilities while, in contrast, capping mean that, in the event of a loss of well (ii) Establishing the requirements that stacks have been field tested and control, the containment dome and cap the operator must satisfy if the operator successfully deployed in multiple and flow system would be in transit 46 elects to use an SSID to comply with practice drills (id. at 32 and 34). while the capping stack is being § 250.472; With respect to the cap and flow deployed at the well location. In light of (iii) Establishing the requirements that system, the flow portion of the system the distinct functions and capabilities of the operator must satisfy if the operator would require additional vessel support these various elements of SCCE under elects to have access to a relief rig to activities on the surface (e.g., support anticipated Arctic OCS exploratory comply with § 250.472; vessels for oil and gas processing, and drilling conditions, BSEE proposes to (iv) Adding a new provision that hydrocarbon storage/transfer) to keep retain these requirements, as modified, would apply if the operator elects to the system working in comparison to have access to a relief rig, which states, what would be needed to deploy a to preserve the regulations’ requirement ‘‘However, the Regional Supervisor will capping stack (e.g., a single vessel that for redundant protective measures, approve delaying access to your relief would load the capping stack and while acknowledging the capability of rig until your operations have reached deploy to the well when needed). The each SCCE component, as there is no the last casing point prior to penetrating support activities and the vessel on guarantee that a single measure could a zone capable of flowing hydrocarbons which the flow system is loaded would control or contain a WCD. in measurable quantities provided that be subject to the same challenging Finally, BSEE proposes to revise you submit adequate documentation metocean conditions previously existing paragraph (b) by eliminating the (such as, but not limited to, risk described, thus limiting their ability to requirement for the operator to conduct modeling data, off-set well data, analog be safely deployed throughout the a stump test of a pre-positioned capping data, seismic data), with your APD, Arctic drilling season. The capping stack, if the operator elects to use one, demonstrating that you will not stack would generally have a better prior to installation on each well. This encounter any abnormally high- opportunity for deployment because proposed change would provide pressured zones or other geological once the capping stack is lowered under consistency with BSEE’s proposed hazards. The Regional Supervisor will the water and attached to the wellhead, revision to the definition of a capping base the determination on any weather becomes less of a factor. stack in § 250.105 and the new SSID BSEE believes it is critical to ensure documentation you provide as well as alternative BSEE is proposing under any other available data and that operators have redundant § 250.472. BSEE’s proposed SSID protective measures in place, as there is information.’’; and alternative includes specific testing (v) Eliminating the reference to no guarantee that a single measure procedures, which is discussed in detail expected seasonal ice encroachment at could control or contain a worst-case later in this preamble. BSEE’s prior the drill site, which applies to relief rig discharge (see 81 FR 46487). Because references to ‘‘pre-positioned capping operations. the chances of successfully deploying a stacks’’ were intended to address a With respect to the structure of capping stack under Arctic OCS comment on the 2015 Arctic § 250.472, proposed paragraph (a) conditions may be greater in Exploratory Drilling Proposed Rule would establish the requirements the comparison to the containment dome suggesting that the definition of a operator must follow if the operator and cap and flow system, BSEE is capping stack be expanded to allow pre- elects to use an SSID, and proposed revising, and not eliminating, the positioned capping stacks to be used paragraph (b) would establish the below subsea BOPs when deemed requirements the operator must follow if 46 For example, the capping stack technology was used to shut-in the Macondo well during the technically and operationally the operator elects to maintain access to Deepwater Horizon incident. appropriate. a relief rig. BSEE would combine the

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requirements in existing paragraphs (a) conducted from MODUs are and Gas Resources.’’ The supplemental and (b) into a single paragraph— complicated by the fact that these assessment evaluated recent experiences proposed paragraph (b)—for operations can take place only during a with Arctic exploration and organizational purposes, since existing short period each year, when ice advancements in technology, and it paragraphs (a) and (b) cover relief rigs. hazards can be physically managed and provided findings and Proposed paragraph (b) would also there is no continuous ice layer over the recommendations directed toward include the relief rig-related revision water. Outside of that window, ice enhancing the Nation’s regulatory described in item (iv) of the previous encroachment complicates or prevents environment to improve reliability, paragraph, which could allow the drilling, including drilling a relief well, safety, efficiency, and environmental operator to adjust the point in time and transit operations. Therefore, BSEE stewardship for Arctic oil and gas during operations when it must stage its concluded in the proposed rule: Oil and development. One of the key areas the relief rig—from ‘‘when drilling or Gas and Sulphur Operations on the Secretary of Energy requested that the working below the surface casing’’ to OCS—Requirements for Exploratory NPC address was regulatory burdens ‘‘when drilling or working below the Drilling on the Arctic OCS (February 24, related to development on the Arctic last casing point prior to the zone 2015, 80 FR 9916) that, for Arctic OCS OCS. (NPC 2019 Report at A–1) capable of flowing hydrocarbons in Conditions, it was necessary to establish The NPC 2015 Report described measurable quantities’’—if the operator a relief rig and SSRW requirements, various technologies employed by is able to demonstrate that it will not whereby the rig would be positioned at industry as preventative measures, to encounter any abnormally high- a location that would enable it to transit reduce the risk of a well control pressured zones or other geological to the well site, drill a relief well, kill incident or to mitigate the impacts of an hazards before that casing point. and permanently plug the out-of-control incident through response and recovery However, unless otherwise approved by well, plug the relief well, and measures. It recommended further BSEE, the operator must stage its relief demobilize from the site, prior to examination of source control and rig in a location, such that the relief rig expected seasonal ice encroachment. containment technologies, including would be available to arrive on site, drill (see 80 FR 9940). capping stacks and SSIDs, noting that a relief well, kill and abandon the Prior to finalizing the 2016 Arctic such alternatives ‘‘. . . could prevent or original well, and abandon the relief Exploratory Drilling Rule, BSEE did not significantly reduce the amount of well no later than 45 days after the loss identify any alternative technologies spilled oil compared to a relief well, of well control, when drilling or that provided a comparable level of which could take a month or more to be working below the surface casing. results to drilling a relief well and effective.’’ (NPC 2015 Report at 4–16). Finally, proposed paragraph (b) would permanently killing an out-of-control In July/August of 2007, BSEE’s include the proposed relief rig-related well. Drilling a relief well prior to predecessor, MMS, published a paper revision to eliminate the reference to seasonal ice encroachment eliminates entitled, ‘‘Absence of fatalities in expected seasonal ice encroachment at the risk of a prolonged uncontrolled blowouts encouraging in MMS study of the drill site, which could potentially flow of hydrocarbons under the ice, OCS incidents 1992–2006.’’ You may extend the open-water drilling season throughout the winter season. The SCCE download and view the paper at http:// for MODUs. The changes included in intervention options in BSEE’s existing drillingcontractor.org/dcpi/dc- proposed paragraphs (a) and (b) are regulations (capping stack, cap and flow julyaug07/DC_July07_ discussed in further detail below, system, and containment dome) are MMSBlowouts.pdf. The paper respectively, under the two subheadings intended only to temporarily control a summarizes BSEE’s assessment of entitled, Proposed Paragraph (a)— well and not to be left in place over an statistical information about loss of well Complying with § 250.472 by Using an entire ice season. However, BSEE did control events that occurred during SSID and Proposed Paragraph (b)— provide an option through the 2016 rule drilling operations on the OCS from Complying with § 250.472 by Having for the operator to request that BSEE 1992 through 2006. The paper noted Access to a Relief Rig. approve ‘‘alternative compliance that although relief wells were initiated In addition, the general alternative measures to the relief rig requirement,’’ in 2 of the 39 blowouts that occurred compliance language in existing as provided in the longstanding during the study period, both wells paragraph (c) would be eliminated regulation at § 250.141, May I ever use were controlled by other means prior to because the proposed rule would alternate procedures or equipment? completion of the relief well. According provide the operator with the Since the promulgation of the 2016 to the NPC 2015 report, ‘‘[a] relief well alternatives of either using an SSID or Arctic Exploratory Drilling Rule, BSEE under good weather conditions may having access to a relief rig, and because has received and considered new take 30 to 90 days plus rig mobilization, § 250.141, May I ever use alternate information regarding the current relief whereas a capping stack could be procedures or equipment?, already rig and SSRW requirements in installed significantly sooner, and a provides an option for an operator to § 250.472. BSEE used the following subsea shut-in device could be activated seek approval to use alternate information when developing the in minutes.’’ (NPC 2015 Report at 8–17) procedures or equipment, potentially proposed requirements of this section: The NPC 2019 Report noted that, including future technologies that have • Supplemental Assessment to the when ExxonMobil drilled an not yet been developed. 2015 Report on Arctic Potential: exploratory well in the Russian waters When it promulgated the 2016 Arctic Realizing the Promise of U.S. Arctic Oil of the Kara Sea, it used an SSID that was Exploratory Drilling Rule, BSEE and Gas Resources (NPC 2019 Report) built and tested in Norway. According understood that, based on past loss of In April 2018, the Secretary of Energy, to the NPC 2019 Report, the SSID used well control events (including the in cooperation with DOI, requested that in the Kara Sea used existing capping Deepwater Horizon incident), it was the NPC develop a supplemental stack technology, including dual blind important for the operator to be assessment to the NPC 2015 Report. In shear rams; an upgraded, redundant prepared to drill a relief well to April 2019, the NPC issued a report control system; and side inlets for permanently plug a well, in the event of entitled, ‘‘Supplemental Assessment to intervention below the shear rams. (id. a loss of well control. Arctic OCS the 2015 Report on Arctic Potential: at C–10). At the same time, the NPC exploratory drilling operations Realizing the Promise of U.S. Arctic Oil 2019 Report described the SSID as

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

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operation. (id. at 108 and 145). publication of the 2016 rule, BSEE has including the SSID’s redundant control Moreover, the NPC 2019 Report notes reevaluated the use of SSIDs and the system (i.e., under proposed that ‘‘vessels and equipment that are overall improved technology for similar § 250.472(a)(2)(ii)) and subsea positioned in the theater ‘just in case’ components (BOPs). In this proposed accumulators (i.e., under proposed they are needed to minimize rule, BSEE would allow operators the § 250.472(a)(2)(iii)). environmental impact, can actually option to use an SSID based on BSEE’s Although the NPC 2019 Report impede personnel safety and source assessment of improved SSID design recommended that the use of an SSID control objectives, because they distract and operating requirements, including and capping stacks replace the operations personnel, add congestion, the ability to shut in a well over the requirement for an SSRW capability, and can impede surface access to the winter ice season with a well cap. BSEE is not proposing to eliminate the well location.’’ (NPC 2019 Report at 19). Additionally, BSEE would make this relief rig and SSRW requirements. In the Beaufort Sea, the available open revision to potentially minimize Rather, BSEE is proposing to maintain water operating season is limited to environmental damage due to a the relief rig and SSRW requirement as approximately 50 to 60 days across the prolonged ongoing well control event. an option for the operator to meet the historically active exploration area. (id. An SSID is not a permanent solution for regulatory requirements of § 250.472. at 143). The study’s analysis showed well remediation. However, it can BSEE has determined that its there is a high probability (90 percent) provide a significantly quicker response regulations should provide options and that drilling can be conducted safely for time to address a well control event flexibility to the operator (i.e., an SSID 70 days, from mid-August through compared to drilling a relief well. or a relief rig) to fit its needs and plans October, in a majority of the historically Consistent with the policy in E.O. to develop its Arctic OCS leases. There active exploration area of the Beaufort 13783 to review existing regulations that could be cases where the operator’s Sea. (id. at 146). potentially burden the development or drilling schedule may not align with the In light of the information from the use of domestically produced energy availability of an SSID. In such a case, NPC reports and the Bratslavsky and resources, BSEE re-considered the SSID the operator should have the option to SolstenXP study, and BSEE’s more closely, in light of the SSID elect to proceed by complying with the consideration of that information, BSEE information from the NPC reports and relief rig and SSRW requirements. If an proposes to revise § 250.472 in the the Bratzlavsky and SolstenXP study, to operator does not complete its following manner: determine whether the device could exploratory drilling operations during • Proposed Paragraph (a)— address the issues the Bureau identified that open water operating season, the Complying with § 250.472 by Using an when promulgating the 2016 rule. operator could come back during a SSID Drilling a relief well is a complex, subsequent open water operating season The use of an SSID is not a new time-consuming process. After setting and use an SSID, if one has become concept and was discussed in the 2016 up the drill rig and drilling begins, the available in time. Arctic Exploratory Drilling Rule.47 process to intercept the original There could also be cases where two Through the 2016 rulemaking comment wellbore may take several weeks or or more operators may plan to perform process, stakeholders informed the more because the operator needs to drill exploratory drilling operations during Bureau that use of an SSID could help deep enough at great precision to ensure the same open water season. In such a significantly reduce the risk of a release interception of the original well. This case, each operator’s drilling rig could of hydrocarbons if the BOP system fails. delay increases the length of the time oil serve as the other’s relief rig. Under the At that time, BSEE focused more on and other fluids within the original well existing regulations, BSEE would permanent remediation to resolve a could be flowing uncontrollably into the consider this type of a scenario to be in WCD event in the Arctic. Nonetheless, marine environment. There is no delay compliance with the relief rig and the Bureau agreed that an operator for operational use of an SSID compared SSRW requirements. BSEE would not could request to use an SSID as an to the process of using the relief rig or change that interpretation as part of this alternate procedure or equipment to the capping stack. rulemaking. In a scenario like this, none relief rig (80 FR 9940). Stopping short of In this proposed rule, BSEE of the operators would need to install an requiring the use of an SSID, BSEE, developed its proposed SSID SSID, so long as there is an agreement instead, stated in the 2016 rule that it requirements based on existing BOP among the operators that their drilling would consider the use of an SSID as an equipment/technology whose rigs will serve as a relief rig, if alternate procedure or equipment, under performance and reliability has been necessary. While it is not possible to appropriate circumstances, if proposed tested, proven in a manner that is identify every conceivable scenario, for use with a jack-up (when surface repeatable and reproducible, and has BSEE recognizes there could be other BOPs are used). At that time, BSEE improved since promulgation of the scenarios that are reasonably possible. determined that, in the case where 2016 rule. BSEE also proposes to require Thus, it is appropriate to provide subsea BOPs are used in conjunction an SSID used in the Arctic OCS to regulatory flexibility in order to with floating drilling units, SSIDs operate independently from the BOP. accommodate an operator’s drilling would only be marginally effective or This would be accomplished by program. BSEE also retains its redundant (81 FR 46531). Since the requiring the SSID to have a redundant regulatory authority to approve alternate control system, independent from the procedures or equipment if the 47 See, e.g., 80 FR 9940 (‘‘[BSEE] requests BOP control system, and independent, proposed procedures or equipment comments on alternative compliance approaches dedicated subsea accumulators to either meet or exceed the level of safety and specifically requests data on the performance operate the SSID. By having two and environmental protection required. of SIDs, including operational issues (such as timeframes needed to activate such alternatives). In independent, redundant components The term SSID is a broadly used particular, BSEE requests comments on appropriate (i.e., the BOP and the SSID) as part of industry term, and there is not a single, staging requirements for a relief rig assuming that the well control system, the overall all-encompassing definition that an SID has been installed at the exploration well. reliability and effectiveness of the entire establishes the scope and function of an Comments are also requested on the need for an operator to have an in- season relief well drilling system increases. The following SSID. In some cases, different terms are capability if an SID is used at a location that is not paragraphs describe BSEE’s proposed used to describe the device. For subject to ice scouring.’’) requirements associated with the SSID, example, as stated earlier, the

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Bratslavsky and SolstenXP study refers wellbore). If the wellbore is pressure may exceed the strength of the to the device as a ‘‘subsea intervention compromised during or after a full shut- formation (fracture pressure) in the device,’’ while some in the industry also in, an underground blowout or broach wellbore, potentially resulting in a refer to the SSID as a ‘‘mudline closure to the seafloor may occur. BSEE fracture of the formation and an device.’’ Irrespective of these reviewed available incident data on loss underground blowout. Because synonymous titles, BSEE uses the term of well control events,48 and determined proposed paragraph (a) of § 250.472 SSID to refer to a fit-for-purpose device that, on average, five loss of well control contemplates allowing the operator to that may be used for different types of events occurred each year on the OCS leave a well shut-in from one open- situations, including for well between 2007 and 2017. water season to the next (i.e., in the case intervention applications, and can be The well design language in proposed of a late season well control event), used in different locations, including paragraph (a) would also require the wells need to be designed to withstand outside of the Arctic. However, for the operator to account for the stresses and this potential loading condition. purposes of Arctic OCS exploratory loads placed on the well from the In a new paragraph (a)(1), BSEE drilling from a MODU, BSEE is equipment that may be required to proposes to establish performance-based proposing to define the minimum regain control after a loss of well control design requirements for the SSID. BSEE acceptable capabilities and functions of event. This includes the SSID, BOP would require the operator to ensure an SSID. BSEE notes that, outside of the stack, and capping stack. It is imperative that the SSID is designed to: Arctic OCS, operators are contemplating that all well components are designed to (1) Close and seal the wellbore, using SSIDs for future projects, and withstand all potential loads and independent of the BOP; SSIDs have already been approved for stresses placed on the well, including (2) Perform under the maximum use in other parts of the OCS. The NPC those that may be required during well environmental and operational 2019 Report notes that the requirement control situations and deployment of conditions anticipated to occur at the to drill an SSRW to mitigate the risk of SCCE (i.e., the well must be able to well; a late season well control event support a capping stack in addition to (3) Be left on the wellhead in the continuing over the winter season is the other equipment required for normal event the drilling rig is moved off ‘‘outdated.’’ The 2019 report concludes operations). location (e.g., due to storms, ice that SSIDs and capping stacks are The need for the operator to account incursions, or emergency situations); superior solutions that could stop the for all potential loads placed on the well (4) Preserve isolation through the flow of oil and allow intervention also includes consideration of winter season without relying on the through the original borehole before a conditions where a well would be shut- elastomer elements of the rams (e.g., by relief well could be completed. (NPC in over the ice season. For example, in using a well cap) and allow re-entry 2109 Report at 19). The SSID typical well control operations, a BOP is during the following open-water season; requirements BSEE is proposing to used to stop the uncontrolled flow and and establish in this proposed rule would shut-in the well. It remains shut-in for (5) In the event of a loss of well not apply to projects outside of the a relatively short period of time while control, preserve isolation until other Arctic OCS. The design requirements for well kill operations are implemented methods of well intervention may be those SSIDs would be based on the and, if needed, materials and personnel completed, including the need to drill a needs of a particular project and may or are mobilized to the rig. relief well. may not be similar to what BSEE is For wells that may be shut-in for BSEE’s analysis of loss of well control proposing in this proposed rule. BSEE extended periods, the operator must events data indicates that the most requests comments on these SSID consider the potential effects of gas common methods employed to regain requirements as outlined in the expansion within the well. For example, control of a well include pumping mud proposed rule. in reservoirs containing gas, which is or cement into the uncontrolled well or Under proposed paragraph (a) of less dense than the liquids in the activating mechanical well control § 250.472, if the operator elects to satisfy wellbore (e.g., drilling mud, completion equipment (e.g., blowout preventer). the requirements of this section by using fluid, brine), the gas will migrate These SSID design requirements an SSID, BSEE would require the upward in the wellbore until it reaches would help ensure the device is capable operator to ensure that the SSID and the closed BOP. This gas exerts a lower of shutting in and containing all fluids well design (including the casing and hydrostatic pressure than the column of within the wellbore for an entire ice cementing program) are designed to oil or drilling fluids in the wellbore, and season (in the case of a loss of well achieve a full shut-in, without causing more of the reservoir pressure is control event too late in the open-water an underground blowout or having transmitted to the top of the wellbore as season to provide enough time for the reservoir fluids broach to the seafloor. a result. As the hydrostatic pressure operator to perform well kill or plug and Currently, BSEE’s regulations for acting on the bubbles decreases, the abandonment operations). BSEE is SCCE under § 250.462 do not require all bubbles expand. basing the proposed design requirement wells to be designed to achieve a full As these bubbles continue to migrate for the SSID to be capable of preserving shut-in (e.g., partial shut-in is and expand over time, the wellbore isolation through the winter season acceptable) as there are methods to pressure profile increases. What was without relying on the elastomer control the residual fluid flow into a once a low pressure at the top of the elements of the rams (e.g., by using a surface production and storage system well, with a hydrostatic pressure well cap) on information it gained from when a well is designed for partial shut- gradient below it, will eventually the Kara Sea project. BSEE understands in. However, because BSEE is proposing increase to reservoir pressure, that the SSID used in the Kara Sea that the SSID be designed to achieve full increasing the downhole pressure. As project was capable of preserving wellbore shut-in until kill operations are the pressures in the wellbore increase, isolation over an entire ice season completed, it is important that the well some of the liquid may bleed into the because it was designed to have a metal- design assures that the well will be able open formation(s). Eventually, the to-metal cap installed on top of the to withstand the associated loads for the SSID, after the BOP is detached and all entire time the SSID is closed (e.g., 48 See, BSEE’s website at https://www.bsee.gov/ equipment is moved off of the drill site. prevents gas migration in the shut-in stats-facts/offshore-incident-statistics. BSEE understands that isolation could

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

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environment is meant to address those necessary for certain emergency this issue, then the SSID may also cases where it may be necessary to place situations. BSEE is aware that in the encounter the same problem, depending the SSID in an enclosed or restricted Arctic OCS, it is possible for a drilling on the part of the drill string that is environment. For example, if the SSID vessel to sink and allide with (i.e., strike across the rams at that time. In this is used in an area with ice scouring or against) the top of a wellhead during a scenario, it would be more appropriate with deep ice keels, the SSID would be loss of well control event (Bratslavsky to assess the situation to determine placed in a mudline cellar. If the ROV and SolstenXP at 17). As discussed in whether other well intervention panels are attached to the SSID, the the previous section, all exploratory operations could be performed to ROV may not be able to access the drilling in the Beaufort Sea and the address the position of the drill string, panels if there is not enough space in Chukchi Sea has taken place in waters before activating the SSID. the cellar. The operator must ensure that less than 167 feet deep, and as recent as Regardless of these challenges, BSEE the ROV has the capabilities to address April 2020,49 there were active leases in is seeking comment on what fail-safe these types of scenarios. BSEE is aware the Beaufort Sea where an SSID could mechanism(s) may be appropriate to of current projects that are evaluating have been deployed. These leases were address cases where the BOP fails and positioning the ROV panels away from located in water depths less than the SSID is inaccessible by an ROV or the SSID. The ROV would function the approximately 170 feet deep. In these a control station. If an autoshear system SSID from the remote panel, which water depths, during an emergency, a or a deadman system are appropriate would be hardwired to the SSID. In vessel could sink before the BOP or fail-safe mechanisms to add to the SSID, addition, it is possible for a mudline SSID can be activated. A self-actuating BSEE is seeking input on what criteria cellar to be constructed via a dragline. system incorporated into the SSID could should be used to function these In such a case, the mudline cellar could potentially address this problem. systems, to ensure the system does not be constructed wide enough to provide One option BSEE is considering is function at the wrong time or interferes adequate space for the ROV to access whether it may be appropriate to with or impacts the BOP’s autoshear the panel if the panel was attached to establish an autoshear and deadman and deadman systems. the SSID. BSEE proposes to make the system requirement for the SSID. The BSEE is also seeking comment on how requirement in proposed paragraph intent would be to address those to ensure that the SSID will be able to (a)(3)(iv) flexible, recognizing that there emergency situations, such as when a preserve isolation over the winter are multiple ways an operator could sunken MODU allides with the season in the event of a late-season address this type of concern. wellhead, where the SSID could no emergency incident, such as a sunken In general, however, BSEE is seeking longer be functioned via the ROV (due drillship. As previously mentioned, comment on the feasibility of installing to lack of access) or a control station on BSEE understands that prior SSIDs have an SSID below a subsea BOP in cases the drill ship. BSEE’s regulations planned for long-term isolation through where the SSID would also be installed already address autoshear and deadman installation of a metal-to-metal cap (i.e., in a mudline cellar. BSEE’s current systems for subsea BOPs. Existing a well cap) on the SSID before leaving regulations at §§ 250.734(a)(13) and § 250.734(a)(6)(i) requires subsea BOPs the device on the seafloor over the 250.738(h) require placement of subsea to have an autoshear system that is winter season. In the case of a late- BOP systems in mudline cellars when designed to automatically shut-in the season emergency situation that drilling occurs in areas subject to ice- wellbore in the event of a disconnect of prevents access to the SSID to install a scouring. In addition, proposed the lower marine riser package (LMRP). metal-to-metal cap, how would isolation § 250.720(c)(2) requires placement of the Also, existing § 250.734(a)(6)(ii) requires be preserved through the winter season? wellhead in a mudline cellar in areas a deadman system, that is designed to In addition, BSEE is soliciting subject to ice-scouring. BSEE is automatically shut-in the wellbore in comment on whether the regulations requesting more information about the event of a simultaneous absence of should require use of an autoshear or whether there are any other operational hydraulic supply and signal deadman system in cases where these or installation challenges that the transmission capacity in the subsea systems are not built into the BOP’s operator may encounter when control pods, respectively. However, system. As previously mentioned, attempting to effectively operate the BSEE did not propose this requirement BSEE’s autoshear and deadman system SSID in this environment. If so, what are for SSIDs in this rulemaking. The SSID requirements currently apply to subsea those challenges, and how could they be is meant to be a backup to the BOP, and BOPs. There is no current requirement addressed? it is not necessary for the SSID to have to use an autoshear or deadman system BSEE understands that the SSID used the same automatic emergency when surface BOPs are used. BSEE in the Kara Sea could be manually functions as the BOP. would expect that if an operator uses a activated using acoustic technologies. There could potentially be negative surface BOP, the operator would still While such technologies are available to consequences if both systems were to install the SSID on the seafloor. BSEE function the SSID from a remote automatically function. For example, seeks comment on whether it would be location, BSEE is proposing to require there could be a situation where the appropriate in such a case to require use use of an ROV, as described in proposed BOP’s autoshear or deadman systems of an autoshear or deadman system on paragraph (a)(3). BSEE understands that function, but they are not able to shut- the SSID. If so, what criteria should ROVs are more reliable for this type of in the well because a non-shearable drill BSEE apply to the functioning of the application. However, BSEE requests string is positioned across the rams. If autoshear or deadman systems in an that commenters provide any the subsea BOP rams are experiencing environment where a surface BOP is information that demonstrates the used? Furthermore, BSEE welcomes any reliability of acoustic (or other) 49 In April 2020, the only leases with potential other comments, unrelated to autoshear technologies to actuate an SSID from a projects that would be subject to the Arctic OCS’s or deadman systems, regarding use of a remote location. SSID or SSRW requirements were relinquished. surface BOP. Furthermore, although BSEE is not However, there are other active leases in the With respect to installation of the Beaufort Sea located nearer to the shore in proposing to require the SSID to have a shallower waters where exploration and SSID, BSEE proposes in paragraph (a)(4) self-actuating function, the Bureau is development projects are actively being pursued to require operators to install the SSID: contemplating whether one may be (primarily through man-made gravel islands). (1) Below the BOP;

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

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

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

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the summer and early fall when ice regulations at proposed § 550.220(c)(1), seeking comment on whether there are hazards can be physically managed and BOEM would require the operator to other appropriate approaches to well there is no continuous ice layer over the submit a description of how all vessels control operations in the Arctic, water), it was critical to ensure that and equipment will be designed, built, including alternative equipment/ drilling (including relief well drilling) and/or modified to account for Arctic technology or performance standards. and other operations affected by sea ice OCS conditions and how such activities For example, although the NPC 2019 are concluded before ice encroachment. will be managed and overseen as an Report recommends accepting the use of Ice encroachment may complicate or integrated endeavor. This preamble an SSID in place of the requirement for prevent drilling, transit, and oil spill discusses this proposed regulatory SSRW capability, it also recommends response operations. However, the change in more detail later. Collectively, replacing the relief rig and SSRW analysis from the Bratslavsky and this information provided in an EP requirements with requirements that SolstenXP study shows that the sea ice would allow BOEM (in conjunction specify the desired outcome (i.e., to stop capabilities of an ice class MODU and with BSEE) to evaluate the capability of the flow of a well and allow the operator its support vessels can extend the the operator’s equipment, including its to propose equivalent technology and currently available open-water operating vessels and procedures to manage and demonstrate its capabilities). (NPC 2019 seasons in the Chukchi and Beaufort mitigate risks associated with Arctic Report at 30). BSEE assumes that the Seas, depending on the drilling location OCS conditions. NPC recommends specifying a desired within each planning area (id. at 143). At the APD stage, BSEE would also performance-based outcome in the Therefore, BSEE proposes to eliminate review the capabilities of the operator’s regulations that would allow the the reference to ‘‘expected seasonal ice MODU and associated supporting operator to propose and demonstrate encroachment’’ at the drill site in vessels. Existing paragraph (a)(2) of technologies capable of meeting that existing paragraph (b). BSEE, however, § 250.470, What additional information standard at the permitting stage, rather would retain the requirement clarifying must I submit with my APD for Arctic than prescribing a particular technology, that the relief rig must be different than OCS exploratory drilling operations? such as a relief rig. the operator’s primary drilling rig and requires the operator to describe how it Subpart G—Well Operations and that the relief rig must be staged in a plans to prepare its equipment, Equipment location such that it can arrive on site, materials, and drilling unit for service in drill a relief well, kill and abandon the the environmental, meteorological, and When and how must I secure a well? original well, and abandon the relief oceanic conditions it expects to (§ 250.720) well no later than 45 days after the loss encounter at the well site and how its drilling unit will be in compliance with BSEE proposes to delete the last of well control. This proposed sentence in existing paragraph (c)(2) regulatory change would effectively the requirements of existing § 250.713, What must I provide if I plan to use a that states ‘‘BSEE may approve an extend the drilling season in those cases equivalent means that will meet or where the operator’s MODU and Mobile Offshore Drilling Unit (MODU) for well operations. Paragraph (d) of exceed the level of safety and associated support vessels are capable of environmental protection provided by a safely operating beyond the period § 250.713 requires the operator, when using a MODU for well operations, to mudline cellar if the operator can show when seasonal sea ice begins to that utilizing a mudline cellar would encroach at a drill site. The operator provide the current Certificate of Inspection (for U.S.-flag vessels) or compromise the stability of the rig, would no longer need to plan for their Certificate of Compliance (for foreign- impede access to the well head during well operations to end in time to flag vessels) from the USCG, as well as a well control event, or otherwise create complete a relief well prior to the date a Certificate of Classification. The operational risks.’’ In its place, BSEE when sea ice is expected to encroach on operator must also provide current proposes to insert a new sentence that the drill site. The operator would, documentation of any operational states ‘‘You may request, and the instead, have to plan to end its limitations imposed by an appropriate Regional Supervisor may approve, an operations with sufficient time to classification society. As discussed alternate procedure or equipment in complete its relief well prior to the earlier in this section, the Bratslavsky accordance with §§ 250.141 and anticipated date when sea ice and SolstenXP study notes that a 250.408.’’ BSEE, however, would conditions at the drill site are vessel’s capabilities are identified by the preserve the basic requirement in in approaching the ice classification ice classification for the vessel, which is paragraph (c)(2) for the operator to use capability and rating limits of the provided by marine classification a mudline cellar or an equivalent means operator’s vessels. societies such as ABS and DNV GL. if there is indication of ice scour. The BSEE and BOEM would evaluate the BSEE would evaluate the information regulatory change BSEE is proposing in ice classification capabilities and required under existing §§ 250.470(a)(2) this section would make clear that BSEE limitations of the operator’s MODU and and 250.713(d), together with BOEM’s could approve the equivalent means of associated support vessels using approval of the operator’s end-of-season doing so in accordance with §§ 250.141, existing permitting and review date(s) in the EP, to verify whether the May I ever use alternate procedures or processes. For example, through vessels’ capabilities and limitations can equipment? and 250.408, May I use BOEM’s EP review process, the operator support extending operations beyond alternate procedures or equipment is required under existing when seasonal ice is expected to arrive during drilling operations? § 550.220(c)(6) to specify when it at the drill site. However, in no case will The new language that BSEE proposes anticipates completing onsite operations BSEE approve a permit that proposes to to insert reiterates longstanding and when it anticipates terminating use a vessel that does not meet the regulatory provisions contained in drilling operations. In addition, existing requirements of § 250.713, §§ 250.141 and 250.408 that describe § 550.220(c)(1) requires the operator to including providing a current certificate what procedures the operator must describe how it will design and conduct of inspection or compliance from the follow and standards it must meet to its exploratory drilling activities in a USCG. receive BSEE’s approval of a request to manner that accounts for Arctic OCS Finally, while BSEE is proposing use alternate procedures or equipment conditions. Furthermore, in the EP these revisions to § 250.472, BSEE is to those required by regulation. Section

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250.141 allows the BSEE District B. Key Revisions Proposed by BOEM subject to agency approval. BOEM Manager or Regional Supervisor to developed the IOP requirement based Title 30, Chapter V, Subchapter B, Part on the Report to the Secretary of the approve the use of any alternate 550, Subpart B—Plans and Information Interior, Review of Shell’s 2012 Alaska procedures or equipment that the Definitions. (§ 550.200) operator may propose if the proposal Offshore Oil and Gas Exploration provides a level of safety and BOEM is proposing to eliminate the Program, prepared by DOI (60-Day 50 environmental protection that equals or definition of the term ‘‘Integrated Report), March 2013, which Operations Plan,’’ consistent with the 51 surpasses BSEE’s current requirements. included the following proposal to eliminate the requirement recommendation: It also describes the types of information for the operator to submit an IOP for the All phases of an offshore Arctic program— the operator must submit or present to reasons listed immediately below. BSEE when requesting to use alternate including preparations, drilling, maritime and emergency response operations—must be procedures or equipment. Section Removal of the IOP Requirement (§ 550.204) integrated and subject to strong operator 250.408 requires the operator to identify management and government oversight. (60- and discuss their proposed alternate The 2016 Arctic Exploratory Drilling day report, p. 3). procedures or equipment in their APD. Rule discussed how commenters The information provided in the IOP Since the issuance of the 2016 Arctic generally criticized the IOP provision as was intended to facilitate the prompt Exploratory Drilling Rule, BSEE learned being duplicative or redundant of sharing of information among the existing requirements (see 81 FR at that there is an industry misconception relevant Federal agencies (e.g., BOEM, 46492–46493). In 2016, when the rule that the last sentence in existing BSEE, USFWS, USCG, NMFS, U.S. was adopted, BOEM disagreed with Army Corps of Engineers, and EPA). paragraph (c)(2) means that the operator these commenters and published would be required to use a mudline Standing BOEM practice (LP–SOP–06 responses to the commenters in the Standard Operating Procedure for cellar in all cases, except when the preamble. In its responses, BOEM Exploration Plans) in the Anchorage, operator can prove that the mudline discussed how the IOP was distinct Alaska OCS Office is to inform other cellar would present an operational from existing regulations, the agencies about an operator’s EP, well in risk—effectively narrowing the scope of importance of contractor management as advance of the completeness review §§ 250.141 and 250.408 in this context. it related to the IOP provisions, and the (i.e., the deemed submitted However, BSEE did not intend that BOEM Regional Director’s ability to determination) for the EP. BOEM language to constrain the contexts in waive submission of required successfully did so prior to the 2016 which operators could seek approval of information in the EP that was already implementation of the IOP requirement. provided in the IOP. Circumstances alternatives to the mudline cellar The IOP requirement does not have changed since the IOP requirement requirement. Rather, in response to supersede or supplant the operator’s was originally adopted. The various commenters expressing concern that use obligation to comply with all other Federal agencies have improved their of a mudline cellar may create applicable Federal agency requirements. coordination to such an extent that operational risks in certain contexts, As described in the 2016 Arctic BOEM believes there is no need for BSEE introduced that language to make Exploratory Drilling Rule, the IOP operators to create and submit a clear that alternate approaches were process does not provide a mechanism separate IOP for that purpose. Much of available in those contexts, while at the for agencies to approve or disapprove the required content of the two same time highlighting the general the operator’s proposed activities. documents overlaps, and in the 2016 flexibility available under § 250.141, BOEM has no authority under the IOP rulemaking itself BOEM added provision other than to make May I ever use alternate procedures or requirements that the EP include unenforceable suggestions to the equipment? (see 81 FR 46507 and additional information that made this operator. If BOEM or another agency 46510). The last sentence in existing overlap even greater. BOEM is now determined that an operator was failing paragraph (c)(2) was not intended to, proposing to keep two important to engage in the needed integrated and did not, restrict or preclude use of provisions from the IOP and incorporate planning in advance of EP submission, the longstanding options for seeking them into the requirements for EPs. The BOEM could only compel an operator to approval of alternate procedures or first provision would reinforce BOEM’s do so through the EP review process. equipment under §§ 250.141 and commitment to operational safety, while 250.408, which do not necessarily The 2016 Arctic Exploratory Drilling the second provision would require the Rule added informational requirements require a demonstration of operational operator to provide details of how its for EPs to address key concerns that risk. Thus, this proposed change would operations would conform to the unique motivated the IOP, as shown in Table 1, clarify that the operator has more circumstances of the Arctic OCS. Taken ‘‘Crosswalk between the IOP provisions flexibility to propose alternate solutions together, the enhancements to BOEM’s proposed for removal and existing EP to the mudline cellar requirement under regulations made in connection with the regulations and review practices.’’ a broader range of circumstances than 2016 Arctic Exploratory Drilling Rule Because this information is required in those described in the last sentence of and the retention of these key the EP, operators should be aware that existing § 250.720(c)(2). An operator provisions from the IOP make the IOP they must plan for how they will could still base such a request on the unnecessary and redundant. manage contractors to reduce same grounds that BSEE described in For these reasons, BOEM proposes to eliminate the requirement for preparing the language that we propose to delete 50 Available at: https://www.doi.gov/sites/doi.gov/ (i.e., that installation of a mudline cellar and submitting the IOP. In doing so, files/migrated/news/pressreleases/upload/Shell- BOEM would delete all of § 550.204, in a specific case would cause report-3-8-13-Final.pdf. and remove corresponding references to 51 Report to the Secretary of the Interior, Review operational risks). the IOP from §§ 550.200 and 550.206. of Shell’s 2012 Alaska Offshore Oil and Gas Exploration Program, prepared by DOI (60-Day Currently, BOEM requires the operator Report), March 2013, available at: https:// to submit an IOP at least 90 days before www.doi.gov/sites/doi.gov/files/migrated/news/ filing an EP with BOEM. The IOP is not pressreleases/upload/Shell-report-3-8-13-Final.pdf.

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

§ 550.204(a)—The operator describes how vessels and equip- § 550.220 (c)(1)—The operator describes how drilling activities account for Arc- ment were designed for Arctic OCS conditions; tic OCS conditions. § 550.204(b)—The operator includes a schedule of the explor- § 550.211(a)—The operator includes a schedule and discussion of objectives atory program; for its exploration program. § 550.204(c)—The operator describes how its plans account for § 550.220 (c)(1)—The operator describes how drilling activities account for Arc- Arctic OCS conditions; tic OCS conditions. § 550.220(c)(2)—The operator describes weather and ice forecasting and man- agement 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. § 550.204(d)—The operator describes general abandonment § 550.211(a)—The operator includes a schedule and discussion of objectives plans for wells; for its exploration program. § 550.220 (c)(1)—The operator describes how drilling activities account for Arc- tic OCS conditions. § 550.220(c)(2)—The operator describes weather and ice forecasting and man- agement 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. § 550.204(e)—The operator describes its plans for responding § 550.220(c)(2)—The operator describes weather and ice forecasting and man- and managing ice hazards and weather events; agement plans. § 550.220(b)—The operator would describe critical operations and curtailment procedures. § 550.204(f)—The operator describes work to be performed by § 550.220 (c)(1)—The operator describes how drilling activities account for Arc- contractors; tic OCS conditions. § 550.220(c)(2)—The operator describes weather and ice forecasting and man- agement 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. § 550.204(g)—The operator describes how it will ensure oper- § 550.211(c)—The operator would describe the drilling unit, associated equip- ational safety; ment, safety features, and storage of fuels and oils. § 550.220 (c)(1)—The operator describes how drilling activities account for Arc- tic OCS conditions.

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

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

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

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

Existing regulation text New provision

§ 550.204(a)—The operator describes how vessels and equip- § 550.220(c)(1)—The operator describes how the exploratory drilling (including ment were designed for Arctic OCS 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. § 550.204(g)—The operator describes how it will ensure oper- § 550.211(b)—the operator describes how it will ensure operational safety. ational safety;

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

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(3) How it will communicate such suitability of vessels for Arctic supporting reasons and data for your principles to its employees and conditions. These vessels may have or responses. contractors; and acquire classification from a (i) Well Design When Using an SSID (4) How it will determine successful ‘‘recognized organization’’ under the (§ 250.472(a))—BSEE is seeking implementation of such principles. USCG’s Alternative Compliance comments on how well design could be The text of this transferred regulation Program (ACP).52 This specification better addressed in this rulemaking to provision is identical to what it was in provides the operator with guidance on enhance the overall safety of operations § 550.204(g). As such, this addition to what information the EP should contain on the Arctic OCS. More specifically, § 550.211 will not impose any new to show that its vessels would be able BSEE would like to know whether the burden on lessees or operators. BOEM to operate safely in the Arctic OCS. The well design requirement in proposed believes that retaining this important specification would also show that § 250.472(a) is adequate to address safety and environmental protection is a BOEM is not duplicating regulations situations the operator may encounter if necessary part of ensuring that energy from USCG by acknowledging that the a well is shut-in with an SSID over an exploration and development activity is flag state, USCG, and/or the entire winter season (e.g., six to nine safe and environmentally responsible. classification society have authority for months). These situations could include If I propose activities in the Arctic OCS approvals, allowances, and limitations cases where the wellbore pressure Region, what planning information must placed upon modified vessels. For these profile may increase to reservoir accompany the EP? (§ 550.220) reasons, this change would impose no pressures at the top of the well over the material additional burden on lessee or course of the winter season. BSEE BOEM proposes to revise paragraphs operators beyond that which already would also like to know whether there (c)(1) and (4), and (c)(6)(ii) of § 550.220 exists and which has already been are other scenarios that may occur in a to conform to BSEE’s proposed changes accounted for in the information shut-in well over the ice season. to § 250.472, What are the additional collection burden for this section. (ii) SSID Efficacy Relative to the Relief well control equipment or relief rig To ensure consistency with BSEE’s Rig and SSRW—BSEE is proposing to requirements for the Arctic OCS? proposed regulatory changes, BOEM is revise the relief rig and SSRW Existing paragraph (c)(1) of § 550.220 proposing to revise paragraphs (c)(4) requirement with the intent to minimize would be revised to add text to account and (c)(6)(ii) by requiring the operator to environmental damage due to a for the text in existing § 550.204(a), provide a general description of how prolonged ongoing well control event. which would be removed. With the they will comply with § 250.472, When drilling a relief well, there is a elimination of § 550.204, BOEM including a description of the delay in stopping the uncontrolled flow proposes to combine the requirements termination of their operations. BSEE is of oil and other fluid into the marine of these two sections into a revised proposing to revise § 250.472 to provide environment while relief well drilling § 550.220(c)(1) that would require the the operator with the option to either operations are taking place. When operator to describe how its exploratory use an SSID or have access to a relief properly functioning as designed, there drilling (including vessels and rig, as an additional means to secure the is usually no delay for operational use equipment) would account for Arctic well in the event of a loss of well of an SSID compared to the process of OCS conditions, including any control, if the operator will be utilizing the relief rig or capping stack. allowances or limitations its vessels conducting exploratory drilling If the SSID does not initially function, have from a classification society and/ operations from a MODU. the SSID may still be activated through or the USCG. the ROV intervention equipment and BOEM is proposing to add a new III. Additional Comments Solicited capabilities that BSEE is proposing as a informational requirement for modified To assist BSEE and BOEM in these SSID design requirement. The SSID vessels. BOEM is seeking to confirm that revisions, we are requesting public would operate independently from the the operator meets the requirements of comments on specific issues discussed BOP. By having two independent, other entities with authority over in the preamble. We will consider these redundant components, as part of the vessels, not to impose requirements on comments while developing final well control system, the overall those vessels. Although this revised regulations. To provide necessary reliability and effectiveness of the entire paragraph would appear to add new context, we included the requests for system increases. BSEE would like to requirements, in fact this revision public comments in appropriate know of any cases or data, in addition would simply clarify and formalize the locations throughout the preamble. For to what we have already discussed in existing arrangements between BOEM ease of commenting, we consolidated the preamble, regarding the performance and these other entities. This provision the requests for comments in this and reliability of the SSID and its is proposed in order to avoid any section of the preamble. While BSEE effectiveness compared to drilling a potential confusion that might and BOEM are soliciting comment on relief well. otherwise arise regarding the specific topics associated with the (iii) NPC Report and Bratslavsky and incorporation of the existing IOP proposed rule, the bureaus welcome the SolstenXP Study—The NPC 2019 Report requirements into the EP and how they public to submit information or and the Bratslavsky and SolstenXP may relate to the regulations and comment on any other topics relevant to study have been valuable tools that were jurisdiction of the United States Coast this rulemaking that may not necessarily not available when promulgating the Guard, or the flag state of the vessel. pertain to the bureaus’ specific 2016 Arctic Exploratory Drilling Rule. According to this proposed revision, for solicitation. At this stage, the bureaus BSEE requests the public to provide vessel modifications, the operator are open to considering any option that additional information or clarification would describe any approvals from the would improve the regulatory changes related to those portions of these reports flag state and vessel classification proposed, including maintaining the that the Bureau relied upon in this society and include in that description original requirement as part of the final rulemaking. any allowances or limitations placed rule. In all cases, please provide (iv) SSID Capability to Preserve upon the vessel by the classification Isolation Over the Winter Season society and/or USCG. Vessel 52 33 U.S.C. 3316 and 46 CFR part 8 implement (§ 250.472(a)(1)(iv))—BSEE proposes to modifications may include the the USCG’s ACP. require that the SSID must be capable of

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

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subsea BOP system may have failed and leaseholding activities due to seasonal technology. Forgone benefits result from the SSID could no longer be functioned conditions. BSEE is seeking comment slight increases in the risks to via the rig or ROV (due to lack of on this regulatory option for the new subsistence hunters and fishermen and access). BSEE currently has fail-safe SOO provision it is proposing in a new wildlife stemming from an increased requirements for subsea BOP systems paragraph (d) of § 250.175, or any other probability of small or catastrophic oil (autoshear and deadman systems), option that could avoid or minimize the spills. The cost savings exceed the which could be applied to SSIDs. additional burdens associated with forgone benefits, leading to the net However, there could be unintended making requests on an annual basis (if benefits summarized in the following consequences from applying these fail- the duration of the suspension needs to paragraphs. safe systems on an SSID when a subsea be longer), but still assure diligent lease This proposed rule would revise BOP system is used. BSEE is seeking exploration and development. regulatory provisions in 30 CFR part comment on what fail-safe mechanisms (xvi) Other Solicited Comments— 250, subparts A, C, D, and G, and 30 could be deployed to address cases BSEE is also requesting comments on CFR part 550, subpart B. BSEE and where the BOP fails and the SSID is the specific costs and operational BOEM have reassessed a number of the inaccessible by an ROV or a MODU implications of each of the regulatory provisions promulgated through the control station. If an autoshear system or changes included in this proposed rule. 2016 Arctic Exploratory Drilling Rule a deadman system are appropriate fail- IV. Procedural Matters and are proposing to revise some safe mechanisms, BSEE is seeking input provisions to reflect performance-based on what criteria should be used to A. Regulatory Planning and Review standards rather than prescriptive function these systems, to ensure they (Executive Orders (E.O.) 12866, 13563, requirements. Other revisions remove do not function at the wrong time or and 13771) redundant regulatory oversight interfere with or impact the subsea Executive Order 12866 provides that provisions and provide regional BOP’s autoshear and deadman systems. the Office of Information and Regulatory flexibility in the administration of (xiii) Autoshear and Deadman System suspensions and associated lease term Requirements for Surface BOPs—BSEE Affairs (OIRA) within OMB will review all significant rules. This proposed extensions, without significantly is contemplating establishing autoshear impacting the current levels of safety and deadman system requirements in action is an economically significant regulatory action that was submitted to and environmental protection. The cases where operators use a surface bureaus sought the best available data BOP. BSEE does not currently require OMB for review, as it would have an annual effect on the economy of $100 and information to analyze the the use of an autoshear or deadman economic impact of these changes. The system with surface BOPs. BSEE is million or more. BSEE and BOEM IRIA for this rulemaking can be found seeking comment on what criteria developed an economic analysis to in the https://www.regulations.gov/ should be established to function the assess the anticipated costs and docket (Docket ID: BSEE–2019–0008). autoshear or deadman systems in potential benefits of the proposed rule. connection with a surface BOP. BSEE Due to uncertainty surrounding the BSEE and BOEM are proposing to welcomes any other comments, outcome of ongoing litigation regarding revise certain regulations promulgated unrelated to autoshear or deadman the availability of Arctic OCS planning through the 2016 Arctic Exploratory systems, which require additional areas for future leasing and energy Drilling Rule based on new information consideration in those cases where a development, BSEE and BOEM generated since the 2016 rule was surface BOP is used. developed two baseline activity level finalized, and to support the goals of the (xiv) Outcome-based Well Control forecasts: (1) Activity levels expected if Administration’s regulatory reform System Requirements—BSEE is seeking the full Beaufort and Chukchi Sea initiatives, while ensuring safety and comment on other appropriate planning areas are reopened (i.e., the environmental protection. This approaches to well-control operations in Full Arctic baseline), and (2) reduced proposed rule would revise certain the Arctic. The NPC 2019 Report activity levels if these areas remain existing regulations—§§ 250.105; recommends accepting the use of an withdrawn from leasing (i.e., the 250.175; 250.198; 250.300(b); SSID in place of the requirement for Restricted Beaufort baseline). Under 250.470(b), (f), and (h); 250.471(a) and SSRW capability. However, it also either scenario, the proposed action (b); 250.472(a), (b), and (c); 250.720(c); recommends replacing the relief rig and would be economically significant as a 550.200; 550.204; 550.206; 550.211; and SSRW requirements with requirements result of the estimated cost savings of 550.220(c). The bulk of the net benefits that specify desired outcomes (i.e., to this proposed rule. BSEE and BOEM are derived from cost savings driven by stop the flow of a well and allow the estimate the amendments proposed in a proposed revision to existing operator to propose equivalent this rulemaking would provide § 250.472(b) and (c), which is discussed technology and demonstrate its annualized net benefits of $142 million below. The analysis suggests forgone capabilities). BSEE assumes that the under the Full Arctic baseline, or $121 benefits are small compared to the cost NPC recommendation would entail a million under the Restricted Beaufort savings, and the primary forgone performance-based approach to the baseline, discounted at 7 percent. benefits are from possible impacts on regulations, in which the operator could Details on the estimated cost savings the environment and subsistence propose and demonstrate new of this proposed rule can be found in hunting and whaling communities, that technologies to meet a stated objective, the rule’s Initial Regulatory Impact could be caused by an oil spill of greater rather than being required to use certain Analysis (IRIA). The net quantified duration and higher discharge volumes technologies, such as a relief rig. benefits for this proposed rule are based in the event the BOP, SSID, and capping (xv) Suspension of Operations—BSEE on cost savings less forgone benefits. stack were to fail in sequence, and a is considering the option of limiting the The cost savings to both government containment dome and flow system period during which a suspension and industry result from removing would be needed to capture oil flowing would remain in effect to the period regulatory redundancies, reduction in from the well while relief-well drilling between one drilling season and the paperwork burdens, provision for operations are underway. These, and the next when the operator is prevented alternative methods of compliance, and other provisions, are discussed in from continuing its drilling or other adoption of improved industry greater detail within the IRIA.

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The largest contributor to net benefits assumes operators will prefer this during that delayed period, would be attributable to the proposed rule is the option when using MODUs. This the contributing factor to the proposed proposed revision to existing § 250.472 proposed change would produce an rule’s forgone benefits. However, as paragraphs (a), (b), and (c). As annualized cost savings of $142 million discussed in the IRIA, the probability of promulgated under the 2016 Arctic under the Full Arctic baseline, or $121 a catastrophic spill event (as a result of Exploratory Drilling Rule, this provision million under the Restricted Beaufort the BOP and SSID systems experiencing currently requires the use of a ‘relief rig’ baseline, discounted at 7%. total failures) is low. Coupled with a and adoption of a 45-day shoulder This proposed rule would reduce the scenario in which a BOP, SSID, and season. The relief rig is a secondary burden imposed on industry, while capping stack were all to fail, the drilling vessel that is available and maintaining safety and environmental probability of realizing these forgone capable of drilling an SSRW in the event protection. The forgone benefits of benefits may be even lower. of a loss of well control. The 45-day adopting the proposed rule include Nonetheless, the possibility exists and if ‘‘shoulder season’’ was the maximum possible impacts on the environment, the BOP were to fail and the SSID were time permitted by the regulations to subsistence hunting and whaling to function as designed, there would be mobilize the relief rig to an incident, communities, and an oil spill of greater no forgone benefits in comparison to the drill a relief well, kill and abandon the duration with higher discharge volumes existing regulations (and there might be original well, and abandon the relief in the event a BOP and SSID were to a gained benefit since the SSID would fail. As discussed earlier in the well prior to expected seasonal ice activate immediately). preamble, BSEE proposes to require encroachment at the drill site. This As part of the final rule, BSEE and operators to operate an SSID shoulder season necessarily compresses BOEM are contemplating the independently from the BOP. By having the already short Arctic drilling preparation of a sensitivity analysis for two independent, redundant the Final RIA and are soliciting timeframe and also limits the ability of components (i.e., the BOP and the SSID) comments on ways to make the analysis operators to drill and complete a well in as part of the well control system, the as accurate as possible. The information one season. The proposed revisions to overall reliability and effectiveness of we receive through public input on this § 250.472 would provide the operator the entire system increases. In the event with the option to either use an SSID or both devices were to fail, the capping proposed rule regarding the SSID’s have access to a relief rig, as an stack would still be used as required in performance, reliability, and additional means to secure the well in the permitted timeframe. When a effectiveness may inform the the event of a loss of well control, if the capping stack is used to contain a well, preparation of a sensitivity analysis. operator will be conducting exploratory the relief well can be drilled without an The timeframe of the present analysis drilling operations from a MODU. The ongoing active spill event. If the capping is 24 years, composed of an initial 4 two features of this flexibility driving stack were to fail, the containment dome years with no activity followed by 20 the cost savings are the removal of the and flow system would be used to years of activities beginning in 2024. shoulder season and removal of the capture the oil flowing from the well The two tables below summarize BSEE’s requirement for the secondary drilling while relief-well drilling operations are and BOEM’s estimates of the total and vessel, if the operator elects to install an underway. annual net benefits derived from all SSID to comply with § 250.472. Because Given that the proposed rule would proposed revisions and additions. of the relative cost effectiveness of remove the arrival timing requirement Additional information on the time procuring, and potential well control for these pieces of equipment, there may horizon, compliance costs, savings, advantages of installing an SSID versus be a delay in their arrival, in benefits, and forgone benefits may be mobilizing a relief rig and the necessary comparison to the existing regulations. found in the IRIA published in the rule support vessels and personnel, BSEE The amount of oil flowing from the well 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 BSEE and BOEM are providing industry the proposed revisions would be multiple provisions in the current flexibility, when practical, to meet the consistent with the policies of the regulations to implement performance- safety or equipment standards, rather applicable E.O.s and the OCSLA. based provisions based upon reasonably than specifying the compliance method. Executive Order 13563 reaffirms the obtainable information on safety, Based on a consideration of the principles of E.O. 12866 while calling technical, economic, and other issues. qualitative and quantitative safety and for improvements in the Nation’s Redundant or unnecessary reporting environmental factors related to the regulatory system to promote requirements are also being eliminated. rule, BSEE and BOEM determined that predictability, to reduce uncertainty,

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and to use the best, most innovative, Arctic OCS. This proposed rule would disproportionate budgetary effects on and least burdensome tools for directly affect all four Arctic lessees. these governments. BSEE and BOEM achieving regulatory ends. The E.O. Based on the small entity criterion, none have determined the proposed changes directs agencies to consider regulatory of the four businesses are considered a in this rulemaking would result in cost approaches that reduce burdens and small entity. No small companies hold savings annually to regulated entities. maintain flexibility and freedom of leases on the Arctic OCS. Previously, a Therefore, a written statement under the choice for the public where these single small company with only one Unfunded Mandates Reform Act (2 approaches are relevant, feasible, and lease held acreage on the Arctic OCS. U.S.C. 1531 et seq.) is not required. consistent with regulatory objectives. This company relinquished its lease in E.O. 13563 emphasizes that regulations March 2016. D. Takings Implication Assessment must be based on the best available BSEE and BOEM prepared an Initial Under the criteria in E.O. 12630, this science and that the rulemaking process Regulatory Flexibility Analysis (IRFA), proposed rule would not have must allow for public participation and which can be found in Section VII of the significant takings implications. The an open exchange of ideas. Furthermore, IRIA. Given the challenging proposed rule is not a governmental it promotes retrospective review of environment and associated costs of action capable of interference with existing regulations that may be drilling in the Arctic OCS planning constitutionally protected property outmoded, ineffective, insufficient, or areas, no small entities are expected to rights. A Takings Implication excessively burdensome. BSEE and operate in these areas for the foreseeable Assessment is not required. BOEM have reviewed the existing future. Therefore, BSEE and BOEM E. Federalism (E.O. 13132) regulations as amended by the 2016 preliminarily conclude that no small Rule and have developed this proposed entities would be affected by these Under the criteria in E.O. 13132, this rule in a manner consistent with E.O. proposed amendments, however the proposed rule would not have 13563. agency has prepared an IRFA and is federalism implications. This proposed Executive Order 13771 requires seeking public comment on any small rule would not substantially and Federal agencies to take proactive business impacts from the proposed directly affect the relationship between measures to reduce the costs associated amendments. the Federal and State Governments. To with complying with Federal This proposed rule would meet the the extent that State and local regulations. This proposed rule is an E.O. 12866 criteria for an economically governments have a role in OCS E.O. 13771 deregulatory action. significant rule because it would likely activities, this proposed rule would not have an annual effect on the economy affect that role. A Federalism B. Regulatory Flexibility Act and Small of $100 million or more in at least one Assessment is not required. Business Regulatory Enforcement year of the 20-year period analyzed, and Fairness Act BSEE/BOEM comply with the RFA and F. Civil Justice Reform (E.O. 12988) The Regulatory Flexibility Act (RFA), the Small Business Regulatory This proposed rule complies with the 5 U.S.C. 601–612, requires agencies to Enforcement Fairness Act by providing requirements of E.O. 12988. analyze the economic impact of a regulatory flexibility analysis. The Specifically, this rule: regulations when there is likely to be a requirements would apply to all entities 1. Meets the criteria of section 3(a) significant economic impact on a operating on the Arctic OCS regardless requiring that all regulations be substantial number of small entities and of company designation as a small reviewed to eliminate errors and to consider regulatory alternatives that business. For more information on the ambiguity and be written to minimize will achieve the agency’s goals while small business impacts, see the IRFA litigation; and minimizing the burden on small section in the IRIA. Small businesses 2. Meets the criteria of section 3(b)(2) entities. The proposed rule would affect may send comments on the actions of requiring that all regulations be written operators and Federal oil and gas lessees Federal employees who enforce, or in clear language and contain clear legal that could conduct exploratory drilling otherwise determine compliance with, standards. on the Arctic OCS. The RFA defines Federal regulations to the Small G. Consultation With Indian Tribes (E.O. small entities as small businesses, small Business and Agriculture Regulatory 13175) nonprofits, and small governmental Enforcement Ombudsman, and to the jurisdictions. No small nonprofits or Regional Small Business Regulatory Under the criteria in E.O. 13175, small governmental jurisdictions have Fairness Board. The Ombudsman Consultation and Coordination with been identified that would be impacted evaluates these actions annually and Indian Tribal Governments (dated by this rule. rates each agency’s responsiveness to November 6, 2000), DOI’s Policy on Businesses subject to this proposed small business. If you wish to comment Consultation with Indian Tribes and rule fall under North American Industry on actions by employees of BSEE or Alaska Native Corporations (512 Classification System (NAICS) codes BOEM, call 1–888–REG–FAIR (1–888– Departmental Manual 4, dated 211111 (Crude Petroleum and Natural 734–3247). November 9, 2015), and DOI’s Gas Extraction) and 213111 (Drilling Oil Procedures for Consultation with Indian and Gas Wells). For these C. Unfunded Mandates Reform Act of Tribes (512 Departmental Manual 5, classifications, a small business is 1995 (UMRA) dated November 9, 2015), we evaluated defined as one with fewer than 1,250 This proposed rule would not impose the subject matter of this rulemaking employees (NAICS code 211111) and an unfunded Federal mandate on State, and determined that it would have tribal fewer than 1,000 employees (NAICS local, or tribal governments and would implications for Alaska Natives. As code 213111), respectively. A small not have a significant or unique effect described earlier, future Arctic OCS entity is one that is ‘‘independently on State, local, or tribal governments. exploratory drilling activities conducted owned and operated and which is not The requirements in this proposed rule pursuant to this proposed rule could dominant in its field of operation.’’ would apply to Arctic OCS oil and gas affect Alaska Natives, particularly their According to BOEM’s list of Arctic lessees and operators, not to State, local, ability to engage in subsistence and OCS leaseholders, four businesses and tribal governments. Thus, the cultural activities. However, as currently hold lease interests on the proposed rule would not have discussed earlier in Section I.

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Background, Subsection E. Partner In addition, Alaska Natives may also On September 20, 2018, BSEE and Engagement in Preparation for This be beneficiaries of the proposed rule, to BOEM began reaching out to leaders Proposed Rule, Item 2. Summary of the extent they are partners in any from Alaska Native Tribes, ANCSA Comments Received, BOEM’s exploratory activities. There are Corporations, and municipalities to environmental studies program has additional unquantified benefits in determine which partners were provided nearly $500 million over the situations where a SSID is available to interested in having conversations with last 46 years to scientific research on the immediately shut-in a flowing well BSEE and BOEM about the rulemaking. Alaska OCS, which includes the Arctic rather than waiting for a relief well to Consultations entailed meetings in OCS. Since July 2016, BOEM has be drilled. Alaska, at locations and times BSEE and BOEM are committed to completed 35 environmental studies convenient to the Alaska Native regular and meaningful consultation and has 23 ongoing studies that cover communities and corporations, to and collaboration with Alaska Native the Arctic, totaling nearly $72 million. Tribes and ANCSA Corporations on ensure they can have proper While this proposed rule would change policy decisions that have tribal representation during the meetings. how operators could explore for OCS implications, including, as an initial Accordingly, the timing of these resources in the Arctic, there are ample step, through complete and consistent meetings was critical. BSEE and BOEM opportunities to permit these activities implementation of E.O. 13175, together scheduled the meetings around consistent with ESA, MMPA, NEPA, with related orders, directives, and important traditional subsistence and and consultation with Alaska Native guidance. Therefore, BSEE and BOEM cultural activities, such as whaling, that communities. BOEM’s environmental engaged in Government-to-Government take place during specific times of the studies program provides the tribal consultations, Government-to- year, particularly in the early fall. information that is used to evaluate the ANCSA Corporations consultations, and Between November 29, 2018 and potential environmental effects of meetings with municipal leaders (i.e., January 30, 2019, BSEE and BOEM met leasing OCS lands for exploration and mayors or their respective with a majority of the tribal entities (23 development and helps ensure BOEM representatives), to discuss the subject of 25) originally invited to consult. The and BSEE have the best science matter of the proposed rule and solicit following table lists all 25 invited tribal available for the public, industry, and input in the development of the entities, and the dates and locations of federal permitting decisions. proposed rule. 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 tribe’s behalf ...... December 13, 2018 ... Anchorage. 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 Slope ...... Non-tribe that consults on 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 bu- reaus did not receive a response from either organization.

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

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

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outreach by presenting this rulemaking human health or environmental effect the following OMB control numbers to to the tribal assemblies and to citizens on native, minority, or low-income the current ICs: within the communities. One of the communities because its provisions are • 1014–0025 (BSEE), 30 CFR part 250, ANCSA corporations also recommended designed to maintain environmental Applications for Permit to Drill (APD that this rulemaking take into account protection and minimize any impact of and revised APD) (expires 06/30/2023), the NPC 2019 Report. Please refer to the exploration drilling on subsistence and in accordance with 5 CFR 1320.10, discussions above in Part E (Partner activities and Alaska Native community an agency may continue to conduct or Engagement in Preparation for This resources and infrastructure. sponsor this collection of information Proposed Rule) of the background while the renewal submission is I. Paperwork Reduction Act (PRA) section of this preamble for a pending at OMB. description of how BSEE and BOEM are This proposed rule contains existing • 1010–0151 (BOEM), 30 CFR part addressing this input during the and new information collection (IC) 550, subpart B Plans and Information rulemaking process. BSEE and BOEM requirements for both BSEE and BOEM (exp. 06/30/2021), and in accordance intend to continue consultation with with 5 CFR 1320.10, an agency may affected tribes and ANCSA Corporations regulations, and a submission to OMB for review under the Paperwork continue to conduct or sponsor this following publication of this proposed collection of information while the rule. Reduction Act of 1995 (44 U.S.C. 3501 et seq.) is required. Therefore, each renewal submission is pending at OMB. H. Effects on Environmental Justice for bureau will submit an IC request to The IC aspects affecting each bureau Minority and Low-Income Populations OMB for review and approval. We may are discussed separately. Additionally, (E.O. 12898) not conduct, or sponsor, and you are not BOEM is seeking to renew these E.O. 12898 requires Federal agencies required to respond to a collection of information collections for three years to make achieving environmental justice information unless it displays a with this rulemaking. Instructions on part of their mission by identifying and currently valid OMB control number. how to comment follow those addressing disproportionately high and OMB has previously reviewed and discussions. adverse human health or environmental approved the existing information The following table details proposed effects of their programs, policies, and collection requirements associated with changes to the annual estimated hour activities on minority and low-income Outer Continental Shelf drilling burdens and non-hour costs; as well as populations. DOI has determined that permits, plans, and related information associated wage cost changes for both this proposed rule would not have a collection, which would be altered by BSEE and BOEM information disproportionately high or adverse this proposed rule. OMB has assigned 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 § 250.470(h) ...... 0 0 2 6 +2 +6 +$848 Submit request to delay access to your SCCE—§ 250.471(a) and § 250.472(b) ...... 0 0 2 2 +2 +2 +$286

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 in- formation § 550.204 ...... 1 2,880 0 0 (1) (2,880) ($316,800) Submit required Arctic-specific infor- mation with EP § 550.220 ...... 1 350 1 400 ...... +50 +5,500

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

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

BURDEN TABLE [Changes due to the proposed rule shown in bold]

Citation 30 CFR 250; Annual application for permit to drill Reporting or recordkeeping requirement * Hour burden Average number burden hours (APD) of responses (rounded)

Non-hour cost burden

Subparts A, C, D, E, G, H, P .... Apply for permit to drill, sidetrack, bypass, or 1 190 applications...... 190 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 × 190 = $401,470

Subparts D, E, G ...... Obtain approval to revise your drilling plan or 1 730 submittals...... 730 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 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

Subpart C

300(b)(1), (2) ...... Obtain approval to add petroleum-based sub- 150 1 request...... 150 stance 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

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BURDEN TABLE—Continued [Changes due to the proposed rule shown in bold]

Citation 30 CFR 250; Annual application for permit to drill Reporting or recordkeeping requirement * Hour burden Average number burden hours (APD) of responses (rounded)

Subpart D

408; 414(h)...... Request approval of alternate procedures or Burden covered under subpart A, 1014– 0 equipment during drilling operations. 0022

409 ...... Request departure approval from the drilling re- 1 370 approvals...... 370 quirements specified in this subpart; identify and discuss.

410(b); 417(b); 713 ...... Reference well and site-specific information in 8 1 submittal...... 8 case it is not approved in your Exploration Plan, Development and Production Plan, De- velopment Operations Coordination Document. Burdens pertaining to EPs, DPPs, DOCDs are covered under BOEM 1010–0151.

410(d) ...... Submit to the District Manager: An original and 0.5 380 submittals ...... 190 two complete copies of APD and Supple- R–0.5 380 submittals ...... 190 mental APD; separate public information copy of forms per § 250.186.

411; 412 ...... Submit plat showing location of the proposed 2 380 submittals...... 760 well and all the plat requirements associated with this section.

411; 413; 414; 415; 420 ...... Submit design criteria used and all description 15 707 submittals...... 10,605 requirements; drilling prognosis with descrip- tion of the procedures you will follow; and cas- ing and cementing program requirements.

411; 416; 731 ...... Submit diverter and BOP systems descriptions 11 380 submittals...... 4,180 and all the regulatory requirements associated with this section.

411; 713 ...... Provide information for using a MODU and all 10 682 submittals...... 6,820 the regulatory requirements associated with this section.

411; 418 ...... Additional information required when providing 20 380 submittals...... 7,600 an APD include, but not limited to, rated ca- pacities of drilling rig and equipment if not al- ready on file; drilling fluids program, including weight materials; directional plot; H2S contin- gency plan; welding plan; and information we may require per requirements, etc.

414(c) ...... Request preapproval to use alternative equiva- 1 15 requests...... 15 lent downhole mud weight prior to submitting APD.

420(a)(7) ...... Include signed registered professional engineer 3 1,034 certifications...... 3,102 certification and related information.

423(c) ...... Submit for approval casing pressure test proce- 3 527 procedures & cri- 1,581 dures and criteria. On casing seal assembly teria. ensure proper installation of casing or liner (subsea BOP’s only).

428(b) ...... Submit to District Manager for approval revised 125 1 submittal...... 125 casing setting depths or hole interval drilling depth; include certification by PE.

428(k) ...... Submit a description of the plan to use a 125 1 submittal...... 125 valve(s) on the drive pipe during cementing operations for the conductor casing, surface casing, or liner.

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BURDEN TABLE—Continued [Changes due to the proposed rule shown in bold]

Citation 30 CFR 250; Annual application for permit to drill Reporting or recordkeeping requirement * Hour burden Average number burden hours (APD) of responses (rounded)

432 ...... Request departure from diverter requirements; 8 53 requests...... 424 with discussion and receive approval.

460(a) ...... Include your projected plans if well testing along 17 2 plans...... 34 with the required information.

462(c) ...... Submit a description of your source control and 125 1 submittal...... 125 containment capabilities to the Regional Su- pervisor and receive approval; all required in- formation.

470(h) ...... Submit certification signed by PE that SSID 3 2 certs...... 6 and well design meet requirements of § 250.472. (Alaska only).

471(a); 472(b) ...... Submit, to Regional Supervisor, a request to 1 2 requests ...... 2 delay access to your SCCE and relief rig, if applicable, including adequate documenta- tion (such as, but not limited to, risk mod- eling data, off-set well data, analog data, seismic data). Demonstrate you will not en- counter any abnormally high-pressured zones or other geologic hazards. (Alaska only).

490(c) ...... Request to classify an area for the presence of 3 91 requests...... 273 H2S.

Support request with available information such 3 73 submittals...... 219 as G&G data, well logs, formation tests, cores and analysis of formation fluids.

Submit a request for reclassification of a zone 1 4 requests...... 4 when a different classification is needed.

Alaska Region: 410; 412 thru Due to the difficulties of drilling in Alaska, along 2,800 1 request...... 2,800 418; 420; 442; 444; 449; 456; with the shortened time window allowed for 470; 471; 472. drilling, Alaska hours are done here as stand- alone requirements. Also, note that these spe- cific hours are based on the first APD in Alas- ka in more than 10 years.

Subpart D subtotal ...... 5,467 responses ...... 39,558

Subpart E

513 ...... Obtain written approval to begin well completion 3 288 requests ...... 864 operations. If completion is planned and the R–3 1 request ...... 3 data are available you may submit on forms.

Submit description of well-completion, sche- 18.5 295 submittals ...... 5,458 matics, logs, any H2S.. R–26 1 submittal ...... 26

Subpart E subtotal ...... 585 responses ...... 6,351

Subpart G

701; 720 ...... Identify and discuss your proposed alternate pro- Burden covered under subpart A, 1014– 0 cedures or equipment. 0022

702 ...... Identify and discuss departure requests...... Burden covered under subpart A, 1014– 0 0022

713(b) ...... Submit plat of the rig’s anchor pattern for a 125 1 submittal...... 125 moored rig approved in your EP, DPP, or DOCD.

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BURDEN TABLE—Continued [Changes due to the proposed rule shown in bold]

Citation 30 CFR 250; Annual application for permit to drill Reporting or recordkeeping requirement * Hour burden Average number burden hours (APD) of responses (rounded)

713(e) ...... Provide contingency plan for using dynamically 10 682 submittals...... 6,820 positioned MODU and all the regulatory re- quirements associated with this section.

713(g) ...... Describe specific current speeds when imple- 45 1 submittal...... 45 menting rig shutdown and/or move-off proce- dures for water depths > 400 meters; discus- sion of specific measures you will take to cur- tail rig operations/move-off location.

720(b) ...... Request approval to displace kill-weight fluid; in- 5 518 approval requests .. 2,590 clude reasons why along with step-by-step procedures.

721(g)(4) ...... Submit test procedures and criteria for a suc- 2.5 R–4 355 submittals, 1 8,884 cessful negative pressure test for approval. If change. any change, submit changes for approval.

731 ...... Submit complete description of BOP system and 114 129 submittals...... 14,706 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 × 129 submittal = $3,999,000

733(b) ...... Describe annulus monitoring plan; and how the 67 1 submittal...... 67 well will be secured if leak is detected.

734(b) ...... Submit verification report from ITP documenting R–64 1 report...... 64 repairs and that BOP is fit for service.

734(c) ...... Submit revision, including all verifications re- R–66 1 submittal...... 66 quired, before drilling out surface casing.

737(a) ...... Request approval from District Manager to omit 1 358 casing/liner info ...... 358 BOP pressure test. Indicate which casing strings and liners meet the criteria for this re- quest.

737(b)(2) ...... Request approval of test pressures (RAM BOPs) 2 353 requests ...... 706

737(b)(3) ...... Request approval of pressure test (annular 2 380 requests...... 760 BOPs).

737(d)(2) ...... Submit test procedures for approval for surface 2.5 507 submittals...... 1,268 BOP.

737(d)(3); (d)(4) ...... Submit test procedures, including how you will 2 507 submittals...... 1,014 test each ROV intervention function, for ap- proval (subsea BOPs only).

737(d)(12) ...... Submit test procedures (autoshear and deadman 2.5 507 submittals...... 1,268 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 permit with a written statement .5 50 submittals...... 25 from an independent third party documenting the repairs, replacement, or reconfiguration and certifying that the previous certification in § 250.731(c) remains valid.

738(m) ...... Request approval to use additional well control 66 1 request...... 66 equipment, including BAVO report; as well as other information required by District Manager.

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BURDEN TABLE—Continued [Changes due to the proposed rule shown in bold]

Citation 30 CFR 250; Annual application for permit to drill Reporting or recordkeeping requirement * Hour burden Average number burden hours (APD) of responses (rounded)

738(n) ...... Submit which pipe/variable bore rams have no 64 1 submittal...... 64 current utility or well control purposes.

Subpart G subtotal ...... 4,177 response ...... 16,396

Subpart H

807(a) ...... Submit detailed information that demonstrates 13 1 submittal...... 13 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 the fitness of the drilling 6 1 submittal...... 6 unit.

1617 ...... Submit fully completed application (Form BSEE– 40 1 submittal...... 40 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 well-completion or 3 1 submittal...... 3 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 other than to provide information or the Interior at OMB–OIRA at (202) 395– to estimate the total annual reporting keep records for the Government; or (4) 5806 (fax) or via the RegInfo.gov portal and recordkeeping non-hour cost as part of customary and usual business (online). You may view the information burden resulting from the collection of or private practices. collection request(s) at http:// information, and we solicit your As part of our continuing effort to www.reginfo.gov/public/do/PRAMain. comments on this item. For reporting reduce paperwork and respondent Please provide a copy of your comments and recordkeeping only, your response burdens, we invite the public and other to the BSEE Information Collection should split the cost estimate into two Federal agencies to comment on any Clearance Officer (see the ADDRESSES components: (1) Total capital and aspect of this information collection, section). You may contact Kye Mason, startup cost component and (2) annual including: BSEE Information Collection Clearance operation, maintenance, and purchase (1) Whether the collection of Officer at (703) 787–1607 with any information is necessary, including of service component. Your estimates questions. Please reference Revisions to whether the information will have the Requirements for Exploratory should consider the cost to generate, practical utility; Drilling on the Arctic Outer Continental maintain, and disclose or provide the (2) The accuracy of our estimate of the Shelf (OMB Control No. 1014–0025), in information. You should describe the burden for this collection of your comments. methods you use to estimate major cost information; factors, including system and (3) Ways to enhance the quality, BOEM Information Collection—30 CFR technology acquisition, expected useful utility, and clarity of the information to Part 550 life of capital equipment, discount be collected; and This proposed rule would add and rate(s), and the period over which you (4) Ways to minimize the burden of remove requirements related to incur costs. Generally, your estimates the collection of information on submitting exploration plans and other should not include equipment or respondents. information before conducting oil and services purchased: (1) Before October Send your comments and suggestions gas exploration drilling activities on the 1, 1995; (2) to comply with on this information collection by the Arctic OCS. If final regulations become requirements not associated with the date indicated in the DATES section to effective, the information collection information collection; (3) for reasons the Desk Officer for the Department of burdens for this rulemaking would be

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consolidated into the existing collection conditions relevant on the Arctic OCS These changes would result in a net for Subpart B, Control Number 1010– in the EP. These requirements were decrease of 2,830 annual burden hours. 0151, and will be adjusted as necessary. previously included in the IOP Because not all EPs submitted to BOEM is requesting OMB approve the requirements that are removed from this BOEM would involve Arctic OCS modified collections of information for rulemaking. Retaining this provision exploration drilling, we are separating OMB Control Number 1010–0151 with would lessen the 2,880-burden hour the burden associated with the Arctic- the final rule publication. decrease by 50 annual burden hours specific requirements and burdens from Pertaining to this proposed (i.e., by retaining 50 annual burden the national EP requirements. The rulemaking, BOEM would collect the hours). burden table that follows this paragraph information to ensure that planned BOEM proposes to revise outlines the revised requirements and operations will be safe; will not § 550.220(c)(1) to require a description burdens associated with this adversely affect the marine, coastal, or of how exploratory drilling will be rulemaking. BOEM has not identified human environments; will respond to designed and conducted, including how any non-hour cost burdens associated the special conditions on the Arctic all vessels and equipment will be with these proposed requirements. OCS; and will conserve the resources of designed, built, and/or modified, to Title of Collection: Revisions to the the Arctic OCS. BOEM would use the account for Arctic OCS conditions and Requirements for Exploratory Drilling information to ensure, through how such activities will be managed on the Arctic Outer Continental Shelf— advanced planning, that operators are and overseen as an integrated endeavor, 30 CFR part 550, subpart B, Plans and capable of safely operating in the unique and in the description of vessel Information. environmental conditions of the Arctic modifications, a description of any OMB Control Number: 1010–0151. and to make informed decisions on approvals from the flag state and the Form Number: whether to approve EPs as submitted or vessel classification society, including • BOEM–0137, OCS Plan Information whether modifications are necessary. any allowances or limitations placed Form BOEM proposes to remove the upon the vessel by the classification • BOEM–0138, EP Air Quality Integrated Operations Plan (IOP) society and/or the USCG. Vessel Screening Checklist regulations by deleting § 550.204 and modifications may include the • BOEM–0139, DOCD/DPP Air removing the corresponding references suitability of vessels for Arctic Quality Screening Checklist. to the IOP from §§ 550.200 and 550.206. conditions. These vessels may have or • BOEM–0141, ROV Survey Report. BOEM’s existing requirement to submit acquire classification from a • BOEM–0142, Environmental Impact the IOP at least 90 days before the lessee ‘‘recognized organization’’ under the Analysis Worksheet. or operator files an EP would be USCG’s Alternative Compliance Type of Review: Revision of a eliminated. The data and information Program (ACP).54 BOEM is seeking to currently approved collection. requested in the IOP is largely confirm that the operator meets the Respondents/Affected Public: unnecessary in light of the information requirements of other entities with Respondents are Federal oil and gas or already collected in the EP. The current authority over vessels, not to impose sulfur lessees or operators. approval for OMB Control Number requirements on those vessels. BOEM Total Estimated Number of Annual 1010–0151 counts the similar burdens believes that this change would not Response: 4,265 respondents. associated with IOPs and EPs in both. impose any material additional burdens Total Estimated Number of Annual Therefore, BOEM would remove the on the lessees or operators. BOEM is Burden Hours: 433,608 hours. burdens attributed to the IOPs, and keep also proposing to revise § 550.220(c)(4) Respondent’s Obligation: Some the burdens attributed to EPs. Removing and (6) by requiring the operator to responses to the information collection the IOP provision would decrease the provide a general description of how are required to obtain or retain a benefit, annual burden hours by 1 response and they will comply with § 250.472, and some are mandatory. 2,880 hours (- 1 response and 2,880 including a description of the Frequency of Collection: The annual burden hours). termination of their operations. frequency of the response varies, but The proposed rule would add a BOEM estimates that the proposed primarily responses are required only requirement to § 550.211(b) to describe revisions would remove 2,880 annual on occasion. operational safety procedures that the burden hours that correlate to the Total Estimated Annual Nonhour operator has developed specific to removal of the existing IOP requirement. Burden Cost: $3,939,435.

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

Citation 30 CFR 550 Average number of subpart B and NTLs Reporting & recordkeeping requirement Hour burden annual responses Burden hours

Non-hour costs

200 thru 206...... General requirements for plans and information; Burden included with specific requirements 0 fees/refunds, etc. below.

201 thru 206; 211 thru BOEM posts EPs/DPPs/DOCDs on FDMS and re- Not considered IC as defined in 5 CFR 0 228: 241 thru 262. ceives public comments in preparation of EAs. 1320.3(h)(4).

Subtotal ...... 0 ...... 0

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

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

Citation 30 CFR 550 Average number of subpart B and NTLs Reporting & recordkeeping requirement Hour burden annual responses Burden hours

Non-hour costs

Ancillary Activities

208; NTL 2009–G34* ...... Notify BOEM in writing, and if required by the Re- 11 61 notices...... 671 gional Supervisor notify other users of the OCS before conducting ancillary activities.

208; 210(a) ...... Submit report summarizing & analyzing data/infor- 2 61 reports...... 122 mation obtained or derived from ancillary activities.

208; 210(b) ...... Retain ancillary activities data/information; upon re- 2 61 records...... 122 quest, submit to BOEM.

Subtotal ...... 183 responses ...... 91

Contents of Exploration Plans (EP)

209; 231(b); 232(d); 234; Submit new, amended, modified, revised, or supple- 150 345 changed plans3 ...... 51,750 235; 281; 283; 284; 285; mental EP, or resubmit disapproved EP, including NTL 2015–N01. required information; withdraw an EP.

209; 211 thru 228; NTL Submit EP and all required information (including, 600 163 ...... 97,800 2015–N01. but not limited to, submissions required by BOEM Forms 0137, 0138, 0142; lease stipulations; re- ports, including shallow hazards surveys, H2S, G&G, archaeological surveys & reports (§ 550.194) ***, in specified formats. Provide notifi- cations.

$3,673 × 163 EP surface locations = $598,699

210; 220(a)–(c); 291; 292 For existing Arctic OCS exploration activities: revise 700 1 ...... 700 and resubmit Arctic-specific information, as re- quired.

202; 211; 216; 219, For new Arctic OCS exploration activities: submit re- 400 1 ...... 400 220(a)–(c); 224, 227;. quired 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); Submit amended, modified, revised, or supple- 235 353 changed plans ...... 82,955 272(a); 273; 281; 283; mental DPP or DOCD, including required informa- 284; 285; NTL 2015– tion, or resubmit disapproved DPP or DOCD. N01.

241 thru 262; 209; NTL Submit DPP/DOCD and required/supporting infor- 700 268 ...... 187,600 2015–N01. mation (including, but not limited to, submissions required by BOEM Forms 0137, 0139, 0142; lease stipulations; reports, including shallow haz- ards surveys, archaeological surveys & reports (§ 550.194)), in specified formats. Provide notifica- tion.

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

Subtotal ...... 621 responses ...... 270,555

$1,135,784 Non-hour costs

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

Citation 30 CFR 550 Average number of subpart B and NTLs Reporting & recordkeeping requirement Hour burden annual responses Burden hours

Non-hour costs

Review and Decision Process for the DPP or DOCD

267(a) ...... Once BOEM deemed DPP/DOCD submitted; Gov- Not considered IC as defined in 5 CFR 0 ernor of each affected State, local government of- 1320.3(h)(4). ficial; etc., submit comments/recommendations.

267(b) ...... General public comments/recommendations sub- Not considered IC as defined in 5 CFR 0 mitted to BOEM regarding DPPs or DOCDs. 1320.3(h)(4).

269(b) ...... For leases or units in vicinity of proposed develop- 3 1 response...... 3 ment 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 departure from your ap- Burden included under 1010–0114. 0 proved EP, DPP, or DOCD.

281(a) ...... Submit various BSEE applications for approval and Burdens included under appropriate sub- 0 submit permits. part or form (1014–0003; 1014–0011; 1014–0016; 1014–0018).

282 ...... Retain monitoring data/information; upon request, 4 150 records...... 600 make available to BOEM.

Prepare and submit monitoring plan for approval ..... 2 6 plans ...... 12

282(b) ...... Prepare and submit monitoring reports and data (in- 3 12 reports...... 36 cluding BOEM Form 0141 used in GOMR).

284(a) ...... Submit updated info on activities conducted under 4 56 updates...... 224 approved EP/DPP/DOCD.

Subtotal ...... 224 responses ...... 872

Submit CIDs

296(a); 297...... Submit CID and required/supporting information; 375 14 documents...... 5,250 submit CID for supplemental DOCD or DPP.

$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

NTL 2016–G02; 211 thru Submit to BOEM observer training requirement ma- 1.5 hours 2 sets of material ...... 3 228; 241 thru 262. terials and information.

Training certification and recordkeeping ...... 1 hour 1 new trainee ...... 1

During seismic acquisition operations, submit daily 1.5 hours 344 reports ...... 516 observer reports semi-monthly.

If used, submit to BOEM information on any passive 2 hours 6 submittals ...... 12 acoustic monitoring system prior to placing it in service.

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

Citation 30 CFR 550 Average number of subpart B and NTLs Reporting & recordkeeping requirement Hour burden annual responses Burden hours

Non-hour costs

During seismic acquisition operations, submit to 1.5 hours 1,976 reports ...... 2,964 BOEM marine mammal observation report(s) semi-monthly or within 24 hours if air gun oper- ations were shut down.

During seismic acquisition operations, when air 1.5 hours 344 reports ...... 516 guns are being discharged, submit daily observer reports semi-monthly.

Observation Duty (3 observers fulfilling an 8-hour 3 observers × 8 hrs × 365 days = 8,760 hours × 4 vessels shift each for 365 calendar days × 4 vessels = observing = 35,040 man-hours × $52/hr = $1,822,080. 35,040 man-hours). This requirement is con- tracted 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 Notify BOEM within 24 hours of strike, when your 1 hour 1 notice ...... 1 228; 241 thru 262. vessel injures/kills a protected species (marine mammal/sea turtle).

Subtotal ...... 1 response ...... 1

General Departure

200 thru 299 ...... General departure and alternative compliance re- 2 25 requests...... 50 quests not specifically covered elsewhere in Sub- part 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 requirements not associated with the Send your comments and suggestions to estimate the total annual reporting information collection; (3) for reasons on this information collection by the and recordkeeping non-hour cost other than to provide information or date indicated in the DATES section to burden resulting from the collection of keep records for the Government; or (4) the Desk Officer for the Department of information, and we solicit your as part of customary and usual business the Interior at OMB–OIRA at (202) 395– comments on this item. For reporting or private practices. 5806 (fax) or via the portal at and recordkeeping only, your response As part of our continuing effort to RegInfo.gov (online). You may view the should split the cost estimate into two reduce paperwork and respondent information collection request(s) at components: (1) Total capital and burdens, we invite the public and other http://www.reginfo.gov/public/do/ startup cost component and (2) annual Federal agencies to comment on any PRAMain. Please provide a copy of your operation, maintenance, and purchase aspect of this information collection, comments to the BOEM Information of service component. Your estimates including: Collection Clearance Officer (see the (1) Whether the collection of ADDRESSES section). You may contact should consider the cost to generate, information is necessary, including Anna Atkinson, BOEM Information maintain, and disclose or provide the whether the information will have Collection Clearance Officer at (703) information. You should describe the practical utility; 787–1025 with any questions. Please methods you use to estimate major cost (2) The accuracy of our estimate of the reference Revisions to the Requirements factors, including system and burden for this collection of for Exploratory Drilling on the Arctic technology acquisition, expected useful information; Outer Continental Shelf (OMB Control life of capital equipment, discount (3) Ways to enhance the quality, No. 1014–0151), in your comments. rate(s), and the period over which you utility, and clarity of the information to incur costs. Generally, your estimates be collected; and J. National Environmental Policy Act of should not include equipment or (4) Ways to minimize the burden of 1969 (NEPA) services purchased: (1) Before October the collection of information on BSEE and BOEM developed a draft 1, 1995; (2) to comply with respondents. Environmental Assessment (EA) to

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determine whether this proposed rule List of Subjects and you satisfy one of the following would have a significant impact on the conditions: 30 CFR Part 250 quality of the human environment (1) You are conducting drilling under the NEPA. The draft EA is Administrative practice and operations from a Mobile Offshore available for review in conjunction with procedure, Continental shelf, Drilling Unit (MODU), but you are not this proposed rule at Environmental impact statements, able to safely continue leaseholding www.regulations.gov (in the Search box, Environmental protection, Government operations due to the presence of enter BSEE–2019–0008). contracts, Incorporation by reference, seasonal ice; Investigations, Oil and gas exploration, (2) You are conducting drilling K. Data Quality Act Penalties, Pipelines, Public lands– operations from an artificial gravel In developing this proposed rule, we mineral resources, Public lands—rights island or a gravity-based structure, but did not conduct or use a study, of-way, Reporting and recordkeeping you are not able to safely continue experiment, or survey requiring peer requirements, Sulphur. leaseholding operations due to review under the Data Quality Act (44 temporary seasonal restrictions in your 30 CFR Part 550 U.S.C. 3516 note). approved oil spill response plan; or Administrative practice and (3) You are conducting drilling L. Effects on the Nation’s Energy Supply procedure, Continental shelf, operations from an artificial ice island, (E.O. 13211) Environmental impact statements, but you are not able to safely continue Although this proposed rule is a Environmental protection, Mineral leaseholding operations due to seasonal significant regulatory action under E.O. resources, Oil and gas exploration, temperature changes. 12866, it is not a significant energy Pipelines, Reporting and recordkeeping ■ 4. Amend § 250.198 by revising action under the definition of that term requirements, Sulfur. paragraph (e)(73) to read as follows: in E.O. 13211 because: Katharine MacGregor, 1. It is not likely to have a significant § 250.198 Documents incorporated by adverse effect on the supply, Deputy Secretary, U.S. Department of the reference. Interior. distribution or use of energy; and * * * * * 2. It has not been designated as a For the reasons stated in the (e) * * * significant energy action by the preamble, BSEE and BOEM amend 30 (73) API RP 17H, Remotely Operated Administrator of OIRA. CFR parts 250 and 550 as follows: Tools and Interfaces on Subsea Production Systems, Second Edition, Thus, a Statement of Energy Effects is Title 30—Mineral Resources not required. June 2013; Errata, January 2014; While offshore Arctic OCS oil and gas CHAPTER II—BUREAU OF SAFETY AND incorporated by reference at studies indicate the potential of vast ENVIRONMENTAL ENFORCEMENT, §§ 250.472(a) and 250.734(a); resources, there is currently little DEPARTMENT OF THE INTERIOR * * * * * exploration activity and very little SUBCHAPTER B—OFFSHORE ■ 5. Amend § 250.300 by revising production of oil and gas on the Arctic paragraphs (b)(1) and (2) to read as OCS, largely due to the inherent PART 250—OIL AND GAS AND follows: practical difficulties of exploration and SULPHUR OPERATIONS IN THE § 250.300 Pollution prevention. production in the area. The only OUTER CONTINENTAL SHELF existing oil production from the Arctic * * * * * ■ OCS is through the Northstar Island 1. The authority citation for 30 CFR (b)(1) The District Manager may facility. part 250 continues to read as follows: restrict the rate of drilling fluid Authority: 30 U.S.C. 1751, 31 U.S.C. 9701, discharges or prescribe alternative M. Clarity of Regulations 33 U.S.C. 1321(j)(1)(C), 43 U.S.C. 1334. discharge methods. The District We are required by E.O. 12866, E.O. ■ 2. Amend § 250.105 by revising the Manager may also restrict the use of 12988, and by the Presidential definition of ‘‘Capping stack’’ to read as components that could cause Memorandum of June 1, 1998, to write follows: unreasonable degradation to the marine all rules in plain language. This means environment. No petroleum-based that each rule we publish must: § 250.105 Definitions. substances, including diesel fuel, may 1. Be logically organized; * * * * * be added to the drilling mud system 2. Use the active voice to address Capping stack means a mechanical without prior approval of the District readers directly; device that can be installed on top of a Manager. For Arctic OCS exploratory 3. Use clear language rather than subsea or surface wellhead or blowout drilling, you must capture all jargon; preventer to stop the uncontrolled flow petroleum-based mud to prevent its 4. Be divided into short sections and of fluids into the environment. discharge into the marine environment. sentences; and * * * * * (2) You must obtain approval from the 5. Use lists and tables wherever ■ 3. Amend § 250.175 by adding District Manager of the method you plan possible. paragraph (d) to read as follows: to use to dispose of drill cuttings, sand, If you believe we have not met these and other well solids. For Arctic OCS requirements, send us comments by one § 250.175 When may the Regional exploratory drilling, you must capture of the methods listed in the ADDRESSES Supervisor grant an SOO? all cuttings from operations that use section. To better help us revise the * * * * * petroleum-based mud to prevent their rule, your comments should be as (d) For leases or units on the Arctic discharge into the marine environment. specific as possible. For example, you OCS, you may request, and the Regional * * * * * should tell us the numbers of the Supervisor may grant, an SOO when ■ 6. Amend § 250.470 by: sections or paragraphs that you find you have conducted leaseholding ■ a. Revising paragraphs (b)(11) and unclear, which sections or sentences are operations during the drilling season (12); too long, or the sections where you immediately preceding the period for ■ b. Adding paragraph (b)(13); believe lists or tables would be useful. which you are seeking a suspension, ■ c. Revising paragraph (f)(3); and

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■ d. Adding paragraph (h). which it is intended under expected the calculated worst case discharge rate The revisions and additions read as wellbore conditions. referenced in your BOEM-approved EP; follows: ■ 7. Amend § 250.471 by revising and paragraph (a) introductory text, and (3) A containment dome that can be § 250.470 What additional information paragraphs (a)(2) and (3) and (b) to read must I submit with my APD for Arctic OCS deployed as directed by the Regional exploratory drilling operations? as follows: Supervisor pursuant to paragraph (h) of * * * * * § 250.471 What are the requirements for this section. The containment dome (b) * * * Arctic OCS source control and must have the capacity to pump fluids (11) Pick up the oil spill prevention containment? without relying on buoyancy. booms and equipment; * * * * * (b) You must conduct a monthly (12) Offload the drilling crew; and (a) If you use a MODU, you must have stump test of dry-stored capping stacks. (13) Recover the subsea isolation access to the SCCE as described in * * * * * device (SSID), where applicable. paragraphs (a)(1) through (3) of this * * * * * section capable of controlling and ■ 8. Revise § 250.472 to read as follows: (f) * * * containing the flow from an out-of- § 250.472 What are the additional well (3) Where applicable, proof of control well when drilling below or control equipment or relief rig requirements contracts or membership agreements working below the surface casing. for the Arctic OCS? with cooperatives, service providers, or However, the Regional Supervisor will other contractors who will provide you approve delaying access to your SCCE If you will be conducting exploratory with the necessary SCCE or related until your operations have reached the drilling operations from a Mobile supplies and services if you do not last casing point prior to penetrating a Offshore Drilling Unit (MODU), you possess them. The contract or zone capable of flowing hydrocarbons in must either use a Subsea Isolation membership agreement must include measurable quantities, provided that Device (SSID) or have access to a relief provisions for ensuring the availability you submit adequate documentation rig as an additional means to secure the of the personnel and/or equipment on a (such as, but not limited to, risk well in the event of a loss of well 24-hour per day basis while you are modeling data, off-set well data, analog control. If you satisfy this requirement drilling below or working below the data, seismic data), with your APD, through use of an SSID, you must meet surface casing, or before the last casing demonstrating that you will not the requirements in paragraph (a) in this point prior to penetrating a zone capable encounter any abnormally high- section. If you satisfy this requirement of flowing hydrocarbons in measurable pressured zones or other geologic through maintaining access to a relief quantities, as approved by the Regional hazards. The Regional Supervisor will rig, you must meet the requirements in Supervisor. base the determination on any paragraph (b) in this section. * * * * * documentation you provide as well as (a) Subsea Isolation Device (SSID). If (h) If you plan to install a subsea any other available data and you use an SSID to satisfy this isolation device (SSID) on your well in information. requirement, your SSID and well accordance with § 250.472(a), a * * * * * (including the casing and cementing certification signed by a registered (2) A cap and flow system that can be program) must be designed to achieve a professional engineer that your SSID deployed as directed by the Regional full shut-in, without causing an and well design (including casing and Supervisor pursuant to paragraph (h) of underground blowout or having cementing program) meet the design this section. The cap and flow system reservoir fluids broach to the seafloor. requirements in § 250.472 and the must be designed to capture at least the Your SSID must also meet the following design is appropriate for the purpose for amount of hydrocarbons equivalent to 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 sea- son; and (v) In the event of a loss of well control, preserve isolation until other methods of well interven- tion may be completed, including the need to drill a relief well. (2) Include the following equipment: (i) Dual shear rams, including ram locks; one ram must be a blind shear ram; (ii) A redundant control system, independent from the BOP control system, that includes ROV 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 equipment and ca- (i) Be able to close each shear ram under MASP conditions, as defined for the operation; pabilities. Your ROV equipment and capabili- ties must: (ii) Include an ROV panel that is compliant with API RP 17H (as incorporated by reference in § 250.198); (iii) Meet the ROV requirements in § 250.734(a)(5); and (iv) Have the ability to function the SSID in any environment (e.g., when in a mudline cellar).

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TABLE 1 TO PARAGRAPH (a)—Continued

Your SSID must

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

(b) Relief Rig. If you choose to satisfy equipment in accordance with (b) A description of how you will this requirement by having access to a §§ 250.141 and 250.408. ensure operational safety while working relief rig, you must have access to your * * * * * in Arctic OCS conditions, including but relief rig at all times when you are not limited to: drilling below or working below the CHAPTER V—BUREAU OF OCEAN ENERGY MANAGEMENT, DEPARTMENT OF (1) The safety principles that you surface casing during Arctic OCS THE INTERIOR intend to apply to yourself and your exploratory drilling operations. contractors; However, the Regional Supervisor will SUBCHAPTER B—OFFSHORE approve delaying access to your relief (2) The accountability structure rig until your operations have reached PART 550—OIL AND GAS AND within your organization for the last casing point prior to penetrating SULPHUR OPERATIONS IN THE implementing such principles; OUTER CONTINENTAL SHELF a zone capable of flowing hydrocarbons (3) How you will communicate such in measurable quantities, provided that ■ 10. The authority citation for 30 CFR principles to your employees and you submit adequate documentation part 550 continues to read as follows: contractors; and (such as, but not limited to, risk Authority: 30 U.S.C. 1751; 31 U.S.C. 9701; (4) How you will determine modeling data, off-set well data, analog 43 U.S.C. 1334. successful implementation of such data, seismic data), with your APD, principles. demonstrating that you will not § 550.220 [Amended] encounter any abnormally high- ■ 11. Amend § 550.200 by removing the * * * * * pressured zones or other geologic words ‘‘IOP means Integrated ■ 15. Amend § 550.220 by revising the hazards. The Regional Supervisor will Operations Plan.’’ in paragraph (a). section heading, paragraphs (c)(1) and base the determination on any ■ 12. Remove and reserve § 550.204. (4), and (c)(6)(ii) to read as follows: documentation you provide as well as any other available data and § 550.204 [Reserved] § 550.220 If I propose activities in the information. Your relief rig must be ■ 13. Amend § 550.206 by revising the Arctic OCS Region, what planning different from your primary drilling rig, section heading, paragraph (a) information must accompany the EP? staged in a location, such that it would introductory text, and paragraphs (a)(3), * * * * * be available to arrive on site, drill a (b), and (c) to read as follows: (c) * * * relief well, kill and abandon the original § 550.206 How do I submit the EP, DPP, or (1) A description of how your well, and abandon the relief well no DOCD? later than 45 days after the loss of well exploratory drilling will be designed control. (a) Number of copies. When you and conducted, (including how all submit an EP, DPP, or DOCD to BOEM, vessels and equipment will be designed, (1) Your relief rig must comply with you must provide: built, and/or modified) to account for all other requirements of this part Arctic OCS conditions and how such pertaining to drill rig characteristics and * * * * * activities will be managed and overseen capabilities, and it must be able to drill (3) Any additional copies that may be as an integrated endeavor. In your a relief well under anticipated Arctic necessary to facilitate review of the EP, OCS conditions. DPP, or DOCD by certain affected States description of vessel modifications, and other reviewing entities. describe any approvals from the flag (2) In the event of a loss of well (b) Electronic submission. You may state and the vessel classification control, the Regional Supervisor may submit part or all of your EP, DPP, or society, including any allowances or direct you to drill a relief well using a DOCD and its accompanying limitations placed upon the vessel by relief rig that is able to kill and information electronically. If you prefer the classification society and/or the permanently plug an out-of-control well to submit your EP, DPP, or DOCD United States Coast Guard. as described in your APD. electronically, ask the Regional * * * * * ■ 9. Amend § 250.720 by revising Supervisor for further guidance. paragraph (c)(2) to read as follows: (c) Withdrawal after submission. You (4) Additional well control equipment may withdraw your proposed EP, DPP, requirements for the Arctic OCS. A § 250.720 When and how must I secure a general description of how you will well? or DOCD at any time for any reason. Notify the appropriate BOEM Regional comply with § 250.472 of this title. * * * * * Office if you do. (6) * * * (c) * * * ■ 14. Amend § 550.211 by redesignating (ii) The termination of drilling (2) In areas of ice scour, you must use paragraphs (b) through (d) as paragraphs a well mudline cellar or an equivalent operations consistent with the well (c) through (e), respectively, and adding control planning requirements under means of minimizing the risk of damage new paragraph (b) to read as follows: to the well head and wellbore. You may § 250.472 of this title. request, and the Regional Supervisor § 550.211 What must the EP include? [FR Doc. 2020–25818 Filed 12–8–20; 8:45 am] may approve, an alternate procedure or * * * * * BILLING CODE 4310–VH–P; 4310–MR–P

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