Oil and Gas and Sulfur Operations on the Outer Continental Shelf-Requirements for Exploratory Drilling on the Arctic Outer Continental Shelf
Federal RegisterJul 15, 2016
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DEPARTMENT OF THE INTERIOR
Bureau of Safety and Environmental Enforcement
30 CFR Parts 250, 254, and 550
Bureau of Ocean Energy Management
30 CFR Part 550
[Docket ID: BSEE-2013-0011; 16XE1700DX EX1SF0000.DAQ000 EEEE500000]
RIN 1082-AA00
Oil and Gas and Sulfur Operations on the Outer Continental Shelf—Requirements for Exploratory Drilling on the Arctic Outer Continental Shelf
AGENCY:
Bureau of Safety and Environmental Enforcement (BSEE); Bureau of Ocean Energy Management (BOEM), Interior.
ACTION:
Final rule.
SUMMARY:
The Department of the Interior (DOI or the Department), acting through BOEM and BSEE, is revising and adding new requirements to regulations for exploratory drilling and related operations on the Outer Continental Shelf (OCS) seaward of the State of Alaska. This final rule focuses solely on the OCS within the Beaufort Sea and Chukchi Sea Planning Areas (Arctic OCS). The Arctic region is characterized by extreme environmental conditions, geographic remoteness, and a relative lack of fixed infrastructure and existing operations. This final rule is designed to help ensure the safe, effective, and responsible exploration of Arctic OCS oil and gas resources, while protecting the marine, coastal, and human environments, and Alaska Natives' cultural traditions and access to subsistence resources.
DATES:
This rule becomes effective on September 13, 2016.
The incorporation by reference of certain publications listed in the rule is approved by the Director of the Federal Register as of September 13, 2016.
ADDRESSES:
Comments and material received from the public, as well as documents mentioned in this preamble as being available in the docket, are part of docket BSEE-2013-0011 and are available for inspection or copying at the Docket Management Facility (M-30), U.S. Department of Transportation, West Building Ground Floor, Room W12-140, 1200 New Jersey Avenue SE., Washington, DC 20590, between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays. You may also find this docket on the Internet by going to
http://www.regulations.gov,
and searching for BSEE-2013-0011.
Materials incorporated by reference in this final rule may be inspected by appointment at BOEM and BSEE Headquarters, 45600 Woodland Road, Sterling, Virginia 20166, or at the BOEM and BSEE Alaska Regional Offices, 3801 Centerpoint Drive, Suite 400 or Suite 500, Anchorage, Alaska 99503, between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays. To make an appointment, call (202) 258-1518.
FOR FURTHER INFORMATION CONTACT:
Mark E. Fesmire, BSEE, Alaska Regional Office,
mark.fesmire@bsee.gov,
(907) 334-5300; John Caplis, BSEE, Oil Spill Preparedness Division,
john.caplis@bsee.gov,
(703) 787-1364; or David Johnston, BOEM, Alaska Regional Office,
david.johnston@boem.gov,
(907) 334-5200. To see a copy of any relevant information collection request submitted to Office of Management and Budget (OMB), go to
http://www.reginfo.gov
(select Information Collection Review).
SUPPLEMENTARY INFORMATION:
Executive Summary
Although there is currently a comprehensive OCS oil and gas regulatory program, there is a need for new and revised Arctic-specific regulatory measures for exploratory drilling conducted by floating drilling vessels and “jack-up rigs” (collectively known as mobile offshore drilling units or (MODU)) in the Beaufort Sea and Chukchi Sea Planning Areas (defined in this final rule as the Arctic OCS). The United States (U.S.) Arctic region, as recognized and defined in the U.S. Arctic Research and Policy Act of 1984, as amended, encompasses an extensive marine and terrestrial area; however, this final rule focuses solely on the OCS within the Beaufort Sea and Chukchi Sea Planning Areas.
On February 24, 2015, BOEM and BSEE published a Notice of Proposed Rulemaking (NPRM) in the
Federal Register
entitled, “Oil and Gas and Sulfur Operations in the Outer Continental Shelf—Requirements for Exploratory Drilling on the Arctic Outer Continental Shelf” (80 FR 9916). We received 1,311 letters to the docket, from over 100,000 individual commenters on the NPRM. Additionally, BOEM and BSEE engaged in Government-to-Government Tribal consultations and Government-to- Alaska Native Claims Settlement Act (ANCSA) Corporations consultations prior to and after publication of the NPRM, to discuss the subject matter of the proposed rule and to solicit input on the development of the final rule. In the development of the NPRM and this final rule, BOEM and BSEE undertook extensive environmental and safety reviews of potential oil and gas operations on the Arctic OCS. After considering comments on the NPRM, Tribal and other consultations, the environmental analysis, and DOI's direct experience from Shell's 2012 and 2015 Arctic operations, BOEM and BSEE concluded that finalizing additional exploratory drilling regulations will enhance existing regulations and is appropriate for establishing a more holistic Arctic OCS oil and gas regulatory framework.
The U.S Arctic region is known for its oil and gas resource potential, its vibrant ecosystems, and the Alaska Native communities, which rely on the Arctic's resources for subsistence use and cultural traditions. The region is characterized by extreme environmental conditions, geographic remoteness, and a relative lack of fixed infrastructure and existing operations. These are key factors in considering the feasibility, practicality, and safety of conducting offshore oil and gas activities on the Arctic OCS. This final rule will help to ensure that Arctic OCS exploratory drilling operations are conducted in a safe and responsible manner while taking into account the unique conditions of Arctic OCS drilling activities and Alaska Natives' cultural traditions and access to subsistence resources.
This final rule adds to and revises existing regulations in 30 CFR parts 250, 254, and 550 for Arctic OCS oil and gas activities and focuses on exploratory drilling activities that use MODUs and related operations during the Arctic OCS open-water drilling season. The final rule does not preclude exploratory drilling on the Arctic OCS conducted in the future using other drilling technologies (
e.g.,
use of a land rig on grounded or land-fast ice). Exploratory drilling operations using technologies other than MODUs are outside the scope of the final rule and would be evaluated under the existing OCS oil and gas regulatory program, as may be amended. The final regulations address a number of important issues and objectives, including ensuring that each operator:
1. Designs and conducts exploration programs in a manner that accounts for Arctic OCS conditions;
2. Develops an integrated operations plan (IOP) that addresses all phases of its proposed Arctic OCS exploration program, and submits the IOP to BOEM at least 90 days in advance of filing its Exploration Plan (EP);
3. Has access to, and the ability to promptly deploy, Source Control and Containment Equipment (SCCE) while drilling below, or working below, the surface casing;
4. Has access to a separate relief rig located in a geographic position to be able to timely drill a relief well under the conditions expected at the site in the event of a loss of well control;
5. Has the capability to predict, track, report, and respond to ice conditions and adverse weather events;
6. Effectively manages and oversees contractors; and,
7. Develops and implements an Oil Spill Response Plan (OSRP) that is designed and executed in a manner that accounts for the unique Arctic OCS operating environment, and has the necessary equipment, training, and personnel for oil spill response on the Arctic OCS.
The final rule furthers the Nation's stewardship of the Arctic's environment and resources, and establishes specific operating models and requirements for the extreme, changing conditions that exist on the Arctic OCS. The regulations will require comprehensive planning of operations, especially for emergency response and safety systems. A goal of the final rule is to encourage the identification of operational risks early in the planning process and to encourage operators to plan for how to avoid and/or mitigate those risks. The requirements in the final rule also aim to ensure that plans meet the challenges presented by Arctic conditions and are executed in a safe and environmentally protective manner.
Table of Contents
I. Introduction
A. Resource Potential
B. Integrated Arctic Management
C. Overview of Regulations
D. Costs and Benefits of Final Rule
E. Availability of Incorporated Documents for Public Viewing
F. Summary of Documents Incorporated by Reference
II. Background
A. Statutory and Regulatory Overview
B. Factual Overview of the Arctic OCS Region
III. Regulations for Arctic OCS Exploratory Drilling
A. Measures That Address Recommendations
B. Approval of Alternative Procedures or Equipment
C. IOP Requirement
D. SCCE and Relief Rig Capabilities
E. Planning for the Variability and Challenges of the Arctic OCS Conditions
F. Arctic OCS Oil Spill Response Preparedness
G. Reducing Pollution From Arctic OCS Exploratory Drilling Operations
H. Oversight, Management, and Accountability of Operations and Contractor Support
IV. Section-By-Section Discussion of Changes and Comments
A. Summary of Key Changes From the NPRM
B. Discussion of and Responses to Comments
1. General Comments
2. Definitions
3. Additional Regulations by BOEM
4. Additional Regulations by BSEE
C. Discussion of Comments on the Initial RIA
D. Arctic Exploratory Drilling Process Flowchart
E. Conclusion
V. Procedural Matters
A. Regulatory Planning and Review (E.O. 12866 and E.O. 13563)
B. E.O. 12866
C. E.O. 13563
D. Regulatory Flexibility Act
E. Unfunded Mandates Reform Act of 1995 (UMRA)
F. Takings Implication Assessment
G. Federalism (E.O. 13132)
H. Civil Justice Reform (E.O. 12988)
I. Consultation With Indian Tribes (E.O. 13175)
J. E.O. 12898—Environmental Justice
K. Paperwork Reduction Act (PRA)
L. National Environmental Policy Act of 1969 (NEPA)
M. Data Quality Act
N. Effects on the Nation's Energy Supply (E.O. 13211)
O. Clarity of This Regulation
List of Acronyms and References
List of Acronyms and References
60-Day Report
Report to the Secretary of the Interior, Review of Shell's 2012 Alaska Offshore Oil and Gas Exploration Program.
ACPs
Area Contingency Plans.
AEWC
Alaska Eskimo Whaling Commission.
ANCSA
Alaska Native Claims Settlement Act.
APD
Application for Permit to Drill.
API
American Petroleum Institute.
APM
Application for Permit to Modify.
Arctic OCS
OCS within the Beaufort Sea and Chukchi Sea Planning Areas.
BAST
Best Available and Safest Technology.
BOEM
Bureau of.
BOP
Blowout Preventer.
BSEE
Bureau of Safety and Environmental Enforcement.
CAA
Conflict Avoidance Agreement.
CAP
Corrective Action Plan.
CFR
Code of Federal Regulations.
COCP
Critical Operations and Curtailment Plan.
CWA
Clean Water Act.
Department
Department of the Interior.
DOCD
Development Operations Coordination Document.
DOI
Department of the Interior.
DPP
Development and Production Plan.
EA
Environmental Assessment.
E.O.
Executive Order.
E.O. 13580 Alaska Energy Permitting IWG
Interagency Working Group on Coordination of Domestic Energy Development and Permitting in Alaska.
EP
Exploration Plan.
EPA
Environmental Protection Agency.
ESA
Endangered Species Act.
FOSC
Federal On Scene Coordinator.
HPHT
High Pressure High Temperature.
IACS
International Association of Classification Societies.
IBR
Incorporation by Reference.
IC
Information Collection.
ICAS
Inupiat Community of the Arctic Slope.
ICS
Incident Command System.
IEC
International Electrotechnical Commission.
IMH
Incident Management Handbook.
IMO
International Maritime Organization.
IMP
Ice Management Plan.
INC
Incident of Noncompliance.
IOGP
International Association of Oil and Gas Producers.
IOP
Integrated Operations Plan.
IPD
Interim Policy Document.
IPIECA
International Petroleum Industry Environmental Conservation Association.
IQA
Information Quality Act.
IRFA
Initial Regulatory Flexibility Analysis.
ISO
International Organization of Standardization.
MMPA
Marine Mammal Protection Act.
MMS
Minerals Management Service.
MOA
Memorandum of Agreement.
MODU
Mobile Offshore Drilling Unit.
MPD
Managed Pressure Drilling.
MWD
Measurement while Drilling.
NAICS
North American Industry Classification System.
NARA
National Archives and Records Administration.
NCP
National Oil and Hazardous Substances Pollution Contingency Plan.
NEPA
National Environmental Policy Act of 1969.
NMFS
National Marine Fisheries Service.
NOAA
National Oceanic and Atmospheric Administration.
NPC
National Petroleum Council.
NPDES
National Pollutant Discharge Elimination System.
NPRM
Notice of Proposed Rulemaking.
NSAR
President's National Strategy of the Arctic Region, issued May 2013.
NTL
Notice to Lessees and Operators.
NWS
National Weather Service.
OCS
Outer Continental Shelf.
OCSLA
Outer Continental Shelf Lands Act.
ODCE
Ocean Discharge Criteria Evaluations.
OEM
Original Equipment Manufacturer.
OIRA
Office of Information and Regulatory Affairs.
OMB
Office of Management and Budget.
OPA
Oil Pollution Act of 1990.
OSRO
Oil Spill Response Organization.
OSRP
Oil Spill Response Plan.
PHMSA
Pipeline and Hazardous Materials Safety Administration.
PRA
Paperwork Reduction Act.
PREP
Preparedness for Response Exercise Program.
RCPs
Regional Contingency Plans.
RFAI
Requests for Additional Information.
RIA
Regulatory Impact Analysis.
RMROL
Realistic Maximum Response Operating Limits.
RP
Recommended Practice.
RTM
Real-Time Monitoring.
SCCE
Source Control and Containment Equipment.
SCSC
Source Control Support Coordinator.
Secretary
Secretary of the Interior.
SEMS
Safety and Environmental Management Systems.
SID
Subsea Isolation Device.
SINTEF
Scientific and Industrial Research at the Norwegian Institute of Technology.
SOSC
State on Scene Coordinator.
TAP
Technical Assessment Program.
UMRA
Unfunded Mandates Reform Act of 1995.
U.S.
United States.
USCG
U.S. Coast Guard.
USFWS
U.S. Fish and Wildlife Service.
WCD
Worst Case Discharge.
I. Introduction
In May 2013, President Obama issued a document entitled, “National Strategy for the Arctic Region” (NSAR). The President affirmed that emerging economic opportunities exist in the region, but that “. . . we must exercise responsible stewardship, using an integrated management approach and making decisions based on the best available information, with the aim of promoting healthy, sustainable, and resilient ecosystems over the long term.” The NSAR is intended, among other things, to “reduce our reliance on imported oil and strengthen our Nation's energy security” by working with stakeholders to enable “environmentally responsible production of oil and natural gas.” To provide responsible stewardship of the
Arctic's environment and resources, the NSAR emphasizes the need for integrated and balanced management techniques.
Furthermore, the NSAR acknowledges the potential international implications of Arctic oil and gas activities for “other Arctic states and the international community as a whole.” The U.S. has committed to do its part to “keep the Arctic region prosperous, environmentally sustainable, operationally safe, secure, and free of conflict[.]” One primary objective outlined in the implementation plan for the NSAR is to “reduce the risk of marine oil pollution while increasing global capabilities for preparedness and response to oil pollution incidents in the Arctic.” (available at:
http://www.whitehouse.gov/sites/default/files/docs/implementation_plan_for_the_national_strategy_for_the_arctic_region_-_fi....pdf
). The NSAR is an example of the types of action the U.S. is taking to implement its obligations under international agreements, such as the Arctic Council's Agreement on Cooperation on Marine Oil Pollution Preparedness and Response in the Arctic (available at
http://arctic-council.org/eppr/agreement-on-cooperation-on-marine-oil-pollution-preparedness-and-response-in-the-arctic/
).
A. Resource Potential
The Arctic OCS region is estimated to contain a vast amount of undiscovered, technically recoverable oil and gas. Most of the Alaska OCS resource potential is located off the Arctic coast within the Chukchi Sea and Beaufort Sea Planning Areas. According to BOEM's 2016 Assessment of Undiscovered Technically Recoverable Oil and Gas Resources of the Nation's Outer Continental Shelf (mean estimates available at
http://www.boem.gov/National-Assessment-2016/,
there are approximately 23.6 billion barrels of technically recoverable oil and about 104.4 trillion cubic feet of technically recoverable natural gas in the combined Beaufort Sea and Chukchi Sea Planning Areas. This resource potential has intermittently received considerable attention from the oil and gas industry over several decades. The U.S. government has responded to this interest by holding lease sales offering millions of acres resulting in hundreds of leases, and the oil and gas industry has conducted Arctic exploration activities beginning in the 1970s.
B. Integrated Arctic Management
As ocean and seasonal conditions continue to change in the U.S. Arctic, both commercial and recreational activities will increase as more areas of water open up for longer periods of time due to the increased melting of sea ice. The decrease in summer sea ice raises legitimate concerns regarding changes to the environment and the Arctic resources that Alaska Natives depend on for survival and cultural traditions. Consistent with the Outer Continental Shelf Lands Act (OCSLA), BOEM and BSEE, the Bureaus responsible for managing oil and gas resources on the Arctic OCS, are finalizing these regulations that take into account the needs of the multiple users who have an interest in the future of the U.S. Arctic region (
see
43 U.S.C. 1332(6)).
The U.S. has a longstanding interest in the orderly development of oil and gas resources on the Arctic OCS, while also seeking to ensure the protection of its environment and communities. The U.S. has proceeded with Arctic OCS oil and gas development to ensure that laws, regulations, and policies are created and implemented based on a thorough examination of the multiple factors at play in this unique environment. BOEM and BSEE have conducted extensive research on potential oil and gas activities on the OCS in anticipation of operations (
see, e.g., www.bsee.gov/Technology-and-Research/Technology-Assessment-Programs/Categories/Arctic-Research/
), and have also evaluated the potential environmental effects of such activities (
see, e.g., http://www.boem.gov/akstudies/
). These research projects, along with other initiatives, form the basis for the most recent National policies and directives regarding Alaska OCS oil and gas development, all of which have guided this final rule.
Coordinating the future uses of the U.S. Arctic region will require integrated action between and among Federal, State, municipal and tribal governmental entities. On July 12, 2011, President Obama signed Executive Order (E.O.) 13580, establishing an Interagency Working Group on Coordination of Domestic Energy Development and Permitting in Alaska (E.O. 13580 Alaska Energy Permitting IWG), chaired by the Deputy Secretary of the Interior. The E.O. 13580 Alaska Energy Permitting IWG is composed of representatives from the DOI, Department of Defense, Department of Commerce, Department of Agriculture, Department of Energy, Department of Homeland Security, and the Environmental Protection Agency (EPA).
1
It is charged with facilitating “coordinated and efficient domestic energy development and permitting in Alaska while ensuring that all applicable [health, safety, and environmental protection] standards are fully met” (E.O. 13580, sec. 1).
1
The Office of the Federal Coordinator for Alaska Natural Gas Transportation Projects was represented on the E.O. 13580 Alaska Energy Permitting IWG, but closed on March 7, 2015, due to lack of funding. Its Web site,
Arcticgas.gov
, is being maintained, but not updated, by the U.S. Arctic Research Commission, with assistance from Alaska Resources Library & Information Services (ARLIS) at the University of Alaska Anchorage.
See http://www.arcticgas.gov/.
The E.O. 13580 Alaska Energy Permitting IWG's report entitled, “Managing for the Future in a Rapidly Changing Arctic, A Report to the President” (March 2013) (
see http://www.afsc.noaa.gov/publications/misc_pdf/iamreport.pdf
), was the result of substantial collaboration and also plays a significant role in shaping U.S. Arctic policies. Further, the President signed E.O. 13689,
Enhancing Coordination of National Efforts in the Arctic
on January 21, 2015. This E.O. states the policy: “The Arctic has critical long-term strategic, ecological, cultural, and economic value, and it is imperative that we continue to protect our national interests in the region, which include: national defense; sovereign rights and responsibilities; maritime safety; energy and economic benefits; environmental stewardship; promotion of science and research; and preservation of the rights, freedoms, and uses of the sea as reflected in international law.” An Arctic Executive Steering Committee was established to provide guidance to Federal departments and agencies and to enhance coordination of Federal Arctic policies.
C. Overview of Regulations
Although there is currently a comprehensive OCS oil and gas regulatory program, DOI engagement with partners and stakeholders
2
and comments on the NPRM underscore the need for new and enhanced regulatory measures for Arctic OCS exploratory drilling by MODUs. For purposes of this rulemaking, exploratory drilling is defined as “[a]ny drilling conducted for the purpose of searching for commercial quantities of oil, gas, and sulfur, including the drilling of any additional well needed to delineate any reservoir to enable the lessee to decide whether to proceed with development and production.”
2
Tribes, State and local governments, and Federal agencies are “partners.” “Stakeholders” are non-governmental organizations, industry, and other entities with an interest in this rulemaking.
This final rule defines the “Arctic OCS” as the Beaufort Sea and Chukchi Sea Planning Areas, as described in the
Proposed Final OCS Oil and Gas Leasing Program for 2012—(June 2012) (available at:
www.boem.gov/uploadedFiles/BOEM/Oil_and_Gas_Energy_Program/Leasing/Five_Year_Program/2012-2017_Five_Year_Program/PFP%2012-17.pdf
(see pp.21-24)).
3
This definition is added to §§ 250.105, 254.6, and 550.105. As described below, BOEM and BSEE determined that these areas are both the subject of exploration and development interest and subject to conditions that present significant challenges to such operations.
3
This final rule uses and defines terms that may be similar to terms used in other programs by other Federal agencies; however, the terms and definitions used in this final rule are intended to apply only to the BSEE and BOEM regulatory programs covered by this final rule, unless otherwise noted.
This final rule applies to Arctic OCS exploratory drilling activities that use MODUs (
e.g.,
jack-ups and drillships) and related operations during the Arctic open-water drilling season (generally late June to early November). We note that, because this rulemaking is applicable only to MODUs conducting exploration drilling, the provisions finalized here do not apply to shallow water drilling from gravel islands or the use of a land rig on grounded or land-fast ice and do not prohibit these or other methods of exploratory drilling operations on the Arctic OCS.
This final rule builds on and codifies input received from partners and stakeholders, comments to the proposed rule, as well as key components of the 2012 and 2015 Arctic exploratory drilling programs. DOI released in 2013 a “Report to the Secretary of the Interior, Review of Shell's 2012 Alaska Offshore Oil and Gas Exploration Program” (60-Day Report) (available at
http://www.doi.gov/news/pressreleases/upload/Shell-report-3-8-13-Final.pdf
). The 60-Day Report identified a number of lessons learned and recommended practices to ensure future Arctic oil and gas exploration activities would be carried out in a safe and responsible manner.
Shell's exploratory operations proceeded in 2015 without any unexpected drilling-related problems, and it safely drilled its well to a total depth of 6800 feet. On
September 28, 2015, Shell announced that it had found indications of oil and gas in the well, but stated that the results were not sufficient to warrant further exploration of the prospect, and the well was to be plugged and abandoned in accordance with BSEE regulations. Shell subsequently announced it was ceasing further exploration activity in offshore Alaska for the foreseeable future.
4
4
Shell update of Alaska exploration, Press release (September 28, 2015) (available at
http://www.shell.com/global/aboutshell/media/news-and-media-releases/2015/shell-updates-on-alaska-exploration.html
).
BOEM and BSEE have undertaken extensive environmental and safety reviews of potential oil and gas operations on the Arctic OCS. These reviews, along with concerns expressed by environmental organizations and Alaska Natives, as well as other stakeholders, highlight the need to develop additional measures specifically tailored to the operational and environmental conditions of the Arctic OCS. Arctic OCS operations can be complex, and there are challenges and operational risks throughout every phase of an exploratory drilling program.
This final rule is a combination of prescriptive and performance-based requirements that address a number of important issues and objectives, including, but not limited to, ensuring that operators:
1. Design and conduct exploration programs in a manner that accounts for Arctic OCS conditions (
e.g.,
using equipment and processes that are capable of performing effectively and safely under extreme weather and sea conditions and in remote locations with relatively limited infrastructure);
2. Develop an IOP that addresses all phases of an Arctic OCS exploration program and submit the IOP to BOEM at least 90 days in advance of filing an EP;
3. Have access to, and the ability to promptly deploy, SCCE while drilling below, or working below, the surface casing;
4. Have access to a separate relief rig located in a geographic position to be able to timely drill a relief well under the conditions expected at the site;
5. Have the capability to predict, track, report, and respond to ice conditions and adverse weather events;
6. Effectively manage and oversee contractors; and
7. Develop and implement OSRPs that are designed in a manner that accounts for the unique Arctic OCS operating environment and that describe the availability of the necessary equipment, training, and personnel for oil spill response on the Arctic OCS.
D. Costs and Benefits of Final Rule
The Final Regulatory Impact Analysis (RIA) for this final rule estimates that the new requirements could result in compliance costs for the industry of $2.05 billion under 3-percent discounting and $1.74 billion under 7-percent discounting over 10 years. The provisions of the rule subsumed within the regulatory baseline are estimated to cost $1.83 billion under 3-percent discounting and $1.51 billion under 7-percent discounting over the 10-year analysis period. As discussed in Section V.B of the preamble, the baseline includes the estimated costs associated with current regulatory requirements and industry standards. While the economic and other benefits of the final rule—based primarily on preventing or reducing the severity or duration of catastrophic oil spills—are difficult to quantify, BOEM and BSEE have determined that it is appropriate to proceed with this final rule. Although the probability of a catastrophic oil spill is low, the
Deepwater Horizon
oil spill demonstrated that even such low probability events can have devastating human, economic and environmental results if they occur.
Reducing the risks of Arctic OCS operations is particularly important because of the unique significance to Alaska Natives of the marine mammals, fish, and migratory birds, in the lands and waters around the Arctic OCS. Ensuring a continuing opportunity to harvest these subsistence resources is critical for protecting Alaska Natives' health, livelihood, and culture. Additionally, adequately protecting the health of the Arctic ecosystem, including the sensitive environment and wildlife, is particularly important and highly valued. Thus, the impact of a catastrophic oil spill, while a remote possibility, would have extremely high cultural and societal costs, and prevention of such a catastrophe would have correspondingly high cultural and societal benefits.
The requirements of the rule—specifically tailored to the Arctic OCS—provide additional specificity regarding BOEM's and BSEE's expectations for safe and responsible development of U.S. Arctic resources and outline the particular actions that lessees, owners, and operators must take to meet those expectations. BOEM and BSEE do not anticipate that these requirements, or their associated costs, will prevent lessees and operators from conducting exploratory drilling on their leases. In pursuing such operations, Arctic OCS lessees and operators are well aware of the significant challenges presented by Arctic OCS conditions, and the final rule largely reflects clarification and codification of the Bureaus' expectations under existing regulations and industry standards for the relevant operations. In fact, the additional clarity and specificity provided by the final
rule should assist the oil and gas industry to plan better and to more effectively conduct exploratory drilling on the Arctic OCS with lower risk. As discussed later in this final rule, the positive impact of such production on U.S. energy independence and energy security could be substantial if hydrocarbon resources can be extracted and marketed economically. Thus, this final rule would help achieve the NSAR goals of protecting the unique and sensitive Arctic ecosystems, as well as the subsistence-based health and culture of nearby Alaska Native communities, while reducing reliance on imported oil and strengthening National energy security.
E. Availability of Incorporated Documents for Public Viewing
BSEE frequently uses standards (
e.g.,
codes, specifications, Recommended Practices (RP)) developed through a consensus process, facilitated by standards development organizations and with input from the oil and gas industry, as a means of establishing requirements for activities on the OCS. BSEE may incorporate these standards into its regulations without republishing the standards in their entirety in the Code of Federal Regulations (CFR), a practice known as incorporation by reference. The legal effect of incorporation by reference is that the incorporated standards become regulatory requirements. This incorporated material, like any other properly issued regulation, has the force and effect of law, and BSEE holds operators, lessees and other regulated parties accountable for complying with the documents incorporated by reference in our regulations. We currently incorporate by reference over 100 consensus standards in BSEE's regulations governing offshore oil and gas operations (
see
30 CFR 250.198).
Federal regulations, at 1 CFR part 51, govern how BSEE and other Federal agencies incorporate various documents by reference. Agencies may only incorporate a document by reference by publishing in the
Federal Register
the document title, edition, date, author, publisher, identification number, and other specified information. The Director of the
Federal Register
must approve each publication incorporated by reference in a final rule. Incorporation by reference of a document or publication is limited to the specific edition cited by the agency in the final rule and approved by the Director of the Federal Register.
BSEE incorporates by reference in its regulations many oil and gas industry standards in order to require compliance with those standards in offshore operations. When a copyrighted publication is incorporated by reference into BSEE regulations, BSEE is obligated to observe and protect that copyright. BSEE provides members of the public with Web site addresses where these standards may be accessed for viewing—sometimes for free and sometimes for a fee. Standards development organizations decide whether to charge a fee. One such organization, the American Petroleum Institute (API), provides free online public access to review its key industry standards, including a broad range of technical standards. These standards represent almost one-third of all API standards and include all that are safety-related or are incorporated into Federal regulations. One of those standards is incorporated by reference in this final rule. In addition to the free online availability of the standard for viewing on API's Web site, hardcopies and printable versions are available for purchase from API. The API Web site address is:
http://www.api.org/publications-standards-and-statistics/publications/government-cited-safety-documents.
5
5
To review these standards online, go to the API publications Web site at:
http://publications.api.org.
You must then log-in or create a new account, accept API's “Terms and Conditions,” click on the “Browse Documents” button, and then select the applicable category (
e.g.,
“Exploration and Production”) for the standard(s) you wish to review.
For the convenience of members of the viewing public who may not wish to purchase or view these incorporated documents online, they may be inspected at BSEE's office, 45600 Woodland Road, Sterling, Virginia 20166; phone: 703-787-1665.
F. Summary of Documents Incorporated by Reference
This rulemaking is substantive in terms of the content that is explicitly stated in the rule text itself, and it also incorporates by reference a technical standard concerning structures and pipelines for offshore Arctic conditions. A brief summary of the standard follows.
ANSI/API Recommended Practice 2N, Recommended Practice for Planning, Designing, and Constructing Structures and Pipelines for Arctic Conditions
This standard was developed in response to the offshore industry's demand for a coherent and consistent definition of methodologies to design, analyze, and assess arctic and cold region offshore structures. This standard also addresses issues such as topsides, winterization, and escape, evacuation, and rescue that go beyond what is strictly necessary for the design, construction, transportation, installation, and decommissioning of the structure. These issues are essential for offshore operations in arctic and cold region conditions and they are not covered in other standards. When future editions of this and other standards are prepared, effort will be made to avoid duplication of scope.
II. Background
A. Statutory and Regulatory Overview
1. Procedural History
On February 24, 2015, BOEM and BSEE published an NPRM in the
Federal Register
entitled, “Oil and Gas Operations in the Outer Continental Shelf—Requirements for Exploratory Drilling on the Arctic Outer Continental Shelf” (80 FR 9916). In response to several commenters' requests, we published a 30-day extension of the comment period for the NPRM on April 20, 2015 (80 FR 21670). We received 1,311 letters to the docket for the rulemaking, from over 100,000 individual commenters on the NPRM. We summarize these comments in the preamble of this final rule in Section IV.B
Discussion of and Responses to Comments.
Between June 6, 2013 and July 15, 2016, BOEM and BSEE held several meetings as part of tribal consultations on this rulemaking in the following Alaskan locations: Kotzebue, Point Hope, Point Lay, Barrow, Wainwright, and via teleconference with Nuiqsut. Comments received from Alaska Native Tribes and ANCSA Corporations, both written and oral, are summarized in Section IV.B. Discussion of these consultations with Alaska Native Tribes and Corporations appears in the preamble at Section V.I
Consultation with Indian Tribes (E.O 13175).
2. OCSLA
The OCSLA, 43 U.S.C. 1331
et seq.,
was first enacted in 1953, and substantially amended in 1978, when Congress established a national policy of making the OCS “available for expeditious and orderly development, subject to environmental safeguards, in a manner which is consistent with the maintenance of competition and other national needs” (43 U.S.C. 1332(3)). In addition, Congress emphasized the need to develop OCS mineral resources in a safe manner “by well-trained personnel using technology, precautions, and techniques sufficient to prevent or minimize the likelihood of blowouts, loss of well control, fires, spillages,
physical obstruction to other users of the waters or subsoil and seabed, or other occurrences which may cause damage to the environment or to property, or endanger life or health” (43 U.S.C. 1332(6)). The Secretary of the Interior (Secretary) administers the OCSLA's provisions relating to the leasing of the OCS and regulation of mineral exploration and development operations on those leases. The Secretary is authorized to prescribe “such rules and regulations as may be necessary to carry out [OCSLA's] provisions” and “may at any time prescribe and amend such rules and regulations as [s]he determines to be necessary and proper in order to provide for the prevention of waste and conservation of the natural resources of the [OCS] . . .” which “shall, as of their effective date, apply to all operations conducted under a lease issued or maintained under the provisions of [OCSLA]” (43 U.S.C. 1334(a)).
The Secretary delegated most of the responsibilities under the OCSLA to BOEM and BSEE, both of which are charged with administering and regulating aspects of the Nation's OCS oil and gas program (see § 250.101 and § 550.101). BOEM and BSEE work to promote safety, protect the environment, and conserve offshore resources through vigorous regulatory oversight.
BOEM manages the development of the Nation's offshore energy resources in an environmentally and economically responsible way. BOEM's functions include leasing; exploration, development and production plan administration and review; environmental analyses to ensure compliance with the National Environmental Policy Act of 1969 (NEPA); environmental studies; resource evaluation; economic analysis; complying with other Federal laws (
e.g.,
the Endangered Species Act (ESA)); and management of the OCS renewable energy program.
BSEE performs offshore regulatory oversight and enforcement to ensure safety and environmentally sound performance during operations, and the conservation of OCS resources, by, among other things, evaluating drilling permits, and conducting inspections to ensure compliance with laws, regulations, lease terms, and approved plans and permits.
Prior to commencing exploration for oil and gas on the OCS, OCSLA and its implementing regulations (43 U.S.C. 1340(c)(1); § 550.201(a)) require lessees to submit an EP to BOEM for approval. An EP must include information such as a schedule of anticipated exploration activities, equipment to be used, the general location of each well to be drilled, and any other information deemed pertinent by BOEM (§§ 550.211 through 550.228).
However, approval of an EP does not by itself permit the lessee to proceed with exploratory drilling. After the EP is approved, the lessee must submit to BSEE an Application for Permit to Drill (APD), which BSEE must approve before a lessee may drill a well (43 U.S.C. 1340(d); § 250.410)). The APD must be consistent with the approved EP and include information on the well location, the drilling design and procedures, casing and cementing programs, the diverter and Blowout Preventer (BOP) systems, MODU (if one is used), and additional information requested by the District Manager.
BOEM evaluates EPs, and BSEE evaluates APDs, to determine whether the operator's proposed activities meet the OCSLA's standards and each Bureau's regulations governing OCS exploration. The regulatory requirements include, but are not limited to, ensuring that the proposed drilling operation:
i. Conforms to OCSLA, as amended, its applicable implementing regulations, lease provisions and stipulations, and other applicable laws;
ii. Is conducted in a safe manner;
iii. Conforms to sound conservation practices and protects the rights of the U.S. in the mineral resources of the OCS;
iv. Does not unreasonably interfere with other uses of the OCS; and
v. Does not cause undue or serious harm or damage to the human, marine, or coastal environments (§§ 250.101 and 250.106; 550.101 and 550.202).
Based on these evaluations, BOEM and BSEE will approve the lessee's (or operator's) EP and APD, require the lessee (or operator) to modify its submissions, or disapprove the EP or APD (§§ 250.410; 550.233).
3. The Oil Pollution Act of 1990 (OPA) and Clean Water Act (CWA)
Congress passed the OPA, 33 U.S.C. 2701
et seq.,
following the
Exxon Valdez
oil spill. The OPA amended the CWA, 33 U.S.C. 1251
et seq.,
by, among other things, adding OSRP requirements for offshore facilities. The OPA provides for prompt federally coordinated responses to offshore oil spills and for compensation of spill victims. It also calls for the issuance of regulations prohibiting owners and operators of offshore facilities from operating or handling, storing, or transporting oil until:
i. They have prepared and submitted “a plan for responding, to the maximum extent practicable, to a worst case discharge (WCD), and to a substantial threat of such a discharge, of oil . . .;”
ii. The plan “has been approved by the President;” and
iii. The “facility is operating in compliance with the plan” (OPA section 4202(a), codified at 33 U.S.C. 1321(j)(5)(A)(i) and (F)(i)-(ii)).
E.O. 12777 (October 18, 1991) delegated to the Secretary the functions of 33 U.S.C. 1321(j)(5) and (j)(6)(A) related to offshore facilities (other than deep water ports). This includes the promulgation of regulations governing the obligation to prepare and submit OSRPs, the review and approval of OSRPs, and the periodic verification of spill response capabilities related to these plans. Those applicable regulations are administered by BSEE and are at parts 250 and 254. E.O. 12777 also delegated to the Secretary the authority to implement, for offshore facilities, 33 U.S.C. 1321(j)(1)(C), which provides for the issuance of regulations “establishing procedures, methods, and equipment and other requirements for equipment to prevent discharges of oil and hazardous substances from . . . offshore facilities, and to contain such discharges.”
B. Factual Overview of the Arctic OCS Region
1. Arctic OCS Oil and Gas Activity
There has been a renewed interest in the oil and gas potential of the Alaska OCS since the first exploratory wells were drilled in the late 1970s. The majority of exploratory drilling north of the Arctic Circle has occurred where the greatest oil and gas resource potential exists, namely the Beaufort Sea and Chukchi Sea Planning Areas (
see
Figure 1). A total of 30 exploratory wells have been drilled on the Beaufort OCS since the first Federal OCS leases were offered, and more wells have been drilled beneath the near-shore Beaufort Sea under the jurisdiction of the State of Alaska. The Chukchi Sea Planning Area has a more limited history of leasing and exploration. Before 2012, only a total of five exploratory wells had been drilled there (between 1989 and 1991
6
), and no explored prospect was considered economically viable for development.
6
See
BOEM Alaska Region Web site available at
www.boem.gov/About-BOEM/BOEM-Regions/Alaska-Region/Historical-Data/Index.aspx.
Until Shell's 2012 and 2015 exploratory operations, there had been only one exploratory well drilled on the Arctic OCS since 1994—the 2003
exploratory well near Prudhoe Bay in the Beaufort Sea (
see
BOEM Assessment of Undiscovered Technically Recoverable Oil and Gas Resources of the Nation's Outer Continental Shelf (2016). In 2012, Shell drilled two “top hole” wells (
i.e.,
a partial well not intended to enter hydrocarbon zones), one in the Chukchi Sea (Burger Prospect) and the other in the Beaufort Sea (Sivulliq). In 2015, Shell completed an exploratory well in the Burger prospect of the Chukchi Sea; however, according to Shell, indications of oil and gas were “not sufficient to warrant further exploration in the Burger prospect.”
7
7
http://www.shell.com/global/aboutshell/media/news-and-media-releases/2015/shell-updates-on-alaska-exploration.html.
ER15JY16.099
With the exception of three OCS leases making up a portion of the Northstar oil field, currently operated by Hilcorp Alaska, LLC, from State submerged lands in the Beaufort Sea, no production has yet resulted from Alaska OCS leases.
2. Challenges to U.S. Arctic Oil and Gas Operations
The challenges to conducting operations and responding to emergencies in the extreme and variable environmental and weather conditions in the Arctic are demanding. Both the Beaufort Sea and Chukchi Sea Planning Areas experience sub-freezing temperatures during most of the year, extended periods of low-light visibility, significant fog cover in the summer, strong winds and currents, storms that produce freezing spray and dangerous sea states, snow, and significant ice cover. During the fall (September-November), conditions become increasingly inhospitable as air temperatures decrease, wind speeds increase, storms become more frequent, and sea ice begins to form, all of which make Arctic OCS exploratory drilling operations more challenging.
8
Other challenges to conducting operations and responding to emergencies on the Arctic OCS include the geographical remoteness and relative lack of established infrastructure to support oil and gas operations, as well as the presence of protected marine mammals and Alaska Native subsistence activities.
8
See
Environmental Assessments for Shell Offshore, Inc.'s Revised Outer Continental Shelf Lease Exploration Plan, Camden Bay, Beaufort Sea, Alaska (2011), Revised Outer Continental Shelf Lease Exploration Plan, Chukchi Sea, Alaska, Burger Prospect (2015), and Shell Gulf of Mexico, Inc.'s Revised Chukchi Sea Exploration Plan Burger Prospect (2011); BOEM Alaska Region Web site available at
http://www.boem.gov/About-BOEM/BOEM-Regions/Alaska-Region/Environment/Environmental-Analysis/Environmental-Impact-Statements-and-Major-Environmental-Assessments.aspx.
III. Regulations for Arctic OCS Exploratory Drilling
The existing OCS oil and gas regulatory regime is extensive and covers all offshore facilities or operations in any OCS region, as appropriate and applicable, including the Arctic OCS. BOEM and BSEE apply these regulations while overseeing OCS leasing, exploration, development, production, and decommissioning. Operators are subject to the same regulatory requirements, such as: Application procedures and information requirements for exploration, development, and production activities; pollution prevention and control; safety requirements for casing and cementing and the use of a BOP and diverter systems; design, installation, use and maintenance of OCS platforms to ensure structural integrity and safe and environmentally protective operations; decommissioning; development and implementation of Safety and Environmental Management Systems (SEMS); and preparation and submission of OSRPs (
see generally
30 CFR parts 250, 254, and 550).
The existing regulations also contain provisions that apply to specific regions or atypical activities or operating conditions, especially, for example, where drilling occurs in deep water or in a “frontier” area (typically characterized by its remote location and limited infrastructure and operational history, such as the Arctic OCS region).
In these situations, BOEM and BSEE have special requirements, such as information and design requirements for deep-water development projects (§§ 250.286 through 250.295); use of appropriate equipment, third-party audits, and contingency plans in frontier areas or other areas subject to subfreezing conditions (§§ 250.713(c) and 250.418(f)); the placement of subsea BOP systems in mudline cellars when drilling occurs in areas subject to ice-scouring (§ 250.738); and emergency plans and critical operations and curtailment procedures information in the Arctic OCS Region (§§ 550.220 and 550.251).
Though there is currently a generally applicable OCS oil and gas regulatory program, there is a need for new and amended regulatory measures specifically for Arctic OCS exploratory drilling by MODUs. This final rule, in combination with the existing regulations (which continue to apply to Arctic OCS operations unless otherwise expressly stated) will ensure that exploratory drilling operations are well planned from the outset and conducted safely and responsibly in relation to the unique Arctic environment and the local communities that are closely connected to the region and its resources. The key elements of the final rule are as follows:
A. Measures That Address Recommendations
The final rule addresses recommendations contained in several recent reports on OCS oil and gas activities, including the Arctic Council, Arctic Offshore Oil and Gas Guidelines (2009); the National Commission on the BP
Deepwater Horizon
Oil Spill and Offshore Drilling (2011); Ocean Energy Safety Advisory Committee Recommendations (2013); DOI's 60-Day Report (2013); the E.O. 13580 Alaska Energy Permitting IWG's report entitled, “Managing for the Future in a Rapidly Changing Arctic, A Report to the President” (March 2013); the NSAR (May 2013); the Arctic Council, Arctic Offshore Oil and Gas Guidelines: Systems Safety Management and Safety Culture (March 2014); and the National Petroleum Council (NPC), Arctic Potential: Realizing the Promise of U.S. Arctic Oil and Gas Resources (2015).
B. Approval of Alternate Procedures or Equipment
Numerous comments were submitted on the NPRM requesting a more performance-based approach to regulating exploratory drilling operations on the Arctic OCS. As discussed in depth in Section IV. B,
Discussion of and Responses to Comments,
we are aware that methods for source control and containment, securing a well, or killing and permanently plugging an out-of-control well on the Arctic OCS may include available technology for which there are no recognized industry standards or best practices. Accordingly, several of the final regulations are intended to convey an overarching performance requirement. For example, the operator must have the means available to secure any uncontrolled flow of hydrocarbons and kill the out-of-control well prior to seasonal ice encroachment. The regulations also provide prescriptive elements establishing means to comply with that requirement using existing, proven technology. And finally, the regulations provide a clear pathway towards alternative compliance measures to account for future technological advances. To further clarify our intent, we are revising the proposed language of both § 250.471,
What are the requirements for Arctic OCS source control and containment?,
and § 250.472,
What are the relief rig requirements for the Arctic OCS?
Paragraph (a) of § 250.471 is revised and a new paragraph (i) in § 250.471 is added to clearly convey the performance standard an operator must be able to demonstrate when requesting approval for alternative procedures or equipment to the SCCE—
i.e.,
response capabilities able to stop or capture the flow of an out-of-control well. Similarly, we are also revising the provisions at paragraphs (a) and (c) of § 250.472 to clarify that alternative procedures or equipment to the relief rig requirements must be capable of killing and permanently plugging an out-of-control well in less than 45 days.
Furthermore, existing regulations will continue to allow operators to use new and emergent technology on the OCS in certain circumstances and upon demonstrating adequate safety and environmental protection. Under § 250.141,
May I ever use alternate procedures or equipment?,
the District Manager or Regional Supervisor may approve the use of alternate procedures or equipment provided the operator can show the technology will meet or exceed the level of safety and environmental protection required by the current regulations. This provision enables operators to request approval for innovative technological advancements that may provide additional flexibility, provided the operator clearly establishes that such technology will meet or exceed the level of protection provided by the regulatory requirements. The operator is responsible for providing sufficient data to BSEE to adequately demonstrate the safety of the technology or operations. To obtain approval under § 250.141, an operator should submit information regarding its proposed alternate technology, which could include:
1. Laboratory tests results, test protocols, test procedures, testing methodologies, Quality Assurance/Quality Control provisions, manufacturer testing, and/or qualification or accreditation procedures implemented by an independent third party relevant to the performance characteristics of such equipment when used in a real world environment;
2. Actual operational performance of such equipment if previously used or currently being used in other areas under similar conditions; and
3. Additional studies, evaluations, or risk and/or hazards analyses relevant to the equipment or procedures under consideration.
C. IOP Requirement
During exploratory drilling operations on the Arctic OCS, operators may face substantial environmental challenges and operational risks throughout every phase of the endeavor, including preparations, mobilization, in-theater drilling operations, emergency response and preparedness, and demobilization. Thorough advanced planning is critical to mitigating these challenges and risks. One of the key components of this final rule is a requirement that operators explain how their proposed Arctic OCS exploratory drilling operations are fully integrated from start to finish in a manner that accounts for Arctic OCS conditions and that they provide this information to DOI at an early stage of the planning process.
This final rule requires that operators develop and submit IOPs to BOEM at least 90 days in advance of filing their EPs. The purpose of the IOP is to describe, at a strategic or conceptual level, how exploratory drilling operations will be designed, executed, and managed as an integrated endeavor from start to finish. The IOP is intended to be a concept of operations that includes a description of pertinent aspects of an operator's proposed exploratory drilling activities and supporting operations and how the operator will design and conduct its program in a manner that accounts for the challenges presented by Arctic OCS conditions. The primary issues that operators must address in their IOPs include:
1. Vessel and equipment designs and configurations;
2. The overall schedule of operations, including contractor work on critical components;
3. Mobilization and demobilization operations and maintenance schedule(s);
4. In-theater drilling program objectives and timelines for each objective;
5. Weather and ice forecasting and management capabilities;
6. Contractor management and oversight;
7. Operational safety principles;
8. Preparation and staging of spill response assets;
9. Impact on local community infrastructure, including but not limited to housing, energy supplies and services; and
10. Extent the project will rely on local community workforce and spill clean-up response capacity.
DOI recognizes that other Federal agencies have primary oversight responsibility for some of the previously listed activities. Upon receipt of the IOP, DOI would engage with members of the E.O. 13580 Alaska Energy Permitting IWG and promptly distribute the IOP to the State of Alaska and Federal government agencies making up the Alaska Energy Permitting IWG and others that are involved in the review, approval, or oversight of various aspects of OCS operations.
However, the IOP process does not entail any mechanism through which agencies can or must approve the operator's proposed activities described in the IOP. The IOP is intended to be a conceptual, informational document designed to ensure that an operator has planned to address risks associated with the full suite of regulated activities, and to provide the relevant regulatory agencies a preview of an operator's approach to regulatory compliance and integrated planning. It is also anticipated that an operator would already develop much of this requested information as a part of its internal planning for potential activity. Thus, the IOP enables relevant agencies to familiarize themselves, early in the planning process, with the operator's overall proposed program from start to finish. This, in turn, allows DOI and those agencies to coordinate and provide early input to the operator regarding potential issues presented by the proposed activities with respect to any future EP reviews and permitting requirements, including aspects of the program that might require additional details or refinement. The IOP requirement—and the final rule in general—will not, however, interfere with or supplant operators' obligations to comply with all other applicable Federal agency requirements. Each agency that receives an IOP would continue to review the relevant details of an operator's planned activities for compliance with that agency's regulatory requirements in the appropriate manner and at the appropriate time under its own regulatory program.
D. SCCE and Relief Rig Capabilities
In Arctic OCS exploratory drilling, there is a need for operators to demonstrate that they have access to, and could promptly deploy, well control and containment resources that would be adequate to respond to a loss of well control. This equipment is readily available and accessible in the Gulf of Mexico due to the level of activity in that area, but is not similarly available in the Arctic as a matter of normal course. Ensuring that operators have redundant protective measures in place is critical, as there is no guarantee that a single measure could control or contain a WCD. Therefore, BSEE is requiring that operators who use a MODU for Arctic OCS exploratory drilling must be able to stop or capture the flow of an out-of-control well by having access to, and the ability to deploy, SCCE (
e.g.,
a capping stack, cap and flow system, and containment dome) within the timeframes discussed in this final rule and that the SCCE be capable of functioning in Arctic OCS conditions.
BSEE is also requiring operators to have access to a separate relief rig, staged at a location such that it could arrive on site, drill a relief well, kill and abandon the original well, and abandon the relief well prior to expected seasonal ice encroachment at the drill site and in no event later than 45 days after the loss of well control. This equipment is fundamental to safe and responsible operations on the Arctic OCS, where existing infrastructure is sparse, the geography and logistics make bringing equipment and resources into the region challenging, and the time available to mount response operations is limited by changing weather and ice conditions, particularly at the end of the drilling season.
The 45-day period is the maximum time allowed for conducting relief rig operations. However, it is a performance-based requirement and leaves the means of compliance up to the operator. The operator may seek to demonstrate its ability to complete relief well operations in less than 45 days, subject to review by BOEM in the EP process under § 550.22(c)(4) and BSEE's review during the APD process under § 250.470(c). The length of the “shoulder season”, or the period of time operators may not drill or work below the surface casing, depends upon how long operations related to the use of a relief rig can be expected to take. An operator must demonstrate how long it will take for a relief rig to arrive on site, drill a relief well, kill and abandon the original well and abandon the relief well prior to expected seasonal ice encroachment at the drill site (or trigger date). In evaluating this demonstration, consideration may be given to a number of factors, including but not limited to: The distance of drilling operations to the shore; available infrastructure; and the capacity and location of oil spill response equipment. The trigger date, established by BOEM (in consultation with the National Weather Service (NWS) and the operator)), restricts when the operator can drill or work below the surface casing in order to address risks associated with late season drilling and ensure an opportunity for spill response and cleanup in favorable conditions. BSEE notes the operator's actual timeframe to drill a relief well would be based on consideration of the distance between anticipated exploratory drilling sites, the availability of adequate staging locations for relief rigs, the length and complexity of rig transit, and the time necessary to complete the requisite operations once on-site. The 45-day maximum timeframe is intended to ensure a timely response and prevent an extended uncontrolled flow of hydrocarbons in the event of a loss of well control early in the open water season.
As discussed previously in Section III.B, we have revised the proposed language for the SCCE provisions at paragraph (a) of § 250.471 and added a new paragraph (i) in § 250.471, and revised the relief rig provisions at paragraphs (a) and (c) of § 250.472, to clearly state the standards operators must meet to satisfy the requirements, while also alternatively providing that operators may request approval of an alternate technology under existing § 250.141, if the operator can show the alternate technology will meet or exceed the level of safety and environmental protection provided by the SCCE and relief rigs requirements. This provision enables operators to request approval for innovative technological advancements that may provide additional flexibility.
E. Planning for the Variability and Challenges of the Arctic OCS Conditions
Reliable weather and ice forecasting play a significant role in ensuring safe
operations on the Arctic OCS. Advanced forecasting and tracking technology, information sharing among industry and government, and local knowledge of the operating environment are essential to managing the substantial challenges and risks that Arctic OCS conditions pose for all OCS operations. In light of the threats posed by ice and extreme weather events, BOEM and BSEE require that operators include in their IOPs, EPs, and APDs, at appropriate levels of specificity for each document, a description of their weather and ice monitoring and forecasting capabilities for all phases of their exploration program, as well as their alert procedures and thresholds for activating ice and weather management systems. Once operations commence, this rule requires operators to:
1. Notify BOEM and BSEE immediately of any sea ice movement or condition that has the potential to affect operations or trigger ice management activities; and
2. Notify BSEE of the start and termination of ice management activities and submit written reports after completing such activities.
F. Arctic OCS Oil Spill Response Preparedness
Operators need to be prepared for a quick and effective response in the event of an oil spill on the Arctic OCS and be ready to coordinate activities with the Federal government and other stakeholders. The OSRPs and related activities should be tailored to the unique Arctic OCS operating environment to ensure that operators have the necessary equipment, training, and personnel. Among other things, this final rule establishes specific planning requirements to maximize the application of oil spill response technology and ensure a coordinated response system designed to address the challenges inherent to the U.S. Arctic region.
G. Reducing Pollution From Arctic OCS Exploratory Drilling Operations
Partners, primarily Alaska Native Tribes, as well as other stakeholders expressed concern that mud and cuttings from exploratory drilling could adversely affect marine species (
e.g.,
whales and fish) and their habitat and compromise the effectiveness of subsistence hunting activities. Existing environmental analyses support these concerns regarding petroleum based mud and cuttings and also demonstrate that such discharges could affect water quality, benthic habitat, and marine organisms within the localized area (
see, e.g.,
Shell Revised Outer Continental Shelf Lease Exploration Plan, Chukchi Sea, Alaska, Burger Prospect (2015)).
BSEE is requiring the capture of all petroleum-based mud and associated cuttings from Arctic OCS exploratory drilling operations to prevent the discharge of such pollutants into the marine environment. The new provision also clarifies the Regional Supervisor's discretionary authority to require that operators capture all water-based mud and associated cuttings from Arctic OCS exploratory drilling operations (after completion of the hole for the conductor casing) to prevent their discharge into the marine environment. The Regional Supervisor would exercise this discretion based on various factors, such as the proximity of exploratory drilling operations to subsistence hunting and fishing locations or the extent to which such discharges might cause marine mammals and birds to alter their migratory patterns in a manner that interferes with subsistence activities or might adversely affect marine mammals, fish, birds, or their habitat(s).
H. Oversight, Management, and Accountability of Operations and Contractor Support
An effective risk management framework at the beginning of a project incorporates many components, including planning, vessel design, contractor selection, and an assessment of regulatory requirements for all facets of the project. DOI is requiring that operators provide an explanation, starting in the IOP, at a conceptual level, of how they would apply their oversight and risk management protocols to both their personnel and their contractors to support safe and responsible exploratory drilling. These new regulations, in conjunction with DOI's existing regulations, require varying levels of information about operator safety and oversight management at progressive stages of the planning and approval process. This would start with the most general information and increase the level of detail with successive regulatory submittals, as the project proceeds from planning to implementation (
e.g.,
IOP to EP to APD).
In addition, the final rule requires Arctic OCS operators to:
1. Report threatening sea ice conditions and ice management activities, and unexpected operational issues that could result in a loss of well control;
2. Conduct real-time monitoring of various aspects of well operations,
3. Increase their SEMS auditing frequency; and,
4. Enhance their oil spill preparedness and response capabilities for Arctic OCS operations.
A summary of the changes that this final rule makes to the provisions proposed by the NPRM follows:
IV. Section-By-Section Discussion of Changes and Comments
This section summarizes the requirements proposed in the NPRM and how they are addressed in this final rule. Some of these provisions received no comments during the public comment period, while other provisions were supported or criticized by certain commenters. Section IV.A discusses the changes from the proposed to the final rule. Section IV.B discusses the public comments received and our responses to the comments. Many of these provisions and concepts are described in more detail above in Section III.
A. Summary of Key Changes From the NPRM
This section includes a description of how the final rule differs from the provisions proposed by the NPRM (80 FR 9916 (February 24, 2015)) along with an explanation of why the changes in the final rule are necessary. For a full discussion of comments and BOEM and BSEE responses, see section IV.B
Discussion of and Responses to Comments.
Definitions. (§ 250.105)
BSEE is revising the proposed definition of “capping stack” to clarify that the required capping stack may be pre-positioned. Although the proposed definition did not preclude the use of a pre-positioned capping stack, in response to comments we determined a clarification to the definition of capping stack is appropriate. Accordingly, the addition of the clarification that the capping stack may be pre-positioned to the definition does not create a new category of capping stack, but instead clarifies that the use of a capping stack is not limited to subsea wellheads when surface BOPs are used. The revised definition makes clear that pre-positioned capping stacks may be used below subsea BOPs. BSEE will evaluate the use of a pre-positioned capping stack as a part of an operator's proposal on a case-by-case basis and approve their use when deemed technically and operationally appropriate, such as when the operator proposes to use a jack-up rig with surface trees.
When and how must I secure a well? (formerly § 250.402)
BSEE is revising the language of proposed § 250.402(c)(2) to clarify the
circumstances under which BSEE may approve an equivalent means to satisfy the requirement that, in areas of ice scour, an operator must use a mudline cellar. We note the former § 250.402 was removed and reserved and the contents were moved to § 250.720 in the Blowout Preventer Systems and Well Control Final Rule (Well Control Rule) (80 FR 25888) published April 29, 2016. Therefore, the revisions to proposed § 250.402(c)(2) discussed here have been finalized as § 250.720(c)(2) in this rulemaking. The proposed rule provided that the operator may use an equivalent means to minimize the risk of damage to the well head. In response to comments expressing concern for the operational risks presented by the mudline cellar when using a jack-up rig, BSEE has clarified what an operator should show when requesting to utilize an equivalent alternative that minimizes risk to both the well head and the wellbore. Having a mudline cellar in place to protect the well head and wellbore provides an additional protection against a loss of well control and possible release of hydrocarbons to the environment. Accordingly, we have revised the language to clarify that an operator seeking approval of an equivalent means must show that a mudline cellar would create operational risks, as finalized at § 250.720(c) as set out in the regulatory text at the end of this document.
When must I pressure test the BOP system? (§ 250.447)
The proposed amendments to § 250.447(b) are not being included in the final rule. BSEE has decided to maintain the same 14-day BOP pressure test cycle on the Arctic OCS as is required elsewhere on the OCS. The existing regulation in paragraph (a)(4) of § 250.737 provides that the District Manager or Regional Supervisor may require more frequent testing if conditions or BOP performance warrant.
As discussed in Section IV.B,
Discussion of and Response to Comments,
many commenters to the proposed 7-day BOP testing requirement were concerned that increasing the number of pressure tests may reduce the reliability of the equipment by degrading the sealing capability of the elements within the BOP stack and would not necessarily demonstrate the future performance of the equipment. Commenters also asserted that the requirement for operators to stop drilling operations to perform a pressure test could ultimately increase the likelihood of an incident occurring. The BOP is a critical line of defense against loss of well control. Ensuring the proper functioning of the BOP is essential to all OCS drilling operations BSEE considered whether the integrity of BOPs could be compromised by Arctic OCS conditions; in particular, BSEE considered the possible effects of extreme weather conditions on BOPs maintained on surface vessels or facilities (such as jack-up rigs). At this time, pressure tests and functional tests are the primary methods for ensuring the performance of BOPs. BSEE considered these and other issues raised via public comments and has determined not to require increased testing frequency on the Arctic OCS.
BSEE recognizes the importance of ensuring the proper functioning of the BOP. Shell proposed a 7-day BOP testing cycle in 2012, and BSEE ultimately approved that approach for Shell. We proposed in the NPRM to require a similar testing frequency for all Arctic OCS exploratory drilling operations, due to the possibility that the integrity of BOPs could be compromised by Arctic conditions. BSEE specifically requested comments on the appropriateness of the proposed 7-day testing frequency to demonstrate the reliability of the equipment under Arctic conditions; any additional safety issues that might arise from this increased testing or that would be unique to Arctic operations; and all potential drilling impacts related to the proposed 7-day testing frequency.
Comments on BOP testing frequency fell largely into two groups: Supporters of the 14-day (or longer) test cycle and supporters of the 7-day test cycle. BSEE considered all of the comments, the information and justifications provided by the commenters, and various studies in deciding the appropriate test frequency. After careful consideration, BSEE determined that increasing the testing frequency to 7-days could cause increased wear-and-tear and fatigue on the equipment, without measurably increasing the reliability of the BOPs. No significant evidence was presented by supporters of a 7-day test cycle that demonstrated that more frequent testing in all situations would increase safety, and no evidence was presented for why BSEE should have a different requirement for BOP pressure tests in the Arctic than elsewhere on the OCS.
Therefore, in the final rule BSEE removed the proposed amendments that would have required operators to test their BOP systems every 7 days during Arctic OCS exploratory drilling operations. Existing regulatory provisions address similar protection concerns. Paragraph (a)(4) of § 250.737 allows for the District Manager, to require more frequent testing if conditions (Arctic or otherwise) or the BOP performance warrant. Additionally, § 250.737(d)(9) requires a function test of the annular and ram BOPs every 7 days, between pressure tests, ensuring the BOP rams will function in all operating conditions.
9
9
Throughout this preamble, the Bureaus refer to regulatory provisions promulgated through the recently-finalized Blowout Preventer Systems and Well Control Rule (81 FR 25888 (April 29, 2016)) (WCR). To accommodate the respective timing of these rules, those references and the related discussions of the relevant WCR provisions are based upon the working assumption that those elements of the WCR go into effect as promulgated.
What are the real-time monitoring requirements for Arctic OCS exploratory drilling operations? (§ 250.452)
BSEE is revising the proposed § 250.452 to clarify the operator's responsibilities for complying with the real-time monitoring (RTM) requirements.
Paragraph (a) of § 250.452 is revised by deleting the phrase “all aspects of” from the provision identifying what functions must be monitored. This revision allows the operator flexibility in determining which elements of the identified functions will be monitored. The operator is responsible for recording, storing, and transmitting data regarding the BOP system; the well fluid's handling systems on the rig; and the well's downhole conditions as monitored by a downhole sensing system, when such a system is installed. The operator will determine what functional aspects of these systems should be monitored to meet the performance requirements of this provision.
BSEE has revised paragraphs (a) and (b) of § 250.452 to make clear that it is not necessary to cease operations because of a temporary loss of the RTM data feed due to a failure or interruption in the RTM data feed to shore. In this type of situation, the operator should have the ability to gather and record the data in the control room of the offshore unit and transmit the data to shore once the data feed is restored. To clarify this, we deleted the word “immediately” from paragraph (b) of § 250.452 and added the phrase “as they are gathered, barring unforeseeable or unpreventable interruptions in transmissions,” to describe the proper timing of the data transmission. Additionally, to clarify that in the event of a failure or interruption of the datalink the operator should continue collecting RTM data, we added qualifying language to paragraph (a) in § 250.452, providing that the monitoring system must be “independent, automatic, and
continuous” to ensure the operator is able to transmit data, even if not immediately, in a timely and appropriate manner.
We have also revised paragraph (b) in § 250.452 by deleting the proposed text: “and who have the authority, in consultation with rig personnel, to initiate any necessary action in response to abnormal data or events.” BSEE recognizes that operators typically seek to ensure that command and control decision making is primarily the responsibility of the onboard rig personnel, and that the RTM support personnel typically function in an advisory capacity. The RTM monitoring requirements seek to help improve, not disrupt, the ability of onboard rig personnel to monitor operations and assess and mitigate risks.
The final clarifying revision to paragraph (a) in § 250.452 tightens the language, changing from the proposed “you must have real-time data gathering and monitoring, capability to record, store, and transmit data” to now read: “you must gather and monitor real-time data using an independent, automatic, and continuous monitoring system capable of recording, storing, and transmitting data.” Other than as discussed above, these revisions are designed to make the regulatory language clearer and easier to understand and apply.
What are the requirements for Arctic OCS source control and containment? (§ 250.471)
As discussed in Sections III.B
Approval of Alternate Procedures or Equipment
and III.D
SCCE and Relief Rig Capabilities,
BSEE is revising the language proposed in § 250.471 to clarify that operators using a MODU when drilling below or working below the surface casing must have access to SCCE that is capable of stopping or capturing the flow of an out-of-control well. Accordingly, we are revising § 250.471(a) to clearly state that the operator must have access to SCCE equipment capable of “stopping or capturing the flow of an out-of-control well”. We are also adding a paragraph (i) to clarify that when an operator is requesting approval of alternate procedures or equipment to the SCCE requirements under the provisions of § 250.141, the operator must demonstrate that the proposed alternate procedures or equipment provide a level of safety and environmental protection that meets or exceeds that required by BSEE regulations, including demonstrating that the alternate procedures or equipment will be capable of stopping or capturing the flow of an out-of-control well. These revisions are in response to commenters' concerns that the language as originally proposed did not clearly state a performance standard.
What are the relief rig requirements for the Arctic OCS? (§ 250.472)
Also as discussed in Sections III.B and III.D, BSEE is revising the language proposed in § 250.472 to clarify the performance standard that must be met when proposing to use alternate equipment or procedures to the relief rig requirements of § 250.472. Specifically, we are adding the phrase “able to kill and permanently plug an out-of-control well” to the language of proposed § 250.472(a) to clearly state the performance standards the relief rig must achieve. We are also revising the language of proposed § 250.472(c) to clarify that when an operator is requesting approval of alternate procedures or equipment to the relief rig requirements under the provisions of § 250.141, the operator must demonstrate that the proposed alternate procedures or equipment provide a level of safety and environmental protection that meets or exceeds that required by BSEE regulations, including demonstrating that the alternate procedures or equipment will be able to kill and permanently plug an out-of-control well. These revisions are in response to commenters' requests for a clear statement of a performance standard and are designed to offer guidance and clarification to operators with respect to the performance-based standard established by this rule that any proposed alternate compliance must meet or exceed in connection with the requirements finalized in this rulemaking.
If I propose activities in the Alaska OCS Region, what planning information must accompany the EP? (§ 550.220)
BOEM is revising § 550.220(c)(6)(ii) to clarify the intent of the provision. This provision is designed to obtain information regarding the operator's relief rig plans through the EP. BOEM has revised the provision in response to comments, removing language that could potentially create confusion over the interaction between the BOEM EP informational provision and the BSEE operational relief rig requirements at § 250.472. The intent of § 550.220(c)(6)(ii) is to obtain the information that is known at the time of EP submission regarding the operator's plans for compliance with the requirements of § 250.472(b). Therefore, as a technical correction, we finalized the text of § 550.220(c)(6)(ii) without reference to “into zones capable of flowing liquid hydrocarbons.” This revision is explained in further detail in Section IV.B.
Technical and Clarifying Edits
The Bureaus have made several additional changes between the proposed and final regulatory text that are technical made in order to clarify edits. These changes result in more easily understandable regulations but do not make substantive changes. For this reason, the Bureaus have determined that further notice and comment is unnecessary pursuant to 5 U.S.C. 553(b).
B. Discussion of and Responses to Comments
The Bureaus divided our discussion and responses to the comments received into subject matter topics, beginning with general comments, and then organized them by section number in the order in which operators would seek to comply with the regulations during permitting and operations.
Although BSEE permitting and operational requirements appear earlier in 30 CFR part 250, with the BOEM requirements following in 30 CFR part 550, in practice the IOP and EP phases governed by the 30 CFR part 550 regulations would precede the drilling approval and oversight phases governed by 30 CFR part 250. Requirements to prepare for an oil spill, which are contained in part 254, may be met at any time before handling, storing, or transporting oil in operations BSEE permits under part 250. Consequently, the subject matter topics are presented in this preamble in the following order: Definitions of
Arctic OCS
(§§ 250.105, 254.6, and 550.105) and
Arctic OCS conditions
(§§ 250.105 and 550.105), the discussion of and response to comments on BOEM's final regulations (
i.e.,
§§ 550.105, 550.200, 550.204, 550.206, and 550.220), and then the remainder of BSEE's final regulations (
i.e.,
§§ 250.105, 250.188, 250.198, 250.300, former 250.402/finalized as 250.720, 250.418, 250.447, 250.452, 250.470, 250.471, 250.472, 250.473, and 250.1920; §§ 254.6, 254.55, 254.65, 254.70, 254.80, and 254.90).
1. General Comments
Several comments addressed general concepts related to the rulemaking, instead of specific regulatory requirements proposed in the NPRM. These commenters opposed finalizing the proposed rule for a variety of reasons including: An opposition to all drilling in the Arctic Region; the proposed regulations are unnecessary, or overly restrictive or too costly; and
the request for the proposed rule to be withdrawn and re-proposed with additional information. BOEM and BSEE respond to these comments below.
The U.S. Government Should Ban All Offshore Drilling in the Arctic Region
Many commenters opposed the proposed rule in its entirety because of their opposition to all drilling in the Arctic Region, based on concerns over climate change and other environmental reasons. Some of these commenters supported the development of renewable energy in lieu of continued exploration for oil and gas resources.
BOEM and BSEE strongly agree with the need to protect the Arctic environment, and the requirements of this final rule are an important means to achieve that goal. However, the decision whether or not to prevent the exploration and development in the Arctic OCS is beyond the scope of this rulemaking. OCSLA establishes a process for deciding when and where to issue leases based on a defined set of criteria (
see
43 U.S.C. 1344). That is the appropriate process for deciding whether the Arctic OCS should be explored and developed, not this rulemaking.
Advancing renewable energy and transitioning away from reliance on fossil fuels is critical in the long term, but fossil fuels will continue to be an important part of the U.S.' energy portfolio for the foreseeable future. The Department is required by OCSLA to make the OCS “available for expeditious and orderly development, subject to environmental safeguards, in a manner which is consistent with the maintenance of competition and other national needs.” 43 U.S.C. 1332(3). As discussed throughout this preamble, and in several studies and reports available in the docket, the development of the U.S. Arctic's significant resources has the potential to promote a greater national reliance on domestic energy resources, benefits for the U.S. economy, and enhanced global energy security. The protection of the Arctic marine and coastal environments where drilling activities take place is of the utmost importance to BOEM and BSEE. The requirements finalized in this rule ensure that current and future exploratory drilling activities on the Arctic OCS are conducted safely and responsibly, subject to strong operational requirements.
The Proposed Regulations Are Unnecessary or Overly Restrictive or Too Costly
A large number of commenters argue the regulations should not be finalized because they are unnecessary due to other Federal agencies' existing regulations. Many of these commenters also assert that the regulations are overly restrictive and will be too costly. The comments do not provide specific costs or identify specific offending provisions, but only that the regulations should not be finalized.
BOEM and BSEE disagree. The operating environment for exploratory drilling operations on the Arctic OCS is characterized by unique environmental conditions, geographic remoteness, and a relative lack of fixed infrastructure and existing operations. The provisions of this rule are necessary and appropriate to address those challenges.
BOEM and BSEE engaged in Government-to-Government Tribal consultations and Government-to-ANCSA Corporations consultations to discuss the subject matter of the proposed rule and solicit input in the development of the final rule. Additionally, many comments on the NPRM support the finalization of this rule. This rulemaking takes into account the feedback we have received from these consultations and public comments and the lessons learned from recent exploratory drilling activity on the Arctic OCS. The provisions of this final rule do not add significant burdens beyond those that BOEM and BSEE required of Shell in 2012 and 2015, as part of the conditions of approval for its EP and permits to drill. From inception to completion, every phase of Arctic OCS operations comes with inherent challenges and operational risks. BOEM and BSEE determined that the final rule is reasonable and necessary to ensure that Arctic OCS exploration is conducted responsibly and in accordance with the highest safety and environmental standards. The final regulations are also necessary to provide regulatory certainty to industry regarding the requirements BOEM and BSEE will continue to expect operators to meet in their exploration and drilling programs. This final rule provides greater certainty to partners and stakeholders that Arctic OCS operations will be undertaken with the utmost regard for safety and environmental protection. The estimated costs and benefits of the rule are analyzed in greater detail in the final RIA and discussed in the E.O. 12866 section.
The Proposed Regulations Should Be Withdrawn and Re-Proposed With Additional Information
Many commenters request the proposed rule be withdrawn in its entirety. These commenters request withdrawal based on two different rationales.
One group of commenters requested that BOEM and BSEE withdraw the proposed rule and re-propose a rule with provisions aligning with the recommendations from a study by the NPC, a Department of Energy Federal Advisory Committee, entitled, “Arctic Potential: Realizing the Promise of U.S. Arctic Oil and Gas Resources”, (NPC Arctic Potential Study, March 27, 2015) (available at:
http://www.npcarcticpotentialreport.org/
).
We disagree with this suggestion. BOEM and BSEE participated in the development of the NPC Arctic Potential Study and used, where appropriate, knowledge gained from its development. It is our view that this final rule comprehensively addresses the challenges to prudent hydrocarbon exploration posed by the Arctic OCS's unique operating environment. BOEM and BSEE recognize the value of the NPC Arctic Potential Study as a study that considers the research and technology opportunities to enable prudent development of U.S. Arctic oil and gas resources. However, it is only one of the resources we considered in developing regulations that will ensure the safe and responsible development of petroleum resources on the Arctic OCS.
The second group of commenters recommended that BOEM and BSEE delay the finalization of this final rule until the proposed Well Control Rule was finalized.
BOEM and BSEE decided to finalize the Well Control Rule in advance of this rulemaking (
see
81 FR 25888), although the publication of the final rule on Arctic OCS exploration in advance of the Well Control Rule would not have resulted in any conflicting provisions. Throughout both rulemaking processes, BOEM and BSEE ensured the final rule on Arctic OCS exploration and the Well Control Rule contained regulatory provisions that are consistent. The Well Control Rule applies across the entirety of the OCS, including in the Arctic OCS. Many of the provisions of the final rule on Arctic OCS exploration, however, go beyond the scope of the Well Control Rule, and respond to unique challenges posed by the Arctic OCS operating environment. Finalization of the final rule on Arctic OCS exploration, independent of the Well Control Rule, puts in place the needed systems and processes that reduce risk and provide rigorous safeguards for Alaska's North Slope coastal communities and sensitive U.S. Arctic marine environment.
2. Definitions
BOEM and BSEE proposed to add new definitions in the proper alphabetical order for
Arctic OCS
and
Arctic OCS conditions
to existing §§ 250.105 and 550.105. We received no comments on the proposed definition for
Arctic OCS conditions
and it is finalized as proposed.
BSEE further proposed to add new definitions in the proper alphabetical order for
Cap and flow system, Containment dome, District Manager, Source control and containment equipment (SCCE)
and
Capping stacks
to existing § 250.105. No comments were received to the proposed definitions at § 250.105 of
Cap and flow system, Containment dome,
or
District Manager
and they are finalized as proposed. Comments were received on the proposed § 250.105 definitions of
Arctic OCS, Source control and containment equipment (SCCE)
and
Capping Stacks.
One commenter requested the final rule include a definition for MODU.
Arctic OCS
Three commenters requested BOEM and BSEE refine the proposed definition of “Arctic OCS” in §§ 250.105 and 550.105 to include more than the Beaufort and Chukchi Sea Planning areas. Two of these commenters suggested utilizing all OCS areas north of the Arctic Circle under U.S. jurisdiction as the “Arctic OCS”.
BOEM and BSEE disagree that the “Arctic OCS” should be redefined to include offshore areas beyond the Beaufort Sea and Chukchi Sea Planning Areas. We determined that the final definition in this rulemaking should align with the areas of the Arctic OCS utilized in the DOI OCS Oil and Gas Leasing Program for 2012-2017 (June 2012, available at
http://www.boem.gov/Five-Year-Program-2012-2017
). The Arctic OCS definition is reflective of the conditions and challenges the rule is designed to address, and allows focus on Planning Areas with higher hydrocarbon potential. Any other details added to this definition would increase confusion over the scope and applicability of the rule.
SCCE
One commenter stated the proposed definition of SCCE in § 250.105 excludes some of the primary intervention options, such as injection as a means to secure the well. The commenter recommended the definition for surface devices should include pumps and injection lines for dynamic kill and injection into well, and reference to subsea equipment should include jumpers, manifolds, and associated equipment to facilitate pumping into the well.
BSEE disagrees and has chosen to include as SCCE equipment only the equipment necessary to regain control of a well when the primary systems fails and that is not used in everyday drilling operations. Standard equipment (such as the BOP) is specifically excluded from the definition as it is a requirement of safe drilling operations regulated in other provisions of BSEE's rules. The definition of SCCE is not intended to be exclusive or restrictive, nor is the requirement that operators possess and have the ability to promptly deploy such equipment intended to preclude the use of other intervention mechanisms not specifically mentioned.
Capping Stacks
One commenter noted the proposed definition for capping stacks in § 250.105 limits the use of pre-positioned capping stacks to subsea wellheads when surface BOPs are used. The commenter suggests that the definition should be expanded to allow pre-positioned capping stacks to be used below subsea BOPs when deemed technically and operationally appropriate, such as with a jack-up rig.
BSEE agrees that pre-positioned capping stacks should be included in the definition. We therefore added the language “including one that is pre-positioned” to the definition for Capping Stack in § 250.105. BSEE will evaluate the use of a pre-positioned capping stack as a part of an operator's proposal on a case-by-case basis and approve their use below subsea BOPs when deemed technically and operationally appropriate, such as when an operator proposes to use a jack-up rig with surface trees.
MODU
One commenter requested a definition of MODU be included in the final rule.
BSEE disagrees. There is no one comprehensive definition of a MODU that can be utilized across parts 250, 254 and 550. MODUs include different types of vessels, including floating facilities or jack-up rigs, capable of engaging in well operations (
e.g.,
drilling, well completion and workover activities) for the purpose of exploring for or developing subsea oil, gas, or sulfur resources or related activities. What is considered a MODU may vary based on the activity being regulated. These regulations address only MODUs used for exploratory drilling, which include floating drilling vessels and jack-up rigs.
3. Additional Regulations by BOEM
Definitions (§ 550.200)
BOEM proposed to insert the acronym
IOP
—meaning Integrated Operations Plan—into the proper alphabetical location within existing § 550.200, for purposes of the IOP provisions. No comments were received on this provision and it is finalized as proposed.
When must I submit my IOP for proposed Arctic exploratory drilling operations and what must the IOP include? (§ 550.204)
BOEM proposed new § 550.204. This section requires operators to develop and submit IOPs to BOEM at least 90 days in advance of filing their EPs. The purpose of the IOP is to describe, at a strategic or conceptual level, how exploratory drilling operations will be designed, executed, and managed as an integrated endeavor from start to finish. The IOP is intended to be a concept of operations that includes a description of pertinent aspects of an operator's proposed exploratory drilling activities and supporting operations and how the operator will design and conduct its program in a manner that accounts for the challenges presented by Arctic OCS conditions. Several comments were received on this section. To clearly address the commenters' concerns, we have organized our discussion of § 550.204 in two separate topics: (i) Information requested for IOP completion, and (ii) appropriateness of IOP submission. BOEM has reviewed the comments and determined to finalize § 550.204 as proposed for the reasons stated herein.
Information Requested for IOP Completion
Many commenters generally criticized the IOP provision as being duplicative or redundant of existing requirements.
BOEM disagrees. The IOP rules are neither redundant nor duplicative of existing requirements. The IOP is meant to be an overview of all phases of the operator's proposed operations in order to allow the Federal agencies an earlier review in the planning process than currently exists. Section 550.204 requires a description of the design and operation of the proposed exploratory drilling program that demonstrates the operator is accounting for Arctic OCS conditions. Using this description, Federal agencies will coordinate and reduce potential delays by identifying possible vulnerabilities early in the planning process related to safety and environmental protection. This proactive approach enables the operator
to address these issues more effectively in the EP. Though BOEM would review the IOP to ensure that the operator's submission includes each of the elements listed in § 550.204, the IOP would not require approval by DOI or the other relevant agencies. Accordingly, the IOP is fundamentally distinct from the EP. First, the provisions of OCSLA that govern the EP do not apply to the IOP in that the EP requires an agency decision while the IOP is reviewed to ensure the submission is complete. Second, the operator's IOP will contain planning information with less specificity than that furnished with the EP.
Given the important role played by contractors and the fact that many contractors hired to operate on the Alaska OCS do not have a long operating history in the region, effective contractor oversight by operators is critical, and sufficient oversight of each contractor can be a challenge. Section 550.204(f) requires operators to plan for how they will manage contractors to reduce operational risks and address the challenges associated with operations on the Arctic OCS. Further, § 550.204(b) requires operators to plan to coordinate the work of a number of contractors to ensure that time pressure or other contractor complications do not undermine safe and environmentally responsible operations. This section requires a degree of advanced planning that should identify critical paths necessary for successful operations, ensure requisite resources are allocated, and mitigates risks through adequate forethought.
Additionally, if an operator determines that information it will submit in an EP is redundant with that submitted in an IOP, § 550.201(c) provides the Regional Director discretion, on a case-by-case basis, to waive submission of required information or analyses when sufficient applicable information or analyses are readily available to BOEM. Paragraph (d) of § 550.201 also allows for referencing other pre-existing information and data when submitting an EP if that information was previously submitted or is otherwise readily available to BOEM, thus allowing the IOP to simplify the EP preparation process.
Another group of commenters asserted that information required to be included in the IOP will not always be available 90 days before the EP submission. One of the commenters explained that much of the operator's data is immature during this planning phase.
BOEM acknowledges that the IOP will be submitted at a phase of the planning process when not all details of proposed operations will be in place, and that such details will necessarily be further developed through later stages of the process. While the operator will explain how exploratory activities will be integrated in its IOP, BOEM does not expect the IOP to exhibit the same level of detail that other documents (
i.e.
EP, APD, and OSRP) contain. For example, § 550.204(f) requests the operator to list the work its contractors will perform, but does not require the operator to have selected a specific contractor at the time of IOP submission. By providing that the operator need not have finalized contractor selection, it is reasonable for the IOP to be completed, at a minimum, 90 days before the submission of the EP.
The operator should already have the information required to complete an IOP 90 days prior to submitting an EP due to the advanced planning necessary for the operator to safely operate in Arctic conditions and minimize its effects on local communities. In addition, the operator must perform detailed engineering themselves or have a contractor do such work, well in advance of the open-water season. Further, if the operator does not have the general summary information for the IOP, then it is unlikely that the operator will be in a position to submit a completed EP 90 days later.
Another of the commenters requested that BOEM provide notice to the State and local governments when it receives an IOP.
Regarding this request, we note that in addition to posting the IOP online, § 550.206(a)(2) requires the operator to submit eight copies to BOEM for public distribution. BOEM will share copies with State and local governments.
Several commenters requested clarification on whether an operator is obligated to respond to requests for additional information (RFAI) from BOEM, BSEE, or the other agencies with access to the IOP. The commenters note that if operators are obligated to respond to such requests, associated review timings should be established to ensure operators receive feedback within 45 days of submission.
The IOP will be circulated among the members in the E.O. 13580 Alaska Energy Permitting IWG, whose membership and function are discussed in Section I.B, and other relevant agencies. Members of the working group and other agencies will dialogue with the operator about any aspects of the proposed operations that may create risks. This dialogue ensures the operator is aware of elements of its proposed operations requiring clarification or revision to obtain later regulatory approvals in a manner consistent with each agency's regulatory requirements. The IOP is an informational document that must be filed and should cover the identified elements, but does not require approval by DOI. If all elements of § 550.204 are not addressed by the operator in its IOP, BOEM may request supplementation from the operator.
BOEM does not agree that the regulations should be amended to add a 45-day limit for when BOEM's feedback on the IOP should be sent to an operator after the operator has submitted its IOP. If the operator is unable to provide supplementation related to feedback given by BOEM before the end of the IOP review period, the operator would be able to furnish the material in its EP submittal. If, however, during an early point in the review period, BOEM finds that the operator's IOP is incomplete in such a way that it does not address all of the elements of § 550.204, then it may request that the operator supplement the incomplete IOP submission.
One commenter requested clarification of the need for “sufficient information” when submitting the IOP description of vessels utilized in the operator's proposed exploratory drilling program. The commenter understands this as the IOP requirement effectively establishing a 120 day review period for proposed operations (90 days for the IOP and 30 days for the EP). The commenter stated this mandatory IOP process will effectively delay EP submissions and ultimately frustrate future drilling efforts.
BOEM disagrees with the assertion that the IOP will delay the EP process, or that the IOP is designed to effectively expand that process. The final rule is a combination of prescriptive and performance-based requirements developed after extensive outreach to stakeholders, operators, and government agencies. BOEM will review the IOP for completeness, and if the agency finds that aspects of the operator's plan do not meet the necessary information obligations of § 550.204, then it will request the information be presented. The IOP is not subject to approval, and should not delay submission of the EP. Because the IOP is an overview that requires less detail than the EP, operators will be in a position to submit the IOP earlier in their planning process than the EP itself. As a result, the 90-day period will not delay the submittal of the EP.
Three commenters commented on the frequency of IOP submissions. One commenter requested clarification on whether a single IOP could address
multiple EPs. Another commenter requested that BOEM consider a single IOP filed prior to an operator's first EP. The third commenter suggests the IOP be updated when an EP is updated.
BOEM disagrees that an IOP will need to be updated whenever an EP is updated. An IOP is required for each exploratory drilling program planned by an operator. However, a single IOP may cover multiple EPs when sufficient geographic and operational overlap exists. The IOP serves its primary purpose before an EP is submitted, as it informs the early planning process prior to initial EP submission. Requiring the IOP to be updated after the EP's submission would not serve any practical purpose, because the EP serves as the main point of reference for both agencies and the operator after the EP is filed.
One commenter recommended the IOP should mirror the International Association of Oil and Gas Producers (IOGP)/International Petroleum Industry Environmental Conservation Association (IPIECA) guidelines for oil spill risk assessments and management plans.
10
BOEM disagrees with this comment. The IOGP/IPIECA guidelines far exceed the expected scope of the IOP. The IOP is a conceptual document that holistically addresses an operator's Arctic OCS drilling operations from start to finish, providing regulatory agencies a preview of an operator's approach to regulatory compliance and integrated planning. The IOP does provide information on advanced preparations and staging of oil spill response assets, necessary for both BOEM's environmental impact analysis and for BSEE's overall understanding of the operator's OSRP. BOEM does not believe that the final regulations require amendment in response to these comments.
10
The International Association of Oil and Gas Producers (IOGP) is an association, formed in 1974, whose members include public, private, and state-owned oil and gas companies and upstream service companies. The International Petroleum Industry Environmental Conservation Association (IPIECA), formed in 1974, is a global oil and gas association addressing environmental and social issues.
One commenter requested that IOP provisions should require proposed mitigation measures to avoid conflicts with subsistence activities. BOEM does not think this is necessary, as BOEM has determined that existing requirements address this concern. Before an EP is approved, BOEM must comply with applicable statutory requirements to analyze the potential impacts of the proposed exploration activities. As part of the analyses, BOEM analyzes how mobilization, demobilization, and exploratory drilling could affect subsistence use, resource use, and harvest activities. Both BOEM and BSEE may require additional mitigation measures at the EP and APD stages, as necessary, to address appropriately potential interference with subsistence activities. For example, because subsistence hunters are concerned that the effects of offshore oil and gas exploration might displace migrating bowhead whales and other marine mammals (like beluga whales), the Bureaus will meet with the Alaska Eskimo Whaling Commission and its whaling captains to help document traditional knowledge pertaining to bowhead whales, including movement and behavior. Given the importance of subsistence activities and related socio-cultural activities to the Alaska Native communities, operators are encouraged to work directly with interested parties to help mitigate potential impacts to subsistence activities. In addition, BOEM will continue to fund and support studies to better understand the potential impacts from OCS operations on marine mammals and subsistence activities.
One commenter asserted that the proposed rule failed to address public and private investment in on-shore infrastructure supporting oil spill response and protection of specific lands and resources. The commenter noted that the proposed rule neglected local community involvement in oil spill response capabilities, especially at Point Lay, the local community most likely to be impacted by the oil spill response activities. The commenter suggested that regulation be written to specifically require onshore infrastructure development at Point Lay and Cape Sabine, both former Distant Early Warning Line radar sites with existing, but unutilized infrastructure. The commenter shared his Kali traditional knowledge of local meteorological conditions with BOEM and BSEE personnel and has noted that weather conditions often times permit safe flight operations from Point Lay when they are suspended in Barrow and Wainwright.
BOEM has determined that both existing regulations and regulations finalized in this rulemaking address the commenter's concern regarding community involvement. Section 550.202 mandates that operators plan and prepare to conduct their proposed activity safely in conformance with all applicable legal requirements and sound conservation practices in a manner which neither unreasonably interferes with other OCS uses nor causes undue or serious harm to the human, marine or coastal environment. Additionally, § 550.204(j) requires the operator to include in its IOP a description of whether and to what extent a project will rely on local community workforce and spill cleanup response capacity. Regarding the request for specific onshore infrastructure investments, BOEM cannot in this rulemaking specify the location of such investments.
Two commenters assert that introducing an IOP prior to the EP is impractical and unnecessary in terms of timing and objectives. One commenter recommended the submittal of the EP should continue to precede the IOP to allow timely exploration to occur while the IOP is being developed. The commenter argued there is a lack of efficiency in asking operators to prepare a complete IOP as a pre-requisite to engaging in meaningful project-related dialogue and that early engagement between operators and the Federal agencies would be more meaningful as an iterative pre-application process that feeds into the IOP. The second commenter proposes the removal of the IOP as a separate document and that the EP and APD processes are adapted and clarified to meet the intentions of the IOP requirement.
BOEM disagrees and has determined to finalize the IOP provisions as proposed. The IOP requirement calls for information that is different from what is required to be provided in an EP or an APD. Information in an IOP contains a different level of detail and is required at a different point in the planning process. By requiring an IOP, the entire planning process should become more efficient by decreasing the likelihood of requests for additional information or plan modifications during the later stages that require approval. The early engagement facilitated by the IOP requirements of § 550.204 should increase efficiency by improving communication between agencies and operators, improving early agency understanding of and operator preparedness for planning activities.
Appropriateness of IOP Submission
Several commenters assert that the requirement to submit an IOP 90 days before submitting an EP for Arctic exploratory drilling operations is inconsistent with the OCSLA requirements at 43 U.S.C. 1340(c), and the Department is improperly exceeding its jurisdiction by requiring submission of the IOP information. Two of the commenters also assert that the IOP would require reporting of information and data beyond DOI's scope of jurisdiction and is not based in any statutory authority granted by Congress.
BOEM disagrees. The OCSLA requires the submission and approval of an EP, but does not specify or restrict what other information BOEM may require before the EP is submitted. The OCSLA provides the Secretary authority to require information described in the IOP. Section 1334(a) of Title 43 of the U.S.C. grants the Secretary authority to “prescribe and amend such rules and regulations as [s]he determines to be necessary and proper in order to provide for the prevention of waste and conservation of the natural resources of the [OCS].” Section 1332(6) declares that: “operations in the [OCS] should be conducted in a safe manner by well-trained personnel using technology, precautions, and techniques sufficient to prevent or minimize the likelihood of blowouts, loss of well control, fires, spillage, physical obstruction to other users of the waters or subsoil and seabed, or other occurrences which may cause damage to the environment or to property, or endanger life or health.”
11
11
Id.
at section 1332(6).
Section 1348 of Title 43 of the U.S.C. imposes a duty on lessees and operators to “maintain all operations . . . in compliance with regulations intended to protect persons, property, and the environment on the [OCS].”
12
The ability of lessees to explore for oil and gas on the Arctic OCS in accordance with these statutory mandates depends on early, integrated planning. This planning necessarily implicates activities, such as the operation of vessels which are regulated by other Federal agencies but also inform and influence the Department's oversight functions. For example, while the Department does not directly regulate the operations of vessels carrying capping stacks to Arctic well-sites, ice-management vessels or vessels responsible for towing rigs, lessees cannot safely conduct exploratory drilling without properly planning for these activities. Such activities can result in damage to operational equipment critical to DOI-regulated drilling activities, which can in turn compromise, reduce, or force modifications to approved operational or safety capabilities and equipment. Similarly, they can give rise to changes to approved operational schedules, which in the Arctic are particularly critical in light of the limited open water season, the timing of recession and encroachment of sea ice at drill sites, marine mammal migrations, and subsistence hunting seasons, among other considerations.
12
Id.
at section 1348(b)(2).
The EP and the IOP serve different purposes and are not governed by the same provisions of OCSLA. The EP is a statutorily mandated submission under 43 U.S.C. 1340(c), approval of which is required prior to exploration of any OCS lease. BOEM regulations set forth comprehensive and detailed requirements for the contents of an EP.
13
BOEM carefully scrutinizes submitted EPs to ensure that they satisfy all applicable requirements, are consistent with lease terms and governing law, and would not cause serious harm or damage to life, property, any mineral, national security or defense, or the marine coastal or human environment.
14
EPs also provide the basis for analyses and determinations required by other Federal laws, as well as subsequent BSEE review and approval of APDs. Upon satisfaction of all applicable requirements, BOEM approves an EP, often subject to conditions; the terms of that approval are binding and govern activities conducted pursuant to the EP.
13
See
30 CFR 550.211 through 550.228.
14
Id.
at §§ 550.202, 550.233.
The IOP is fundamentally distinct from the EP, and does not implicate the section of OCSLA that governs EPs, 43 U.S.C. 1340. The IOP will be required to be submitted to BOEM well in advance of the EP, at a time when the Department recognizes the operator might not possess the type of detailed and specific information that is required to obtain approval of an EP. It requires Arctic-focused conceptual planning information to encourage and facilitate the development of integrated operational strategies early in the planning process. While the IOP will be reviewed to ensure that the submission is complete, addressing each of the elements listed, the IOP is not subject to approval by any Federal agency and does not bind the operator's future activities. Rather, the IOP, unlike the EP, is designed to be a preliminary informational resource to facilitate relevant Federal agencies' early familiarity with, and opportunities for constructive feedback on, important concepts related to the design of an operator's planned exploration program in an integrated manner that accounts for the unique Arctic OCS conditions. This process has the potential to facilitate the later EP review, but it is fundamentally distinct from the EP itself.
Agency regulations have long recognized the need to obtain through the planning process information about activities outside of the Department's direct regulatory jurisdiction but which are clearly relevant to approval of operations within our jurisdiction.
15
OCSLA provides the Secretary with the authority to require information necessary to ensure that Arctic OCS operations are safe and environmentally responsible and to help facilitate early review by the Department and other agencies in advance of the EP. 43 U.S.C. 1334(a). The IOP requirement reflects a reasonable exercise of that authority.
15
See, e.g.,
§ 550.224 (requiring description in EP of the support vessels, offshore vehicles, and aircrafts you will use to support your exploration activities, including maps of travel routes and methods for transportation of fluids, chemicals, and wastes); § 550.257 (same for Development and Production Plans (DPPs) and Development Operations Coordination Documents (DOCDs)); § 550.225 (requiring description in EP of onshore support facilities to be used to provide supply and service support for the proposed exploration activities); § 550.258 (same for DPPs and DOCDs).
Section 1340(c) of OCSLA requires lessees to submit an EP for approval before they commence exploration pursuant to their lease, and it requires BOEM to take action on an EP within 30 days after submission.
16
The 30-day time limit for reviewing an EP begins only after BOEM's Regional Supervisor deems the EP submitted.
17
This statutorily mandated regulatory requirement is specific to EPs and does not affect the authority in OCSLA to require the preliminary informational submission of the IOP.
16
43 U.S.C. 1340(c).
17
See
30 CFR 550.233.
One commenter argued that industry should not have to incur the additional cost of an IOP considering the roughly 124 day drilling window in the Chukchi Sea, and that the 90 days could instead be spent by agencies to integrate their services for regulatory efficiency. The commenter asserted that agencies must start working together to streamline the regulatory process, to fund and support Arctic-centric science, and to support infrastructure development in this remote region of the country.
We agree with the commenter's concern for agency integration and note the key purpose of the IOP is to facilitate interagency coordination on matters of mutual interest. The regulatory oversight of the Arctic OCS is shared by many agencies and the need for integration among them is recognized by the establishment of the E.O. 13580 Alaska Energy Permitting IWG. The E.O. 13580 Alaska Energy Permitting IWG consists of representatives from Federal agencies which include DOI, the Departments of Defense, Commerce, Agriculture, Energy, Homeland Security, and the EPA. BOEM will circulate the IOP amongst the aforementioned agencies;
such circulation and familiarity will result in a more collaborative effort in regulating OCS oil and gas exploration. With respect to the commenter's concerns regarding timing, the requirement to submit the IOP should not impact the length of the available drilling season as the IOP may be submitted well in advance of the open-water season. With respect to costs, those issues are analyzed at greater length in the final RIA. However, we note here that the type of planning reflected in the IOP is essential for the successful execution of any Arctic OCS exploratory drilling campaign, so the only costs associated with the requirement should be the limited costs of assembling those plans for submission.
How do I submit the IOP, EP, DPP, or DOCD? (§ 550.206)
BOEM proposed to revise § 550.206 to include information that explains how operators should submit their IOPs and allowing operators to request the nondisclosure of information in the IOP using established DOI processes. As is currently the case with EPs, Development and Production Plans (DPPs), and Development Operations Coordination Documents (DOCDs), operators requesting the nondisclosure of portions of an IOP should provide BOEM with two separate versions of the IOP; a public version from which potentially exempt information is redacted, and an agency version with such information present, but clearly marked as proprietary.
Several comments were received on this section. BOEM has evaluated these comments and decided to finalize § 550.206 as proposed. Two commenters requested that BOEM require planning information be submitted electronically to allow immediate availability for public access. This requirement would allow BOEM to immediately upload public-information copies of EPs and IOPs without the intermediate step of reformatting the operator's submissions.
We determined electronic submittal should remain optional. Currently, DOI allows electronic submittals of all or part of the EP and the final rule will allow electronic submission of all or a portion of the IOP. Whether the information is received electronically or in the form of a hardcopy, BOEM will post the appropriate information on
http://www.boem.gov/alaska-region/.
If documents are not received electronically, BOEM will take the necessary steps to convert the files to a format compatible for online viewing by the public.
One commenter recommended that EP requirements be updated to require liaison with DOI as soon as the planning process starts, in order to coordinate forward planning and keep authorities abreast of the approach and milestones related to the EP. The commenter recommended the regulations be revised to require the EP scope be reviewed to ensure that it includes appropriate information requirements related to planning of integrated operations and how this will be achieved. The commenter goes on to recommend that these issues will be discussed as part of the overall EP development process, and that the APD scope be reviewed to ensure that it includes specific requirements for documentation of planned integrated operations, including finalized vessels, contractors and associated management systems. The commenter stated that by establishing such an approach, along the lines of approaches taken by the United Kingdom, Norway, Australia and others, the process for documenting selection and suitability of a rig would be simplified, enabling focus on other risk elements relating to how the unit will be utilized in integrated operations.
BOEM has determined the commenter's recommendations are addressed in the finalized provisions at § 550.204. Compliance with the provisions of § 550.204, related to the submission of the IOP, allows for operators and DOI to coordinate early in the planning process, and allows early visibility and opportunities to address how an operator's activities will be conducted in an integrated manner.
One commenter requested to receive a copy of all Arctic OCS applications and be provided with at least 30 days to review and comment on the applications.
BOEM's existing regulations allow for the public to review and, as appropriate, allow for comment from State, municipal and tribal governments. As stated in the NPRM, BOEM intends to post public versions of IOPs to its Web site upon receipt. Once an EP or DPP is deemed submitted, it is posted on BOEM's Web site,
http://www.boem.gov/alaska-region.
Additionally, § 550.232,
What actions will BOEM take after the EP is deemed submitted?,
allows the Governor of each affected State 21 calendar days to submit comments. During this time, BOEM will make the EP available for public review and comment. Section 550.267,
What actions will BOEM take after the DPP or DOCD is deemed submitted?,
provides that BOEM will make the DPP publicly available within 2 business days of deeming it submitted and accept comments for 60 days after making it available to the public. BOEM has determined these efforts toward public engagement are adequate. BOEM also notes that, particularly with respect to EPs, additional time for public engagement is statutorily constrained.
One commenter recommended that DOI conduct timely and meaningful consultation with Alaska Native tribes before approving an EP. BOEM agrees. Consistent with E.O. 13175 (Consultation and Coordination with Indian Tribal Governments) and Secretarial Order 3317, BOEM requests Government-to-Government consultation with Alaska Native tribes for which the exploration activities could have tribal implications. The Department is committed to fulfilling its tribal consultation obligations, whether directed by statute or administrative action such as E.O. 13175, or other applicable Secretarial orders or policies.
One commenter requested clarification in the final regulations that evidence of equipment ownership or contracts with equipment providers is required only for an APD, but not required for approval of an EP or an OSRP. The commenter expressed concern with having to make commercial commitments to very expensive equipment contracts before getting confirmation from the Bureaus that the plans based on that equipment would be approved. The commenter stated there is sufficient time after EP and OSRP approval for the operator to procure equipment that conforms to the approved plan, and to provide evidence of such procurement at the APD stage.
BOEM does not believe that the final regulations require amendment in response to this comment. Both existing regulations and this final rule require varying levels of information about operator safety and oversight management at progressive stages of the planning and approval process. This information would begin with general information and narrow down to increasing levels of detail with successive regulatory submittals, as the project proceeds from planning to implementation. For example, at the IOP stage, we recognize that operators may not have contracts for vessels finalized or precise dates of drilling so, accordingly, specific names of contractors are not necessary, but could be provided if available. At the EP stage, § 550.220(c) requires, among other planning information, a preliminary general description of SCCE and relief rig capabilities needed for compliance with §§ 250.471 and 250.472. BOEM anticipates that the relief rig description may be general at the EP stage, but
detailed enough for BOEM to confirm that the operator has plans in place for how it would conduct its operations safely and in compliance with the regulations. Further, existing regulation § 550.211(c) requires that a description of the drilling unit and associated equipment be provided in the EP along with a brief description of its safety and pollution prevention features, type of fuel, and an estimate of the maximum quantity of oils, fuels and lubricants. Existing regulation § 550.224(a) also requires at a general level a description of crew boats, supply boats, anchor handling vessels, ice management vessels, aircraft, and other vessels. These longstanding requirements, as supplemented by this rule, lay out a clear picture of the type and level of detail required at different stages of the approval process that is both achievable and appropriate for the management of these operations.
If I propose activities in the Alaska OCS Region, what planning information must accompany the EP? (§ 550.220)
BOEM proposed to revise several of the existing provisions at § 550.220 to ensure, through thorough advanced planning, that operators are capable of operating safely in the extreme and challenging conditions of the Arctic OCS. Revisions to the section include amending the existing “Emergency Plans” provision at § 550.220(a) to add fire, explosion, personnel evacuation, and loss of well control to the events for which emergency plans are required, and to replace the terms “blowout” with “loss of well control” and “craft” with “vessel, offshore vehicle, or aircraft” for clarification purposes. Finally, BOEM proposed creating a new § 550.220(c), which would set forth additional information requirements for EPs that are proposing exploration activities on the Arctic OCS.
Several comments were received on the provisions in this section. BOEM has reviewed the comments and determined to finalize § 550.220 as proposed for the reasons stated herein. One technical revision is finalized at § 550.220(c)(6)(ii). As discussed above in Section IV.A, this revision is required to correctly align the provision with the relief rig planning requirements of § 250.472. For a full discussion of the comment and our response, see the discussion of § 250.472 in Section IV.B.
Two commenters recommend that the end of season date should be decided by the regulators and not by the operators, and also that the operator should only be allowed to drill into hydrocarbon zones with enough time to complete a relief well and remove oil before the freeze-up date. One commenter expressed concern that the operator may overstate their relief well capabilities in order to maximize the length of their drilling season.
BOEM agrees with the commenters. To clarify, the end of season dates that the operator proposes in its EP are anticipated dates. BOEM, in consultation with the NWS, will analyze past and present meteorological conditions, oceanic conditions, and sea ice concentration and movement to determine if the operator has provided an appropriate end of season date estimate to account for its own unique operational capabilities and limits. BOEM does this through the establishment of the trigger date, or estimated seasonal ice encroachment date, that sets a deadline on when the operator can drill or work on the surface casing, so that risks associated with late season drilling are addressed and response and cleanup activities can occur in a timely manner.
Two commenters strongly supported the imposition of an end of season date for operators and request removal of the word “anticipated” in § 550.220(c)(6) to ensure that Arctic OCS operators provide a firm date for their end of seasonal operations to avoid increased risks associated with freeze-up. The commenters further recommended that the final rule provide the Bureaus authority to require operations to terminate before these dates if actual conditions during the drilling season indicate earlier likelihood of ice encroachment over the drill site. The commenters suggest these dates should undergo scientific review by the relevant agencies and should be based on at least ten years of historical ice and weather data.
BOEM disagrees with removing the word “anticipated” from the provisions of § 550.220(c)(6). There are two dates an operator must address in this provision when onsite operations will be complete and when drilling operations will terminate. These dates retain some flexibility at the EP stage, as they are based on a number of predictive factors related to the operator's capabilities to mitigate risk in operating on the Arctic OCS and to the prevailing meteorological and oceanic conditions that vary from year to year. Many of the provisions finalized in this rulemaking require the operator to provide BOEM and BSEE pertinent information that may require exploratory drilling operations to terminate at an earlier date than anticipated at the EP stage. For example, § 250.188 requires the operator to report to BSEE information on various incidents, including sea ice movement that may affect operations or trigger ice management activities and any unexpected “kicks” or operational issues that could result in the loss of well control. We further note the anticipated end of season dates are reviewed through interagency and scientific review prior to an approval of an EP.
Two commenters recommended adding to the final rule a provision requiring operators to develop, as part of the EP, a detailed written Oil Spill Prevention Program that includes a training program. One of the commenters suggest the prevention plan should address critical oil spill prevention programs such as blowout preventer testing, well control, corrosion monitoring and control programs, maintenance and testing of leak detection systems and alarms, and other prevention work.
BOEM and BSEE disagree. Oil spill prevention is a common theme among BOEM and BSEE regulations with the end goal being to prevent serious harm or damage to life, property, any mineral, national security or defense, or the marine, coastal or human environment. As planning is an essential part of spill prevention, the finalized provisions at § 550.220(a) mandate that the operator describe its emergency plans for responding to a variety of incidents, including a loss of well control, at the EP stage. Similar requirements at existing § 550.213(g) require the operator to discuss its worst-case blowout scenario in the EP, including options for response, such as surface intervention and a relief well. Further, existing regulations at § 550.219 mandate that the operator submit an OSRP in accordance with BSEE requirements in part 254, including the training requirements set forth in § 254.29. Accordingly, the Bureaus do not believe that the proposed revisions to § 550.220 are necessary or appropriate.
One commenter recommended deleting § 550.220(a) as existing regulations require a description of plans in the event of a loss of well control, the loss or disablement of a drilling unit, and the loss or damage to support craft, and the proposed language requires information concerning emergency plans in the event of `fire, explosion, or personnel evacuation'. The commenter explains that this information is currently captured by Emergency Evacuation Plans drafted for each of its drilling units and submitted to the U.S. Coast Guard (USCG) pursuant to 33 CFR 146.210. The commenter requested
BOEM incorporate these documents by reference and not require the information to be submitted multiple times across agencies.
BOEM disagrees. Drilling operations, especially in the Arctic OCS, are subject to operational risks and environmental challenges during every phase of the endeavor. For the most part, the text of § 550.220(a) remains unchanged from longstanding requirements. To the extent that operators have compiled the relevant information for other purposes, the burdens of providing them for the EP are minimal and may potentially be addressed through reference on a case by case basis.
One commenter stated the information requested in § 550.220(c)(1) is unnecessary and repetitive, as existing § 550.211 already requires a detailed description of drilling activities and this same information is also requested as part of the IOP under § 550.204.
BOEM disagrees that § 550.220(c)(1) is unnecessary and repetitive, as existing § 550.211 sets forth general requirements for what must be included with an operator's EP anywhere on the OCS. Because of the unique operating environment of the Arctic OCS, proposed activities in this region are subject to additional levels of scrutiny and specialized requirements. Section 550.220(c)(1) is addressed directly to that need, calling for descriptions of the suitability of proposed operations for Arctic OCS conditions, in contrast to the more generic requirements of § 550.211. Additionally, as explained in previous responses to comments, the operator's plans furnished with the IOP are less detailed than the information later available and required for submission with the EP, providing an opportunity for elaboration based on new information as it comes available.
One commenter is supportive of resource sharing with other operators, provided that appropriate terms and agreements can be made. However, the commenter asserted the requirement to share these proprietary private-party agreements under § 550.220(c)(5) is not appropriate and opposes the attempt to regulate what resources will be shared and with whom. The commenter asserted that involvement in any resource sharing agreements will not affect the operator's ability to meet the regulatory requirements regarding oil spills and emergency planning.
BOEM disagrees with the commenter's characterization of the regulation and clarifies that § 550.220(c)(5) is not an attempt to mandate resource sharing by regulation. Instead, this is a requirement to inform BOEM about any agreement the operator may have with a third party for sharing of assets or provisions for mutual aid in the event of an oil spill, as applicable, so regulators are aware of what response resources are available to an operator in the event of a loss of well control. This information is critical to ensure that the operator has made the necessary arrangements to respond appropriately in the event of a loss of well control incident. This information is also critical to confirm the operator's compliance with the relevant regulatory requirements related to well control equipment. To the extent that operators rely on such arrangements to satisfy their regulatory obligations, it is essential for the Bureaus to have access to the terms and conditions of those arrangements to confirm compliance. Additionally, the operator is required under this final rule at § 250.470(f)(1) and (3) to demonstrate at the APD stage that its membership agreements with cooperatives, service providers or other contractors include 24-hour per day availability of SCCE or related supplies while it is drilling or working below the surface casing. The operator is also required to describe its or its contractor's ability to access or deploy all necessary SCCE in accordance with § 250.471 and the SCCE listed in its EP. It is the operator's responsibility to ensure that reliance on resource sharing arrangements does not compromise its ability to fully and promptly respond to an event, and the required information is important to the bureaus' ability to ensure that this is addressed. We note that proprietary information is protected in accordance with existing §§ 250.197 and 550.197,
Data and information to be made available to the public or for limited inspection.
One commenter asserted that the anticipated end of season dates as described in § 550.220(c)(6) should not be driven by a specific calendar date, but by the application of performance-based principles including the ability of the operator's equipment, procedures, and expertise to effectively manage and mitigate risks that are reasonably likely to occur.
BOEM notes that the end of season dates discussed in the final rule at § 550.220(c)(6) are developed largely based on the capability of the operator's equipment and procedures to manage and mitigate risks associated with Arctic OCS conditions. Any date established depends on a number of factors, including a trigger date set by the Bureaus based on an evaluation of earliest sea ice encroachment, the latest ice and weather forecasts, the prevailing meteorological and oceanic conditions, and the timeframe in which an operator could drill a relief well. The specific calendar date is calculated using a performance-based metric, allowing for the operator to apply its capabilities and expertise in reaching a specific date, as approved by the Bureaus.
One commenter recommended deleting the entirety of § 550.220(a), (c)(3), and (c)(4) and replacing them with more performance-based requirements. Specifically, the commenter suggests that the EP be required to contain general planning information on source control and containment capabilities, including anticipated location and mobilization/demobilization times of equipment to mitigate risk from a loss of well control incident.
BOEM disagrees and is finalizing these sections as proposed. One of the main goals of this rulemaking is to help ensure, through advanced planning, that operators are capable of operating safely in the extreme and challenging Arctic OCS conditions. This rulemaking amends existing § 550.220(a) to add fire, explosion, and personnel evacuation to the events for which emergency plans are required and to replace the terms “blowout” with “loss of well control” and “craft” with “vessel, offshore vehicle, or aircraft” for clarification purposes. Paragraph (a) of § 550.220 otherwise remains unchanged from its longstanding form, and keeps the development of emergency plans largely within the performance-based control of the operator. Paragraphs (c)(3) and (4) of § 550.220 simply require the operator to provide a general description in its EP of how it plans to satisfy the separate operational requirements imposed by BSEE at §§ 250.471 and 250.472. While the operator has flexibility in determining how it will comply with those requirements, making the required EP description of the operator's compliance plans more general or performance-based would be unnecessary and inappropriate, and would not satisfy the Bureaus' need to ensure appropriate planning for compliance with the regulations.
One commenter requested that the requirement to provide some data for the APD be accelerated to the EP, including more information to account for operations in Arctic OCS conditions; more detail on emergency and critical operation curtailment plans; a detailed description of how the drilling rig, relief well rig, SCCE, support vessels and other associated support equipment and activities will be designed and conducted in a manner that accounts for Arctic OCS conditions; and information regarding operators' capabilities for
preventing, controlling and/or containing a WCD. The commenter also recommended the IOP be included in the EP application as an appendix and be subject to public review and comment.
Both existing regulations and the regulations finalized in this rulemaking require varying levels of information at progressive stages of the planning and approval process. Furthermore, this final rule contains a combination of prescriptive and performance-based requirements that address a number of important issues. The required submissions begin with general information and are followed by more specificity with successive regulatory submittals, as the project proceeds from planning to implementation. The IOP is an overarching, high-level description of the integration of the exploration activities that provides an advanced summary of all phases of the proposed operations for the relevant Federal agencies to review and is designed to enable Federal agencies to identify possible vulnerabilities early in planning, and to facilitate interagency communication and discussion about possible permitting issues before submission of the EP. At the IOP stage, operators may not have contracts for vessels finalized or precise dates of drilling, accordingly, specific names of contractors are not necessary, but could be provided. At the EP stage the operator must provide a general description of its SCCE capabilities and relief rig plans, in accordance with § 550.220(c), conforming to §§ 250.471 and 250.472. BOEM anticipates that the relief rig description may still be general at the EP stage, but will be detailed enough for BOEM to confirm that the operator has plans in place for how it will conduct operations safely in compliance with the regulations. Existing § 550.213(g) also requires that an EP include a blowout scenario addressing matters including surface intervention and relief well capabilities. Section 550.220(c)(1) requires the EP to provide a description of how an operator will design and conduct the proposed activities in a manner that accounts for Arctic OCS conditions; including a description of how the operator will manage and oversee those activities as an integrated endeavor. Additionally, § 550.220(a) requires that the operator submit a description of emergency plans describing the operator's ability to respond to a fire, explosion, personnel evacuation, or loss of well control, as well as a loss or disablement of a drilling unit, and loss of or damage to a support vessel, offshore vehicle, or aircraft with the EP. These new and existing provisions provide for the appropriate level of detail regarding an operator's plans at successive stages of the approval process. In response to the comment recommending that the IOP be included as an appendix to the EP application, BOEM will have received the operator's IOP at a minimum of 90 days before the EP submittal; therefore it is optional for the operator to include the IOP as an appendix in the EP. In response to the commenter's recommendation of having the public review and comment on the IOP, BOEM will post public versions of the operator's IOP to its Web site when received.
One commenter suggested requiring that drilling rigs not previously used in frontier areas, such as the Arctic OCS, undergo a mandatory third-party review of the unit's design and that such review be submitted as part of the EP application.
BOEM does not believe that the final regulations require amendment in response to this comment. The information provided with the operator's EP is general by necessity; more detailed information becomes available as the operator progresses through the planning process. In accordance with existing § 550.211(c), the EP must include a description of the drilling unit. Later in the planning process at the APD stage, under finalized § 250.470, BSEE requires the operator to submit specific information on the drilling unit. This includes information required in finalized paragraphs (a)(2) and (g) of § 250.470, such as detailed descriptions of how the drilling unit will be prepared for service on the Arctic OCS and how the operator will comply with the requirements of API RP 2N,
Recommended Practice for Planning, Designing, and Constructing Structures and Pipelines for Arctic Conditions,
Third Edition. The finalized requirements at § 250.473(a) mandate that all operators operating on the Arctic OCS use only equipment or materials that are rated or de-rated for service conditions that can be reasonably expected during operations.
Additionally, the operator's SEMS and the accompanying audit performed by a third-party must address the mechanical integrity of critical equipment. The revised requirements at § 250.1920(b)(5) will require Arctic OCS operators to increase their SEMS auditing frequency from every three years after the initial audit to every year in which drilling in the Arctic is conducted. Existing § 250.1920 requires that a third party Audit Service Provider accredited by a BSEE-approved accreditation body perform the audit. Accordingly, the proposed revisions are not necessary.
Two commenters recommend expanding the EP to address additional information including: Evidence that the operator consulted with marine mammal co-management organizations; a description of steps the operator will take to mitigate subsistence impacts, the establishment of appropriate start and stop timing for operations to minimize any potential conflict with subsistence activities, and an approved Conflict Avoidance Agreement (CAA) between the operator and the Alaska Eskimo Whaling Commission (AEWC). One of the commenters further recommended if a CAA is not included, then the EP should include an explanation as to the consultation process.
BOEM appreciates the commenter's concern for mitigating subsistence impacts and does not believe that the final regulations require amendment in response to this comment. For example, § 550.227 requires the operator to, among other things, assess the potential impacts of its proposed exploration activities, describe resources, conditions, and activities that could be affected by exploration operations (including impacts to marine mammals and subsistence and harvest practices), and list the agencies and persons that it consulted with regarding potential impacts associated with proposed exploration activities. Section 550.204(i) requires a description of the operator's efforts to minimize impacts on local community infrastructure. BOEM will also analyze subsistence impacts through its NEPA analyses.
With regard to the CAA processes, BOEM's Alaska OCS Region has regularly noted their positive value in public forums. The CAA is an agreement between AEWC and the operator and is considered a private agreement. As such, it is outside the scope of these regulations to require an operator to obtain a CAA from another entity. Although there is not a requirement for a CAA, discussion of resolutions during the consultation process and plans for continued consultation are required to be included in the EP. BOEM and BSEE continue to be committed to engaging on a routine basis with the AEWC. The AEWC leaders and members bring unmatched perspectives and insights into the relationships that BOEM and BSEE seek to maintain. With respect to the commenters suggestion that the operator be required to include evidence that the operator consulted with marine mammal co-management organizations, § 550.222 addresses the commenters
concerns. Section 550.222 requires the operator to include in its EP a description of the measures it took, or will take, to satisfy conditions of lease stipulations related to its proposed exploration activities. Because a lease stipulation can be formulated in collaboration with a co-management organization at the lease sale stage, evidence of how the operator satisfied the conditions of the lease sale stipulation must be included in the EP.
4. Additional Regulations by BSEE
What incidents must I report to BSEE and when must I report them? (§ 250.188)
The existing regulations at § 250.188 require operators to provide oral and written notification to the BSEE District Manager (who in the Alaska OCS region is the Regional Supervisor) of, among other things, any injuries, fatalities, losses of well control, fires and explosions, and incidents affecting operations. BSEE proposed to add a new paragraph (c) to this section requiring operators on the Arctic OCS to provide an immediate oral report to the BSEE onsite inspector, if one is present, or to the Regional Supervisor, of any sea ice movement or condition that has the potential to affect operations or trigger ice management activities, as well as to report the start and termination of these activities, and any “kicks” or operational issues that are unexpected and could result in the loss of well control. The new provision would likewise require a written report of ice management activities within 24 hours of their completion.
Several comments were received on this section. BSEE has evaluated these comments and decided to finalize § 250.188(c) as proposed. We have separated comments received on this section into two topics: (i) Comments on ice management reporting, and (ii) comments on reporting of kicks or operational issues that are unexpected and could result in the loss of well control.
Ice Management Reporting
Two commenters assert that the ice management reporting requirements are too subjective and vague, and that the reporting should be limited to ice incursion incidents that affect operations or trigger ice management activities as stated in the ice management plan. One of these commenters further asserted that the requirement would necessitate nearly constant communication with BSEE regarding sea ice movement and conditions, and requested that BSEE allow 24 hours to report the incident so the operator is able to focus on a safe response to the incident before contacting the regulator.
BSEE disagrees with these comments. The ice management reporting requirements of this provision require operators to remain in close communication with BSEE about sea ice conditions that have the potential to affect operations before they reach the point of triggering ice management activities as stated in the ice management plan. This requirement does not necessitate constant communication, as the reporting requirements are limited to sea ice movements or conditions that have the potential to affect operations or trigger ice management activities. Just as the operator needs to have sufficient time to plan and act in the event that ice poses an operational hazard, BSEE would need sufficient time to oversee the safety of an operator's reactions and prepare to respond, if a response is necessary, due to a safety or environmental incident resulting from an ice event. BSEE does not agree that the identified standard is vague or ambiguous, and is confident, including based upon recent experience in 2012 and 2015, that Arctic OCS operators will be able to implement the provision in practice, and in coordination with the BSEE inspector or Regional Supervisor.
The requirement to notify the BSEE inspector on location or the Regional Supervisor of sea ice movement or conditions that have the potential to affect an operation or trigger ice management activities is important and appropriate. BSEE agrees with the commenter's statement that the operator should focus on a safe response to an active incident, but we disagree with the commenter's request to allow 24 hours to report an incident. The requirement for an immediate oral report is satisfied by notifying the onsite inspector or BSEE Regional Supervisor when an event or potential event is recognized. Requiring an immediate oral report is reasonable and likely will not burden the operator. This requirement will ensure that BSEE is informed of ice management concerns but will allow the operator to focus on executing safe ice management operations. Consistent with the prioritization of safe ice management operations, the regulation allows 24 hours for the written report to be completed.
One commenter questioned the suitability of § 250.190,
Reporting requirements for incidents requiring written notification,
for use with the ice management reporting required by proposed § 250.188(c)(2), particularly in the case where there is no damage or injury. BSEE determined the information requested in § 250.190 is generally appropriate for these purposes, as all the information required may be relevant to reporting ice management activities in certain circumstances. The person completing the report has the option to state that specific information is not applicable (
e.g.,
no damage or injury occurred).
Two commenters suggested the ice monitoring requirement should be implemented to focus on the operators specifying reporting requirements in advance, based on the risks of a particular location, and these risks should be included in the ice management plan.
BSEE agrees in part. The operator is responsible for addressing the particular ice event, based on the ice management plan submitted to BOEM under § 550.220(c)(2). The operator's ice management plan should address how the operator will respond to and manage ice hazards, its ice alert procedures, and the procedures and thresholds for activating the ice management system. This ice management plan is required as part of the EP, which BOEM reviews to ensure the plan addresses all of BOEM's requirements. However, BSEE also believes that it is necessary and appropriate to establish baseline reporting requirements, not subject to individual operator plan specifications, to enable the agency to perform its necessary oversight functions, and therefore that no revision to the rule is needed in response to the comment.
One commenter proposes revising § 250.188(c)(1)(i) by deleting the requirement to report any sea ice movement or condition that has the potential to trigger ice management activities. The commenter suggests that compliance with these requirements would be achieved by including BSEE on the notification list used when an ice alert code is changed. BSEE does not agree that § 250.188(c)(1)(i) needs to be revised. The language of that provision makes it clear when the operator needs to notify BSEE. The commenter's suggested revision would
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