[Federal Register Volume 80, Number 36 (Tuesday, February 24, 2015)]
[Proposed Rules]
[Pages 9916-9971]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2015-03609]
[[Page 9915]]
Vol. 80
Tuesday,
No. 36
February 24, 2015
Part III
Department of the Interior
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Bureau of Safety and Environmental Enforcement
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30 CFR Parts 250 and 254
Bureau of Ocean Energy Management
30 CFR Part 550
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Oil and Gas and Sulphur Operations on the Outer Continental Shelf--
Requirements for Exploratory Drilling on the Arctic Outer Continental
Shelf; Proposed Rule
Federal Register / Vol. 80 , No. 36 / Tuesday, February 24, 2015 /
Proposed Rules
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DEPARTMENT OF THE INTERIOR
Bureau of Safety and Environmental Enforcement
30 CFR Parts 250 and 254
Bureau of Ocean Energy Management
30 CFR Part 550
[Docket ID: BSEE-2013-0011; 15XE1700DX EX1SF0000.DAQ000 EEEE500000]
RIN 1082-AA00
Oil and Gas and Sulphur 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: Proposed rule.
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SUMMARY: The Department of the Interior (DOI), acting through BOEM and
BSEE, proposes to revise and add new requirements to regulations for
exploratory drilling and related operations on the Outer Continental
Shelf (OCS) seaward of the State of Alaska (Alaska OCS). The Alaska OCS
has the potential to be an integral part of the Nation's ``all of the
above'' domestic energy strategy. This proposed 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. The proposed rule is designed
to ensure 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: Submit comments by April 27, 2015. BOEM and BSEE may not fully
consider comments received after this date. You may submit comments to
the Office of Management and Budget (OMB) on the information collection
burden in this proposed rule by March 26, 2015. The deadline for
comments on the information collection burden does not affect the
deadline for the public to comment to BOEM and BSEE on the proposed
regulations.
ADDRESSES: You may submit comments on the rulemaking by any of the
following methods. For comments on this proposed rule, please use
Regulation Identifier Number (RIN) 1082-AA00 in your message. For
comments specifically related to the draft Environmental Assessment
conducted under the National Environmental Policy Act of 1969 (NEPA),
please refer to NEPA in the heading of your message. See also, Public
Availability of Comments under Procedural Matters.
Federal eRulemaking Portal: http://www.regulations.gov. In
the Search box, enter BSEE-2013-0011, then click search. Follow the
instructions to submit public comments and view supporting and related
materials available for this rulemaking. BOEM and BSEE will post all
submitted comments.
Mail or hand-carry comments to the DOI, BSEE: Attention:
Regulations and Standards Branch, 381 Elden Street, HE3314, Herndon,
Virginia 20170-4817. Please reference ``Oil and Gas and Sulphur
Operations on the Outer Continental Shelf--Requirements for Exploratory
Drilling on the Arctic Outer Continental Shelf,'' 1082-AA00 in your
comments, and include your name and return address.
Send comments on the information collection of this rule
to: Interior Desk Officer 1082-AA00, Office of Management and Budget;
202-395-5806 (fax); email: [email protected]. Please also
send copies to BSEE by one of the means previously described.
FOR FURTHER INFORMATION CONTACT: Mark E. Fesmire, BSEE, Alaska Regional
Office, [email protected], (907) 334-5300; John Caplis, BSEE, Oil
Spill Response Division, [email protected], (703) 787-1364; or David
Johnston, BOEM, Alaska Regional Office, [email protected], (907)
334-5200. To see a copy of either information collection request
submitted to OMB, go to http://www.reginfo.gov (select Information
Collection Review, Currently Under Review).
SUPPLEMENTARY INFORMATION:
Executive Summary
Although there is currently a comprehensive OCS oil and gas
regulatory program, DOI engagement with stakeholders reveals the need
for new and revised regulatory measures for exploratory drilling
conducted by floating drilling vessels and ``jackup rigs''
(collectively known as mobile offshore drilling units or MODUs) on the
Arctic OCS. The United States (U.S.) Arctic region, as recognized by
the U.S. and defined in the U.S. Arctic Research and Policy Act of
1984, encompasses an extensive marine and terrestrial area, but this
proposed rule focuses solely on the OCS within the Beaufort Sea and
Chukchi Sea Planning Areas.
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, reinforce the need to develop additional measures
specifically tailored to the operational and environmental conditions
of the Arctic OCS. After considering the input provided by various
stakeholders and DOI's direct experience from Shell's 2012 Arctic
operations, BOEM and BSEE have concluded that additional exploratory
drilling regulations would enhance existing regulations and would be
appropriate for a more holistic Arctic OCS oil and gas regulatory
framework.
This proposed rulemaking is intended to provide regulations to
ensure Arctic OCS exploratory drilling operations are conducted in a
safe and responsible manner that would take into account the unique
conditions of Arctic OCS drilling and Alaska Natives' cultural
traditions and need to access subsistence resources. The Arctic region
is known for its oil and gas resource potential, its vibrant
ecosystems, and the Alaska Native communities, who rely on the Arctic's
resources for subsistence 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 proposed rule would add to, and revise existing regulations
in, 30 CFR parts 250, 254, and 550 for Arctic OCS oil and gas
activities. The proposed rule would focus on Arctic OCS exploratory
drilling activities that use MODUs and related operations during the
Arctic OCS open-water drilling season. This proposed rule would address
a number of important issues and objectives, including ensuring that
each operator:
1. Designs and conducts exploration programs in a manner suitable
for Arctic OCS conditions;
2. Develops an integrated operations plan (IOP) that would address
all phases of its proposed Arctic OCS exploration program and submit
the IOP to DOI, acting through its designee, BOEM, at least 90 days in
advance of filing the 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;
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4. Has access to a separate relief rig located so that it could
timely drill a relief well in the event of a loss of well control under
the conditions expected at the site;
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 suitable for the unique Arctic OCS
operating environment and has the necessary equipment, training, and
personnel for oil spill response on the Arctic OCS.
The proposed rule would further the Nation's interest in exploring
frontier areas, such as those in the Arctic region, and would establish
specific operating models and requirements for the extreme, changing
conditions that exist on the Arctic OCS. The proposed regulations would
require comprehensive planning of operations, especially for emergency
response and safety systems. The proposed rule would seek to
institutionalize a proactive approach to offshore safety. A goal of the
proposed rule is to identify possible vulnerabilities early in the
planning process so that corrections could be made in order to decrease
the possibility of an incident occurring. The requirements in the
proposed rule are also designed to ensure that those plans would be
executed in a safe and environmentally protective manner despite the
challenges presented by the Arctic.
Table of Contents
List of Acronyms and References
I. Introduction
A. Resource Potential
B. Integrated Arctic Management
C. Overview of Proposed Regulations
D. Potential Costs and Benefits of Proposed Rule
II. Background
A. Statutory and Regulatory Overview
B. Factual Overview of the Alaska OCS Region
C. Partner and Stakeholder Engagement in Preparation for This
Proposed Rule
D. Expected Benefits Justifying Potential Costs
III. Proposed Regulations for Arctic OCS Exploratory Drilling
A. Measures That Address Recommendations
B. IOP Requirement
C. SCCE and Relief Rig Capabilities
D. Planning for the Variability and Challenges of the Arctic OCS
Conditions
E. Arctic OCS Oil Spill Response Preparedness
F. Reducing Pollution From Arctic OCS Exploratory Drilling
Operations
G. Oversight, Management, and Accountability of Operations and
Contractor Support
IV. Section-By-Section Discussion
A. Definitions (Sec. Sec. 250.105, 254.6, and 550.105)
B. Additional Regulations Proposed by BOEM
C. Additional Regulations Proposed by BSEE
D. Arctic Exploratory Drilling Process Flowchart
V. Conclusion
VI. 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
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 Regulations
P. Public Availability of Comments
List of Acronyms and References
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Report to the Secretary
of the Interior, review
60-Day report of Shell's 2012 Alaska MODU Mobile offshore
offshore oil and gas drilling units
exploration program
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AIS.................................. Automatic NARA................... National Archives and
Identification System. Records
Administration.
Alaska OCS........................... OCS Seaward of the National Arctic President's National
State of Alaska. Strategy. Strategy for the
Arctic Region issued
May 2013.
ANCSA................................ Alaska Native Claims NEPA................... National Environmental
Settlement Act. Policy Act of 1969.
APD.................................. Application for Permit NOAA................... National Oceanic and
to Drill. Atmosphere
Administration.
API.................................. American Petroleum NPDES.................. National Pollutant
Institute. Discharge Elimination
System.
APM.................................. Application for Permit OCS.................... Outer Continental
to Modify. Shelf.
Arctic OCS........................... OCS within the Beaufort OCSLA.................. Outer Continental Shelf
Sea and Chukchi Sea Lands Act.
Planning Areas.
ASP.................................. Audit Service Provider. OMB.................... Office of Management
and Budget.
BOEM................................. Bureau of Ocean Energy OPA.................... Oil Pollution Act of
Management. 1990.
BOP.................................. Blowout Preventer...... OSRP................... Oil Spill Response
Plan.
BP................................... BP Exploration PPCS................... Pre-Positioned Capping
(Alaska), Inc.. Stack.
BSEE................................. Bureau of Safety and PRA.................... Paperwork Reduction
Environmental Act.
Enforcement.
CAP.................................. Corrective Action Plan. RFA.................... Regulatory Flexibility
Act.
CFR.................................. Code of Federal RIA.................... Regulatory Impact
Regulations. Analysis.
CWA.................................. Clean Water Act........ RIN.................... Regulation Identifier
Number.
DOCD................................. Development Operations ROV.................... Remotely Operated
Coordination Documents. Vehicle.
DOI.................................. Department of the RP..................... Recommended Practice.
Interior.
DPP.................................. Development and SCCE................... Source Control and
Production Plans. Containment Equipment.
EA................................... Environmental Secretary.............. Secretary of the
Assessment. Interior.
E.O.................................. Executive Order........ SEMS................... Safety and
Environmental
Management Systems.
EP................................... Exploration Plan....... SIDs................... Shut-in Devices.
EPA.................................. Environmental UMRA................... Unfunded Mandates
Protection Agency. Reform Act of 1995.
ESA.................................. Endangered Species Act. U.S.................... United States.
IC................................... Information Collection. USCG................... U.S. Coast Guard.
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ICAS................................. Inupiat Community of USFWS.................. U.S. Fish and Wildlife
the Arctic Slope. Service.
Initial RIA.......................... Initial Regulatory WCD.................... Worst-Case Discharge.
Impact Analysis.
IOP.................................. Integrated Operations Working Group.......... Interagency Working
Plan. Group on Coordination
of Domestic Energy
Development and
Permitting in Alaska.
ISO.................................. International
Organization for
Standardization.
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I. Introduction
The Arctic region is known for its oil and gas resource potential,
its thriving and diverse ecosystems, and the Alaska Native communities
who rely on the Arctic's resources for subsistence and cultural
traditions. The Arctic region is also 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.
In May 2013, President Obama issued a document entitled, ``National
Strategy for the Arctic Region (National Arctic Strategy).'' 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.''
In keeping with the Nation's comprehensive ``all of the above''
energy strategy to continue to expand safe and responsible domestic
energy production, the National Arctic Strategy 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 National Arctic Strategy emphasizes the need for
integrated and balanced management techniques.
Furthermore, the National Arctic Strategy 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 National Arctic Strategy is to ``reduce the
risk of marine oil pollution while increasing global capabilities for
preparedness and response to oil pollution incidents in the Arctic.''
(http://www.whitehouse.gov/sites/default/files/docs/implementation_plan_for_the_national_strategy_for_the_arctic_region_-_fi....pdf). The National Arctic Strategy 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: www.arctic-council.org/eppr/agreement-on-cooperation-on-marine-oil-pollution-preparedness-and-response-in-the-arctic/).
A. Resource Potential
The Alaska OCS region is estimated to contain a vast amount of
undiscovered, technically recoverable oil and gas. According to BOEM's
2011 Assessment of Undiscovered Technically Recoverable Oil and Gas
Resources of the Nation's Outer Continental Shelf (mean estimates
available at: www.boem.gov/Oil-and-Gas-Energy-Program/Resource-Evaluation/Resource-Assessment/2011_National_Assessment_Factsheet-pdf.aspx), 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 Beaufort Sea and Chukchi Sea Planning
Areas combined. Most of the Alaska OCS resource potential is located
off the Arctic coast within the Chukchi Sea and Beaufort Sea Planning
Areas. This resource potential has received considerable attention from
the oil and gas industry and the U.S. government, and has precipitated
the sale of hundreds of leases and the initiation of subsequent
exploration activities. The Alaska OCS region, particularly the
Beaufort Sea and Chukchi Sea Planning Areas, has the potential to be an
integral part of the ``all of the above'' domestic energy strategy
articulated in the National Arctic Strategy.
B. Integrated Arctic Management
As ocean and seasonal conditions continue to change in the Arctic,
there will be an increasing number of stakeholders vying for access to
the Arctic OCS and the waters above it. Both commercial and
recreational activities are increasing as more areas of water open up
for longer periods of time due to the increase of melting 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
proposing 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 maintained 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 cautiously to ensure that laws, regulations, and
policies concerning Arctic OCS oil and gas development are created and
implemented based on a thorough examination of the multiple factors at
play in the unique Arctic environment. BOEM and BSEE have conducted
extensive research on potential oil and gas activities in the Arctic
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
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OCS oil and gas development, all of which have guided this proposed
rule.
Coordinating the future uses of the Arctic region will require
integrated action between and among Federal, state, and tribal
governmental entities. On July 15, 2011, President Obama signed
Executive Order (E.O.) 13580, establishing an Interagency Working Group
on Coordination of Domestic Energy Development and Permitting in Alaska
(Working Group), chaired by the Deputy Secretary of DOI. The Working
Group is composed of representatives from the DOI, Department of
Defense, Department of Commerce, Department of Agriculture, Department
of Energy, Department of Homeland Security, the Environmental
Protection Agency (EPA), and the Office of the Federal Coordinator for
Alaska Natural Gas Transportation Projects. 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).
The Working Group was involved in coordinating Federal regulatory
and oversight efforts for the 2012 Alaska OCS drilling season and
played an important role in BOEM's and BSEE's reviews of plans and
permits for Shell's 2012 operations. The Working Group's report
entitled, ``Managing for the Future in a Rapidly Changing Arctic, A
Report to the President'' (March 2013), was the result of substantial
collaboration and has also played a significant role in shaping U.S.
Arctic policies.
C. Overview of Proposed Regulations
Although there is currently a comprehensive OCS oil and gas
regulatory program, DOI engagement with partners and stakeholders \1\
reveals the need for new and enhanced regulatory measures for Arctic
OCS exploratory drilling by MODUs. For purposes of this rulemaking,
exploratory drilling is considered to be ``[a]ny drilling conducted for
the purpose of searching for commercial quantities of oil, gas, and
sulphur, 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'' (30 CFR 250.105 and 30 CFR
550.105 (one of the definitions of ``exploration'')).\2\ This proposed
rule focuses on Arctic OCS exploratory drilling activities that use
MODUs (e.g., jack-ups and anchored drillships) and related operations
during the Arctic open-water drilling season (generally late June to
early November). After the requirements for exploratory drilling are
finalized and applied to those activities, DOI will be able to assess
whether it should apply similar requirements to development drilling.
BOEM and BSEE will then be in a position to consider developing
requirements appropriate for development drilling activities and
publish a rulemaking for public notice and comment in the Federal
Register. The requirements may be the same as the final requirements
for exploratory drilling, or BOEM and BSEE may modify these
requirements.
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\1\ Tribes, State and local governments, and Federal agencies
are ``partners.'' ``Stakeholders'' are non-governmental
organizations, industry, and other entities.
\2\ This proposed 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 proposed rule are
intended to apply only to the BSEE and BOEM regulatory programs
covered by this proposed rule, unless otherwise noted.
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The Arctic region is known for its challenging environmental
conditions, geographic remoteness, and relative lack of existing
infrastructure. This proposed rule builds on and would codify input
received from partners and stakeholders, key components of Shell's 2012
Arctic exploratory drilling program, as well as the additional measures
DOI required to ensure Shell's drilling operations were conducted
safely.
Though its actual drilling operations were conducted without
incident, Shell experienced a number of challenges during its 2012
exploratory drilling program. In 2013, DOI released 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 continue to be carried out in a safe and responsible manner.
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, reinforce 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. Experience gained during the 2012 Arctic
drilling season has led BOEM and BSEE staff to conclude that enhanced
and more specific requirements can help ensure that oil and gas
activities in the Arctic OCS are conducted in a safe and
environmentally responsible manner. After considering the input
provided by various stakeholders and DOI's direct experience from
Shell's 2012 Arctic operations, BOEM and BSEE have concluded that
additional exploratory drilling regulations are necessary and
appropriate as a part of the Arctic OCS oil and gas regulatory
framework.
This proposed 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 suitable 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 would address all phases of their proposed
Arctic OCS exploration program and submit the IOP to DOI, acting
through its designee, BOEM, at least 90 days in advance of filing the
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 so that it could
timely drill a relief well in the event of a loss of well control 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 and executed in a
manner suitable 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. Potential Costs and Benefits of Proposed Rule
The Initial Regulatory Impact Analysis (RIA) for this proposed rule
estimates that, if implemented as proposed, the new regulations would
result in economic costs ranging from $1.1 to 1.2 billion (at discount
rates of 7 percent and 3 percent, respectively) over 10 years. The
above estimated cost range reflects the increase in costs over
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the baseline costs. As discussed in part VI.B.3, the baseline is
calculated by estimating the costs associated with current regulatory
requirements and industry standards. In general, this includes the
requirements imposed by DOI during the 2012 drilling season. However,
even though DOI required the availability of a relief rig in 2012, we
have conservatively chosen not to include the costs of staging a
standby relief rig in the baseline. Although BOEM and BSEE expect that
over time, as the number of operating rigs on the Arctic OCS increases,
operators will use a second operating rig as a relief rig, in lieu of a
dedicated standby relief rig, we have included the capital and activity
costs for a standby rig for the first two years (2015-2016) of the 10-
year time period in the economic costs of the proposed rule.
While the economic and other benefits of the proposed 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 proposal.
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 economic and environmental results when
they occur. The benefits of the proposed rule include reducing such
risks associated with Arctic offshore operations.
Reducing the risks of Arctic offshore operations is particularly
important because of the unique significance to Alaska Natives of the
fish and marine mammals in the lands and waters around the Arctic OCS;
those resources are critical components of the Alaska Natives'
livelihood, and they rely on fishing and hunting for traditional
cultural purposes and for subsistence. Similarly, many other Americans
place a very high value on protecting the health of the ecosystem,
including the sensitive environment and wildlife, of this largely
frontier area. 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 proposed requirements--specifically tailored to the Arctic
OCS--would provide additional specificity regarding BOEM's and BSEE's
expectations for safe and responsible development of Arctic resources
and would outline the particular actions that lessees, owners and
operators must take in order to meet those expectations. BSEE and BOEM
do not anticipate that these proposed requirements, or their associated
costs, would prevent lessees and operators from conducting exploratory
drilling on their leases. In fact, the additional clarity and
specificity provided by the proposed rule should help the oil and gas
industry to plan better and to more effectively conduct exploratory
drilling on the Arctic OCS, which in turn should result in development
and production of oil and gas with lower risk and fewer delays than
under the current rules. Since the potential economically recoverable
oil and gas resources from the Arctic OCS are abundant, as discussed
later in this proposed rule, the positive impact of such production on
U.S. energy independence and energy security could be substantial.
Thus, this proposed rule would help achieve the National Arctic
Strategy goals of protecting the unique and sensitive Arctic
ecosystems, as well as the subsistence, culture and traditions of the
Alaska Native communities, while reducing reliance on imported oil and
strengthening National energy security.
II. Background
A. Statutory and Regulatory Overview
1. Outer Continental Shelf Lands Act (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)).
Prior to commencing exploration for oil and gas on an OCS lease
tract, the statute and BOEM regulations require lessees to submit an EP
to the Secretary for approval (43 U.S.C. 1340(c)(1); 30 CFR
550.201(a)). 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 the Secretary (43 U.S.C. 1340(c)(3); 30 CFR 550.211
through 550.228)).
However, approval of an EP does not automatically permit the lessee
to proceed with exploratory drilling. The lessee must submit to the
Secretary an Application for Permit to Drill (APD) which must be
approved before a lessee may drill a well (43 U.S.C. 1340(d); 30 CFR
250.410).
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. 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; environmental analyses to ensure compliance with NEPA;
environmental studies; resource evaluation; economic analysis; 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 offshore resources, by, among other things, evaluating
drilling permits, and conducting inspections to ensure compliance with
laws, regulations, lease terms, and approved plans and permits.
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 offshore exploration. The regulatory
requirements include, but are not
[[Page 9921]]
limited to, determining whether the proposed drilling operation:
i. Conforms to OCSLA, as amended, its applicable implementing
regulations, lease provisions and stipulations, and other applicable
laws;
ii. Is safe;
iii. Conforms to sound conservation practices and protects the
rights of the U.S. and 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 (30 CFR 250.101 and 250.106; 30 CFR
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 (30 CFR 250.410; 30 CFR
550.233).
2. 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 provisions 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, 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
Sec. 4202(a), codified at 33 U.S.C. 1321(j)(5)(A)(i) and (F)(i)-(ii)).
E.O. 12777 (October 18, 1991) authorized the Secretary to carry out
the functions of 33 U.S.C. 1321(j)(5) and (j)(6)(A). 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 found at
30 CFR parts 250 and 254. E.O. 12777 also authorized the Secretary to
implement 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 Alaska OCS Region
1. The Arctic OCS Oil and Gas Resource Potential Has Attracted
Significant Attention Over the Past Three Decades
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 (defined
in this proposed rule as the Arctic OCS). 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 (see
BOEM Alaska Region Web site at: http://www.boem.gov/About-BOEM/BOEM-Regions/Alaska-Region/Historical-Data/Index.aspx). The Chukchi Sea
Planning Area has a more limited history of leasing and exploration.
Only a total of five exploratory wells have been drilled (see BOEM
Alaska Region Web site at: www.boem.gov/About-BOEM/BOEM-Regions/Alaska-Region/Historical-Data/Index.aspx) and no site was considered
commercially viable for development during that time.
There have been only three exploratory wells drilled on the Arctic
OCS since 1994--the 2003 exploratory well near Prudhoe Bay in the
Beaufort Sea and Shell's two ``top hole'' wells drilled in 2012 (see
BOEM Assessment of Undiscovered Technically Recoverable Oil and Gas
Resources of the Nation's Outer Continental Shelf (2011)).
BILLING CODE 4310-VH-4310-MR-P
[GRAPHIC] [TIFF OMITTED] TP24FE15.005
[[Page 9922]]
Except for the Northstar project, operated by BP Exploration
(Alaska), Inc. (BP) from State submerged lands in the Beaufort Sea, no
production has yet resulted from any of the leases.\3\
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\3\ BP has transferred its interests in the Northstar project to
Hilcorp. Hilcorp is now the operator of that project.
---------------------------------------------------------------------------
There are currently no active Alaska OCS leases located anywhere
outside of the Beaufort Sea and Chukchi Sea Planning Areas. The oil and
gas industry's interest in offshore oil and gas exploration on the
Arctic OCS remains high despite the pace of exploration and the
challenges of operating in this unique environment.
2. Challenges to 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 severe. 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, strong 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 (see Environmental Assessments for Shell Offshore, Inc.'s
Revised Outer Continental Shelf Lease Exploration Plan, Camden Bay,
Beaufort Sea, Alaska (2011) and Shell Gulf of Mexico, Inc.'s Revised
Chukchi Sea Exploration Plan Burger Prospect (2011)); BOEM Alaska
Region Web site at: http://www.boem.gov/About-BOEM/BOEM-Regions/Alaska-
Region/Environment/Environmental-Analysis/Environmental-Impact-
Statements-and_Major-Environmental-Assessments.aspx). 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.
C. Partner and Stakeholder Engagement in Preparation for This Proposed
Rule
DOI used the recommendations from the 60-Day Report as a basis for
a series of discussions with multiple partners and stakeholders who
provided valuable input regarding potential approaches to regulating
oil and gas operations on the Arctic OCS. BOEM and BSEE recognize the
importance of the Arctic region to a number of partners and
stakeholders with varying positions on oil and natural gas development
in the region. Both Bureaus engaged in discussions with Alaska Native
and State partners, and with environmental and industry stakeholders,
in advance of publishing this proposed rule. Those discussions
addressed the recommendations from the 60-Day Report, as well as
information regarding operating conditions and challenges in the
Arctic. The then-Acting Assistant Secretary for Land and Minerals
Management, along with DOI staff from headquarters and the Alaska
Region, held three listening sessions and a series of meetings in
Alaska over the course of several weeks in June 2013. Representatives
of DOI also met with conservation organizations, the Mayor of the North
Slope Borough, the Alaska Eskimo Whaling Commission, the Inupiat
Community of the Arctic Slope (ICAS), the Native Village of Barrow, two
Alaska Native Claims Settlement Act (ANCSA) corporations, oil and gas
industry representatives, State of Alaska officials, and other local
government representatives.
DOI considered the suggestions and concerns of all partners and
stakeholders to produce a proposed rule that balances maximizing oil
and gas resource exploration on the Arctic OCS, in furtherance of the
Nation's energy security, with appropriate safeguards to protect human
safety and the unique Arctic environment, as well as the cultural
sensitivities and subsistence needs of the Alaska Native communities
that might be affected by oil and gas development in the Arctic.
1. Alaska Natives
DOI heard a variety of perspectives from Alaska Natives during its
outreach in advance of the rulemaking, including interest in the
potential economic opportunities from oil and gas development. However,
the overriding concern expressed by Alaska Natives is the potential for
adverse impacts from oil and gas operations on the marine environment
and its resources, including marine mammals, such as bowhead whales.
Alaska Natives requested that the DOI evaluate the extent to which oil
and gas activities may adversely affect marine resources of the waters
overlying the Arctic OCS and the subsistence harvest practices of
Alaska Natives. In particular, the marine mammal fauna of the Beaufort
and Chukchi Seas are among the most diverse in the world and are of
high scientific and public interest, and many are also important for
subsistence.
Future exploratory drilling could affect subsistence users in the
Arctic region. Subsistence harvests differ among Alaska Native coastal
communities. However, the bowhead whale is the most important marine
mammal species to a majority of Arctic coastal communities because it
is the preferred meat and it provides a unique and powerful cultural
basis for sharing and community cooperation.
Subsistence practices are a highly valued aspect of Alaska Native
culture. These practices are an important facet of Alaska Native
economies because they provide viable and essential means for families
to support themselves in this remote environment. The sharing of
subsistence resources also helps maintain traditional family and
community organizations. In addition to their dietary benefits,
subsistence resources provide special foods for religious and social
occasions, and materials for personal and family use. Subsistence
hunting also links Alaska Native communities to the larger market
economy. Many households within the communities earn money from selling
art work from the crafting of whale baleen and walrus ivory, and from
clothing made from fur-bearing mammals.
The Alaska Eskimo Whaling Commission, the North Slope Borough, and
others requested that DOI consider marine mammals' health as a critical
part of this proposed rule. Throughout the rule, BOEM and BSEE have
proposed elements designed to increase safety of oil and gas
exploration in ways that would help protect marine mammals by reducing
the likelihood and/or severity of oil spills. The Alaska Eskimo Whaling
Commission and its whaling captains have worked with BOEM to help
document traditional knowledge pertaining to bowhead whales, including
movement and behavior. Bowhead hunters are concerned that the effects
of offshore oil and gas exploration might displace migrating bowhead
whales.
Accordingly, BSEE proposes to revise Sec. 250.300(b) in order to:
(i) Require operators to capture all petroleum-based mud and associated
cuttings that result from Arctic OCS exploratory drilling operations to
prevent their discharge into the marine environment; and (ii) clarify
the Regional Supervisor's discretion to require operators to capture
water-based mud and associated cuttings from Arctic OCS exploratory
drilling (after completion of the hole for the conductor casing) to
prevent their
[[Page 9923]]
discharge into the marine environment, based on 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 to alter their migratory patterns in a manner that
interferes with subsistence activities or that might otherwise
adversely affect marine mammals, fish, or their habitat(s).
Given the importance of subsistence hunting and other 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 impacts from OCS operations on
marine mammals and subsistence activities.\4\
---------------------------------------------------------------------------
\4\ BOEM's Environmental Studies Program has made significant
investments into studying potential impacts from operations related
to oil and gas exploration. For example, BOEM has funded bowhead
whale studies incorporating Traditional Ecological Knowledge and
tagging data to learn more about bowhead whale migration through the
Chukchi Sea in the fall and winter (Quakenbush et al., 2010).
---------------------------------------------------------------------------
The North Slope Borough also expressed concern that oil and gas
development not overwhelm local infrastructure, energy supplies, and
services, and that local residents be provided the capacity--both in
terms of training and resources--to protect their communities and
important subsistence use areas. For this reason, DOI proposes to
require operators to provide information about their plans to minimize
the impact of their exploratory drilling operations on community
infrastructure and their plans to provide the communities with oil
spill cleanup training and resources.
2. Environmental Organizations
DOI also met directly with environmental organizations to review
and discuss recommendations for Arctic oil and gas regulations. The PEW
Charitable Trusts requested that BSEE revise 30 CFR 250.447 in order to
require blowout preventer (BOP) pressure testing every 7 days for
drilling and completion operations (an increase from every 14 days).
BSEE proposes to amend the language in Sec. 250.447 in order to
require operators on the Arctic OCS to pressure test the BOP system
every 7 days during exploratory drilling operations. This proposed
requirement is also a safety measure included in Shell's 2012 Arctic
exploratory drilling program. Additionally, BSEE is proposing to add a
new Sec. 250.471, which would require that a capping stack be
available and positioned to arrive at the well within 24 hours after a
loss of well control and a cap and flow system and that a containment
dome be available and positioned to arrive at the well within 7 days
after a loss of well control.
The Wilderness Society requested that BSEE consider implementing
Arctic-specific provisions for OSRPs. BSEE proposes to add several
requirements for OSRPs in this rule. In particular, BSEE proposes to
require that operators conducting exploratory drilling on the Arctic
OCS account for how they would increase oil encounter rates and the
effectiveness of spill response techniques and equipment when sea ice
is present. BSEE also proposes to add new provisions to 30 CFR part 254
for Arctic OCS exploratory drilling operators to, among other things,
account for enhanced oil spill response training and exercises, as well
as address the maintenance of response capabilities in the face of
seasonal gaps in operations.
3. Oil and Gas Operators
DOI held further meetings throughout the summer of 2013 with
individual oil and gas companies to hear their perspectives on possible
regulations for Arctic OCS operations. The oil and gas operators
emphasized a preference for performance-based rules as opposed to
prescriptive rules, and also stressed the need for early engagement
with the agencies in order to achieve up-front regulatory consistency.
While elements of the proposed rule are prescriptive in nature, BOEM
and BSEE endeavored to identify opportunities where performance-based
requirements were feasible and would achieve the Bureaus' goals. For
these reasons, among others, BOEM proposes to add a new requirement
that operators submit an IOP for their proposed Arctic exploratory
drilling operations and describe at an early point in the planning
process how their exploratory drilling program would be designed and
conducted in an integrated manner suitable for Arctic OCS Conditions.
The IOP process is intended to facilitate the prompt sharing of
information among the relevant Federal agencies (e.g., BOEM, BSEE, U.S.
Fish and Wildlife Service (USFWS), U.S. Coast Guard (USCG), National
Oceanic and Atmospheric Administration (NOAA), U.S. Army Corps of
Engineers, EPA) and the State of Alaska. The IOP process would also
provide the relevant agencies an early opportunity to engage in a
meaningful and constructive dialogue with operators and each other.
The goal of the IOP and the enhanced and early dialogue is to have
a well-planned, safe operation. Early communication on planning is also
anticipated to minimize the potential for project delays.
D. Expected Benefits Justifying Potential Costs
The initial RIA for this proposed rule estimates that it would
result in economic costs ranging from $1.1 to 1.2 billion, discounted
at 7 percent and 3 percent respectively, over 10 years. The above
estimated cost range reflects the increase in costs over the baseline
costs, as discussed elsewhere in this notice.
While many of the economic and other benefits of the proposed
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 the benefits of the proposed rule would
justify its potential costs and that it is appropriate to proceed with
this proposal. The probability of a catastrophic oil spill is very low;
however, the Deepwater Horizon oil spill demonstrated that even such
low probability events can have devastating economic and environmental
results. As of October 2014, by its own account, BP spent over $14
billion for cleanup and response operations related to the Deepwater
Horizon oil spill. The benefits of the proposed rule would accrue from
a relief rig, increased safety measures, and other requirements that
are expected to reduce the potential for an incident resulting in an
oil spill associated with Arctic offshore operations and, if an
incident occurs, to reduce the duration of a spill.
The Arctic OCS and its surrounding land and waters have a unique
significance to Alaska Natives, who rely on them for traditional
cultural purposes and depend on them for subsistence. Similarly, many
other Americans place a very high value on protecting the ecosystem,
including the sensitive environment and wildlife, of this largely
frontier area. Thus, prevention of a catastrophic oil spill, and
reduction of the duration of a spill if one occurs, would have
extremely important, even though largely unquantifiable, cultural and
societal benefits for the Nation.
Moreover, as explained elsewhere, this proposed rule would help
achieve the National Arctic Strategy goals of protecting the unique and
sensitive Arctic ecosystems, as well as the subsistence needs, culture
and traditions of the Alaska Native communities, while reducing
reliance
[[Page 9924]]
on imported oil and strengthening National energy security. The
proposed requirements--which are specifically tailored to the Arctic
OCS--would provide additional clarity and specificity regarding BOEM's
and BSEE's expectations for safe and responsible development of Arctic
resources and the particular actions that lessees, owners and operators
must take in order to meet those expectations. This additional clarity
and specificity is intended to help the oil and gas industry to plan
better and to more effectively conduct exploratory drilling on the
Arctic OCS, resulting in the development and production of oil and gas
with lower risk and fewer delays than have occurred under the current
rules. According to BOEM's 2011 Assessment of Undiscovered Technically
Recoverable Oil and Gas Resources of the Nation's Outer Continental
Shelf, there are approximately 17.8 billion barrels of economically
recoverable oil and about 50.1 trillion cubic feet of economically
recoverable natural gas in the Beaufort Sea and Chukchi Sea Planning
Areas combined. Thus, the impact of production in the Arctic region on
U.S. energy independence and energy security could be substantial.
III. Proposed 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. BOEM and BSEE use these regulations in
their respective oversight of OCS leasing, exploration, development,
production, and decommissioning. Depending on the type of activity,
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 cases, BOEM and BSEE have special requirements, such
as information and design requirements for deep-water development
projects (Sec. Sec. 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 (Sec. Sec. 250.417(c)
and 250.418(f)); the placement of subsea BOP systems in mudline cellars
when drilling occurs in areas subject to ice-scouring (Sec. 250.451);
and emergency plans and critical operations and curtailment procedures
information in the Alaska OCS Region (Sec. Sec. 550.220 and 550.251).
Though there is currently a comprehensive OCS oil and gas
regulatory program, there is a need for new and amended regulatory
measures for Arctic OCS exploratory drilling by MODUs. These proposed
regulations, in combination with existing regulations (which would
continue to apply to Arctic OCS operations unless otherwise expressly
stated), are intended to ensure that exploratory drilling operations
are well planned from the outset and then 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 proposed rule are:
A. Measures That Address Recommendations--The proposed rule
addresses recommendations contained in several recent reports on OCS
oil and gas activities (e.g., 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 Working Group's report entitled, ``Managing for the Future in a
Rapidly Changing Arctic, A Report to the President'' (March 2013); the
National Arctic Strategy (May 2013); and the Arctic Council, Arctic
Offshore Oil and Gas Guidelines: Systems Safety Management and Safety
Culture (March 2014)).
B. 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 proposed rule is a requirement that
operators explain how their proposed Arctic OCS exploratory drilling
operations would be fully integrated from start to finish in a manner
suitable for Arctic OCS Conditions and that they provide this
information to DOI at an early stage of the planning process.
This rule proposes to require that operators develop and submit an
IOP to DOI, acting through its designee, BOEM, at least 90 days in
advance of filing their EP. 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 would
include a description of the various aspects of an operator's proposed
exploratory drilling activities and supporting operations and how the
operator's program would be designed and conducted in a manner that
accounts for the challenges presented by Arctic OCS Conditions. The
primary issues DOI would expect operators to address relative to Arctic
OCS Conditions include, but are not limited to:
1. Vessel and equipment design 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; and
7. Preparation and staging of spill response assets.
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 Working Group
and promptly distribute the IOP to the State of Alaska and Federal
government agencies involved in the review, approval, or oversight of
various aspects of OCS operations.
However, the IOP process would not require agencies to review or
approve the IOP or an operator's planned activities. The IOP is a
conceptual, informational document designed to ensure that an operator
pays thorough and early attention to the full suite of regulated
activities, and to give
[[Page 9925]]
regulatory agencies a preview of an operator's approach to regulatory
compliance and integrated planning. Thus, the IOP would enable relevant
agencies to familiarize themselves, early in the planning process, with
the operator's overall proposed program from start to finish. This, in
turn, would allow 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 plan approvals and
permitting requirements, including aspects of the program that might
require additional details or refinement. The proposed IOP
requirement--and the proposed rule in general--would 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.
C. SCCE and Relief Rig Capabilities--In Arctic OCS exploratory
drilling, there is a need for operators to demonstrate that they would
have access to, and could deploy, well control and containment
resources that would be adequate to promptly respond to a loss of well
control. This equipment is already readily available and accessible in
the Gulf of Mexico due to the level of activity in that area. Ensuring
that operators have all necessary redundancies in place is critical, as
there is no guarantee that a single measure could control or contain a
worst-case discharge (WCD). Therefore, BSEE proposes to require
operators who use a MODU for Arctic OCS exploratory drilling to have
access to, and the ability to deploy, SCCE (e.g., a capping stack, cap
and flow system, and containment dome) within the timeframes discussed
elsewhere in this proposed rule and that the SCCE be capable of
functioning in Arctic OCS Conditions. BSEE also proposes that operators
have access to a separate relief rig that would be staged at a location
such that it could arrive on site and be capable of drilling a relief
well under anticipated Arctic OCS Conditions within specified
timeframes. 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. Operators may request
approval of alternative compliance measures under existing regulations,
if they can demonstrate that such alternative equipment or procedures
could provide a level of safety and environmental protection equal to
or surpassing the protection provided by the proposed SCCE and relief
rig requirements (30 CFR 250.141). This provision enables operators to
request approval for innovative technological advancements that may
provide them additional flexibility, provided that the operator can
establish that such technology provides at least the same level of
protection as the proposed requirements.
D. 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 offshore operations. In light of the
threats posed by ice and extreme weather events, BOEM and BSEE propose
to 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 forecasting capabilities for all phases of their
exploration program and their alert procedures and thresholds for
activating ice and weather management systems. Once operations
commence, operators would also be required to:
1. Notify 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.
E. 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 for the Arctic OCS. Among other things, this
rulemaking would establish specific planning requirements to maximize
the application of oil spill response technology and ensure a
coordinated response system that is designed to address the challenges
inherent to the Arctic region.
F. Reducing Pollution from Arctic OCS Exploratory Drilling
Operations--Partners, primarily Alaska Natives, and stakeholders have
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 and
also demonstrate that such discharges could affect water quality,
benthic habitat, and marine organisms within the localized area (see,
e.g., Shell Gulf of Mexico, Inc.'s Revised Chukchi Sea Exploration
Plan, Burger Prospect Environmental Assessment (2011)). BSEE proposes
to require the capture of all petroleum-based mud and associated
cuttings from Arctic OCS exploratory drilling operations to prevent
their discharge into the marine environment. The new provision would
also clarify 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. This discretion would be
exercised 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 to alter
their migratory patterns in a manner that interferes with subsistence
activities or might adversely affect marine mammals, fish, or their
habitat(s).
G. 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 proposes to
require that operators provide an explanation, at a conceptual level,
of how they would apply their oversight and risk management protocols
to both personnel and contractors to support safe and responsible
exploratory drilling on the Arctic OCS. It should be noted that these
proposed regulations, and DOI's existing regulations concerning OCS oil
and gas operations, would require varying levels of information about
operator safety and oversight
[[Page 9926]]
management at progressive stages of the planning and approval process.
This would start with the most general information and narrow down to
increasing levels of detail with successive regulatory submittals, as
the project would proceed from planning to implementation.
In addition, the proposed rule would require 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. Increase their BOP pressure testing frequency;
3. Conduct real-time monitoring of various aspects of well
operations, e.g., the BOP control system;
4. Increase their SEMS auditing frequency; and
5. Enhance their oil spill preparedness and response capabilities
for Arctic OCS operations.
A summary of the major provisions of this rulemaking follows.
IV. Section-By-Section Discussion
This portion of the preamble provides an explanation of the
specific regulatory changes proposed in this rule and why they are
necessary. At the outset, this discussion addresses the proposed
definitions of the terms Arctic OCS and Arctic OCS Conditions for use
in both BOEM's and BSEE's regulations in order to provide context for
the rest of the proposed provisions. Since this is a joint BOEM and
BSEE proposed rule, the remainder of the Section-by-Section discussion
is organized according to how operators would seek to comply with the
proposed regulations, rather than the order in which they would appear
in the Code of Federal Regulations. After introducing the definitions
of Arctic OCS (for purposes of proposed Sec. Sec. 250.105, 254.6, and
550.105) and Arctic OCS Conditions (for purposes of proposed Sec. Sec.
250.105 and 550.105), the Section-by-Section discussion provides an
explanation of the remainder of BOEM's proposed regulations (i.e.,
proposed Sec. Sec. 550.105, 550.200, 550.204, 550.206, and 550.220),
and then follows with the remainder of BSEE's proposed regulations
(i.e., proposed Sec. Sec. 250.105, 250.188, 250.198, 250.300, 250.402,
250.418, 250.447, 250.452, 250.470, 250.471, 250.472, 250.473, and
250.1920; proposed Sec. Sec. 254.6, 254.55, 254.65, 254.70, 254.80,
and 254.90).
Although BSEE permitting and operational requirements appear
earlier in Title 30 of the CFR at 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 (operations).
Requirements to prepare for an oil spill, which are contained in 30 CFR
part 254, may be met at any time before handling, storing, or
transporting oil in operations BSEE permits under Part 250. Finally,
the Section-by-Section discussion includes a process flowchart of
BOEM's and BSEE's current regulatory framework for Arctic OCS
exploratory drilling and how the proposed requirements would be
integrated into that framework.
A. Definitions (Sec. Sec. 250.105, 254.6, and 550.105)
Arctic OCS
For the purposes of this proposed rulemaking, Arctic OCS is defined
as the Beaufort Sea and Chukchi Sea Planning Areas, as described in the
Proposed Final OCS Oil and Gas Leasing Program for 2012-2017 (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). This definition
would appear in Sec. Sec. 250.105, 254.6, and 550.105. As described
previously, BOEM and BSEE have determined that these areas are both the
subject of current exploration and development interest and subject to
conditions that present significant challenges to such operations.
Arctic OCS Conditions
Sections 250.105 and 550.105 would be revised to add a definition
for Arctic OCS Conditions. The definition is necessary because these
proposed regulations are designed largely around the particular
challenges presented by Arctic OCS Conditions. The term Arctic OCS
Conditions would be defined to describe both the environmental
conditions and functional characteristics (e.g., geographic remoteness,
limited infrastructure, subsistence hunting areas) that oil and gas
operators can reasonably expect to encounter during exploratory
drilling operations and when responding to a loss of well control on
the Arctic OCS. Depending on the time of year, relevant environmental
conditions and the proposed definition include, but are not limited to,
the following: ``extreme cold, freezing spray, snow, extended periods
of low light, strong winds, dense fog, sea ice, strong currents, and
dangerous sea states.'' This definition would not affect or alter any
other existing Federal regulatory requirements.
It is crucial for OCS oil and gas operators to have a clear
understanding of the conditions they would likely encounter during
exploratory drilling operations and when responding to a loss of well
control on the Arctic OCS. Offshore oil and gas exploration involves
inherent risks to human safety and the environment. If not effectively
addressed, Arctic OCS Conditions could multiply these risks. Thus, the
proposed definition also recognizes that ``the Arctic's remote
location, limited infrastructure, and existence of subsistence hunting
and fishing areas are also characteristic of the Arctic region'' and
must be considered to ensure safe operations and minimize impacts to
the environment and to other users of the area. Addressing these
factors would enable industry to proactively safeguard people,
facilities, equipment, and the environment.
B. Additional Regulations Proposed by BOEM
Definitions (Sec. 550.200)
The acronym ``IOP''--meaning Integrated Operations Plan--would be
inserted into the proper alphabetical location within existing Sec.
550.200, for purposes of the IOP provisions at proposed Sec. 550.204,
as discussed next.
When must I submit my IOP for proposed Arctic exploratory drilling
operations and what must the IOP include? (Sec. 550.204)
This proposed rule would require the operator to develop an IOP for
each proposed exploratory drilling program on the Arctic OCS, and to
submit the IOP to DOI, through its designee, BOEM, at least 90 days in
advance of filing its EP. The IOP would need to describe how the
proposed exploratory drilling program would be designed and conducted
in an integrated manner suitable for Arctic OCS Conditions and would
address each of the information requirements identified in proposed
Sec. 550.204. Operators may also choose to address the requirements in
Sec. Sec. 550.211 through 550.228, which could facilitate the later
formal review of the operator's EP. The IOP should be detailed enough
to allow DOI, other relevant Federal agencies, and the State of Alaska
to:
1. Familiarize themselves with the proposed operations as an
integrated project from start to finish; and
2. Provide constructive feedback to the operator concerning the
conceptual plans reflected in its IOP.
DOI recognizes that when the IOP is submitted, operators might not
possess all the detailed and specific information that may be more
readily available later
[[Page 9927]]
in the planning process; e.g., contracts for vessels may not be
finalized, precise dates of drilling may be uncertain, or the exact
staging location of assets, such as the relief rig or SCCE, may be
unknown. For BOEM's and BSEE's purposes, operators would submit more
detailed information through the EPs and APDs, as appropriate.
Though BOEM would review the IOP to ensure that the operator's
submission addresses each of the elements listed in Sec. 550.204, the
IOP would not require approval by DOI or the other relevant agencies.
Instead, the IOP would be an informational document intended to
facilitate early review of important concepts related to an operator's
proposed exploratory drilling program. This review would assist DOI and
other relevant agencies in developing an understanding of, and
familiarity with, the operator's overall proposed exploratory drilling
program early in the planning process.
DOI recognizes that the information requirements of Sec. 550.204
could implicate other Federal agencies' and the State of Alaska's
statutory and regulatory mandates. For example, the USCG administers
laws and regulations governing maritime safety, security, and
environmental protection and is also responsible for inspecting the
vessels to which those laws and regulations apply. In acknowledging the
USCG's principal jurisdiction over vessel safety and security, DOI has
determined that information, early in the process, pertaining to the
safety of operations, vessel mobilization, demobilization, and tow
plans, is also essential to DOI's statutory and regulatory
responsibilities related to Arctic OCS oil and gas activities. The IOP
process is intended to facilitate the sharing of information among the
relevant Federal agencies and the State of Alaska and to provide the
relevant agencies an early opportunity to engage in a meaningful and
constructive dialogue with operators, consistent with the policies
articulated in E.O. 13580 (Interagency Working Group on Coordination of
Domestic Energy Development and Permitting in Alaska, discussed
earlier).
Upon receipt, DOI would engage fellow members of the Working Group
and distribute the IOP to other Federal government agencies involved in
the review, approval, or oversight of aspects of OCS operations (e.g.,
BOEM, BSEE, USFWS, USCG, NOAA, and EPA), as well as the State of
Alaska. Early engagement by these entities would allow them to become
familiar with the operator's overall proposed exploratory drilling
program and could provide a meaningful opportunity to offer early
feedback to the operator concerning its proposed activities and any
identifiable issues that might affect future permitting decisions. DOI
would also encourage the assembly of an interagency coordination team
to facilitate and coordinate agency review and feedback. Any feedback
could be provided individually by the relevant Federal agencies or the
State of Alaska, or collectively through DOI.
BOEM also plans to promptly post each IOP on its Web site. BOEM
would not solicit public input on the IOP; instead, the IOP would be
informational only, affording the public an early opportunity to view
key concepts of a proposed exploratory program. This effort responds to
stakeholder concerns that BOEM does not provide the public with
sufficient time to participate meaningfully in BOEM's administrative
process for proposed exploratory drilling activities on the Arctic OCS.
Typically, the public first becomes aware of an operator's plans for
exploratory drilling when the operator submits its EP. BOEM
acknowledges that public review periods for EPs are relatively short in
duration. However, this is a result of the OCSLA provision that
requires BOEM to approve, disapprove, or require modifications to an EP
within 30 days of BOEM deeming the EP submitted (43 U.S.C. 1340(c)(1)),
thus placing modification of the length of the review period outside
the discretion or authority of the agency absent Congressional action.
An early opportunity to view the IOP and the key concepts of the
proposed exploratory drilling program, however, will enhance existing
public engagement opportunities.
Paragraph (a), Vessels and Equipment
Operators must plan to adapt their exploratory drilling operations
to Arctic OCS Conditions. Although generally the equipment for
extracting oil and gas from the OCS is the same for the offshore Arctic
as anywhere else on the OCS, the equipment might need to be modified,
procedures might need to be adjusted, or personnel might need to be
specifically trained for work conditions on the Arctic OCS. For
example, cranes might need to be modified for operations under ice
loading that could be anticipated during Arctic OCS operations, and be
de-rated to account for reduced strength in extreme cold temperatures.
Accordingly, this provision would require that operators submit,
``[i]nformation describing how all vessels and equipment will be
designed, built, and/or modified to account for Arctic OCS Conditions''
and is designed to ensure that the operator is planning to deploy
vessels and equipment capable of operating safely on the Arctic OCS.
Operators would need to submit information sufficient to allow DOI and
other relevant agencies (e.g., the USCG) to understand the function of
each vessel within the proposed fleet of vessels and how the vessels
would be capable of performing their identified roles in the proposed
exploratory drilling program safely and effectively.
Paragraph (b), Exploratory Drilling Program Schedule
The proposed rule would require the IOP to include an exploratory
drilling program schedule of operations including importantly,
contractor work on critical components of the program (e.g., inspection
and testing of critical equipment such as BOPs or SCCE). Thorough
advanced planning regarding the proposed schedule for operations is an
important component of the IOP, particularly in light of the limits
that returning sea ice can place on the drilling season on the Arctic
OCS, and for elements of operations for which operators are relying
upon outside contractor deliverables. Furthermore, it is important for
BOEM and other relevant agencies to have information regarding how the
timing of proposed operations aligns with expected seasonal ice
encroachment, as well as how the timing of proposed operations may
interact with seasonal marine mammal migrations and subsistence
activities, for purposes of understanding the potential environmental
impacts. This will help BOEM and other relevant agencies develop an
understanding of how the operator proposes to conduct operations
safely.
The proposed schedule would need to include, for example, when an
operator intends to enter waters overlying the Alaska OCS (including
transit time to the proposed drilling site), when drilling is expected
to commence and conclude, dates of operations, and when the operator
plans to leave the vicinity of drilling operations. The schedule would
also need to include the critical dates for completion or activation of
components under construction, repair, or storage by outside
contractors. This provision would help assure DOI and other relevant
agencies that the operator and its contractors have developed a
reasonable schedule for executing each phase of the exploration program
and are capable of conducting exploratory drilling activities safely in
Arctic OCS Conditions.
[[Page 9928]]
Paragraph (c), Mobilization and Demobilization
This provision would require operators to include in their IOP a
description of their mobilization and demobilization operations,
including tow plans suitable for Arctic OCS Conditions, as well as
their general maintenance schedules for vessels and equipment. This
element is designed to help DOI and other relevant agencies understand
the extent to which operators:
1. Have accounted for the conditions likely to be encountered on
the Arctic OCS; and
2. Are prepared to handle the substantial environmental challenges
and associated operational risks present throughout the mobilization
and demobilization of personnel and equipment.
The requested information would facilitate coordination between DOI
and the USCG. Similarly, having information about where vessels would
come from and go to before and after entering the waters overlying the
Alaska OCS would aid, for example, DOI's and other relevant agencies'
early understanding of potential environmental issues, such as aquatic
invasive species that might be carried on vessels.
This provision would also require consideration of how repairs to,
and maintenance of, vessels and equipment might affect the larger
exploratory drilling program. This information could facilitate DOI's
and other relevant agencies' understanding of potential environmental
considerations and safety aspects of the projected operational
schedules.
Paragraph (d), Exploratory Drilling Program Objectives, Timelines, and
Contingency Plans
This provision would require operators to include in their IOP a
description of their ``exploratory drilling program objectives and
timelines for each objective, including general plans for abandonment
of the well(s)'' under a variety of circumstances. This description
would help DOI and other relevant agencies familiarize themselves with
the operator's plans for a well-designed, safe operation with clear
objectives for employees and contractors that would allow ample
flexibility in light of the difficult and variable conditions on the
Arctic OCS.
A fully developed exploration program includes, among other things:
the operator's general plan of how many wells it plans to drill in a
particular season; the timing and sequence of those operations;
locations of the wells; necessary equipment and resources, including
information on support vessels; and the operator's contingency plans in
the event that temporary abandonment would become necessary. To the
extent that relevant information submitted with the IOP has not
changed, the operator could later incorporate that information into its
EP. Thorough advanced planning of the operator's objectives, as well as
clear timelines for the accomplishment of each objective, are
essential, particularly in light of the limited seasonal drilling
window on the Arctic OCS.
Given the uncertainties created by the challenging Arctic OCS
Conditions, it is equally essential for an operator to acknowledge and
plan for contingencies and delays that might arise. For example, an
operator would need to provide general information regarding how it
would safely respond to unanticipated ice encroachment at the drill
site, including safe and secure temporary abandonment of the well and
relocation of the drilling rig, as necessary. DOI would need to be
provided with information that explains how the operator has considered
these elements of its exploration program, well in advance of
operations. Also, if an operator plans to drill multiple wells, DOI
must be provided with information regarding the anticipated objectives
and timelines for each well. Similarly, an operator would be expected
to indicate whether it intends to abandon the well(s) at the end of the
season and, if the operator intends to abandon the well, whether such
abandonment would be temporary or permanent.
Paragraph (e), Weather and Ice Forecasting and Management
One of the key drivers of this proposed rule is DOI's need to
understand how operators would account for the variable conditions on
the Arctic OCS and how those conditions might affect drilling
activities. One important component of an operator's overall program is
accounting for adverse weather and ice conditions and developing a plan
to respond to those conditions. Consequently, this provision would
require operators to describe their weather and ice forecasting
capabilities for all phases of the exploration program, including a
description of how they would respond to and manage ice hazards and
weather events. The challenges presented by Arctic OCS Conditions are
not limited to the period of active drilling operations, but would
create difficulties throughout all phases of an exploratory drilling
program, including mobilization and demobilization. Accordingly, it is
important for DOI and other relevant agencies to understand the
operator's plans for implementing ice and weather forecasting and
management systems that would be operational around the clock from
start to finish.
Paragraph (f), Contractors
This provision would require operators to provide in their IOP a
description of work to be performed by contractors supporting their
exploratory drilling program (including mobilization and
demobilization), how such work would be designed or modified to account
for Arctic OCS Conditions, and operators' strategy for contractor
management, oversight, and risk management. This information is
designed to help DOI and other relevant agencies understand the
operator's strategies for developing, early in the planning process, a
rigorous and effective operational management and oversight system for
its contractors that is specifically tailored for operations on the
Arctic OCS. Information regarding the nature and timeline of
operational elements for which the operator would rely on contractors
would aid in a full understanding of the various inputs and
contingencies that might affect the planned execution of the proposed
operations.
The IOP would need to describe, for example, what types of
operations the operator would contract out and how the operator would
oversee the contractor to ensure the contractor's work product would be
suitable for Arctic OCS operations. At the IOP stage, the specific
names of contractors would not be necessary but could be provided, if
known. The focus of this proposed requirement is to facilitate DOI's
and other relevant agencies' understanding of how the operator plans to
rely on contractors and how it plans to manage its contractor
relationships in order to ensure safe and responsible drilling
operations.
Paragraph (g), Safety
BOEM proposes to require that operators include in their IOP a
description of how they ``will ensure operational safety while working
in Arctic OCS Conditions,'' including but not limited to, the safety
principles applicable to operators and their contractors, the
accountability structure within operators' organizations for
implementing these principles, how operators would communicate these
principles to their employees and contractors, and how operators would
[[Page 9929]]
determine successful implementation of these principles.
The OCSLA provides that all operations taking place on 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,
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)). Also, operators are required to demonstrate through their EPs
and APDs that they have planned and are prepared to conduct activities
in a manner that conforms to the OCSLA and applicable implementing
regulations, and that their activities will be conducted safely (see 43
U.S.C. 1340(c)(1); 30 CFR 250.106, 250.107, 550.202 paragraphs (a) and
(b)). The proposed safety information requirement would help DOI and
other relevant agencies (e.g., USCG) familiarize themselves with the
operator's early consideration of how its proposed exploratory drilling
program would proceed in a safe manner with appropriate caution and
respect for the extreme and unpredictable conditions found offshore in
the Arctic and would be consistent with DOI's and other relevant
agencies' safety requirements.
This proposed safety information element is also intended to
complement BSEE's SEMS program by requiring operators to identify and
assess, early in the planning stages of their proposed exploratory
drilling program, their guiding principles for safe Arctic OCS
operations, and optimal strategies for implementing those principles
throughout their workforce.
Proposed 30 CFR 550.204(g) would not require an operator to provide
the same level of detail, if not available, concerning safety of
operations as would be available at the time of the EP and APD, or to
duplicate the detail provided in its USCG Safety Management System
program or its BSEE SEMS program. Instead, the IOP would need to
provide a general understanding of the principles that operators would
follow to manage risks to ensure safety of all exploratory drilling
activities and personnel vis-[agrave]-vis the conditions likely to be
encountered on the Arctic OCS. For example, it is reasonably expected
that operators would experience freezing spray, extended periods of low
light, strong winds, and dense fog during operations. Operators would
need to provide a general description of how they would account for
these conditions, and any guiding principles they would follow to
minimize risk to operations, personnel, vessels, and other equipment.
Paragraph (h), Staging of Oil Spill Response Assets
BOEM proposes to require that operators include in their IOP
information regarding their ``preparations and plans for staging of oil
spill response assets.'' This provision would facilitate DOI's, and
other relevant agencies' (e.g., USCG), early understanding of the
potential effects on local communities from staging spill response
assets near coastal communities, the safety and environmental
implications of plans for mobilization and demobilization of related
vessels and equipment, the potential environmental impacts of the
vessels staged in the area for response, and anticipated response times
based on where the equipment will be located. This information would be
especially relevant to the USCG, which is the Federal On Scene
Coordinator responsible for developing the North Slope Sub-Area
Contingency Plan for Oil and Hazardous Substances Discharges/Releases.
The USCG and all appropriate governmental entities at the State and
local levels would have an early understanding of the proposed
activities.
Paragraph (i), Impact of Exploratory Drilling on Local Community
Infrastructure
BOEM proposes to require that operators include in their IOP, a
description of their ``efforts to minimize impacts of [their]
exploratory drilling operations on local community infrastructure,
including but not limited to housing, energy supplies, and services.''
This provision would facilitate DOI's and other relevant agencies'
early understanding of the potential socioeconomic implications of the
proposed exploratory drilling program, including the extent to which
the proposed activities might strain the limited infrastructure of
coastal communities in the Arctic, or reduce the availability of
housing, energy, food, and health care to local communities through
increased demand and higher costs caused by the presence of persons
supporting the exploratory drilling program.
Paragraph (j), Local Community Workforce and Response Capacity
BOEM proposes to require that operators include in their IOP ``[a]
description of whether and to what extent your project will rely on
local community workforce and spill cleanup response capacity.'' This
provision would encourage operators to engage in early planning toward
providing local communities, which would incur the greatest risk of
offshore exploration activities, with the capacity--both in terms of
training and resources--to protect their communities and important
subsistence use areas. It is intended to provide DOI and other relevant
agencies with early insight into whether the proposed operations are
being planned safely, with appropriate environmental safeguards and
respect for the other users of area resources. This provision would
also allow DOI to develop an early understanding of industry's efforts
to promote local communities' ability to participate in and obtain
benefit from future Arctic OCS oil and gas development.
How do I submit the IOP, EP, DPP, or DOCD? (Sec. 550.206)
DOI recognizes that operators may consider some of the information
required by proposed Sec. 550.204 to be proprietary or commercial in
nature. Pursuant to the proposed revisions to Sec. 550.206, operators
would be able to request the nondisclosure of this information 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 a BOEM version with such information present, but clearly
marked as proprietary.
If I propose activities in the Alaska OCS Region, what planning
information must accompany the EP? (Sec. 550.220)
As described previously, drilling operations, especially on the
Arctic OCS, can be complex, and operators may face substantial
environmental challenges and operational risks throughout every phase
of the endeavor. One of the main goals of this rulemaking is to ensure,
through thorough advanced planning, that operators are capable of
operating safely in the extreme and challenging Arctic OCS Conditions.
BOEM first proposes to amend the existing ``Emergency Plans''
provision at Sec. 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
[[Page 9930]]
``vessel, offshore vehicle, or aircraft'' for clarification purposes.
BOEM next proposes to create a new Sec. 550.220(c), which would
set forth additional information requirements for EPs that are
proposing exploration activities on the Arctic OCS. BOEM proposes to
add a new performance-based provision at Sec. 550.220(c)(1) that would
require an operator to describe how its proposed activities would be
designed and conducted in a manner suitable for Arctic OCS Conditions
and how these activities would be managed and overseen as an integrated
endeavor. This description may be summarized from the operator's IOP
or, if appropriate, updated with any information not available at the
time of the IOP.
BOEM also proposes to add Sec. 550.220(c)(2), which would require
operators to include, as part of their EP submissions, more detailed
and updated information concerning their weather and ice forecasting
and management plans for all phases of their exploratory drilling
activities, including: a description of how they would respond to and
manage ice hazards and weather events; their ice and weather alert
procedures; their procedures and thresholds for activating their ice
and weather management systems; and confirmation that their ice and
weather management and alert systems would be operated continuously
throughout the planned operations. As described previously, DOI needs
to be certain that adequate forecasting equipment and procedures are in
place to predict and follow developing weather and ice conditions that
might pose a risk to operations. Also, it is essential that operators
develop and describe their pre-established thresholds for triggering
varying levels of responsive actions in the face of weather and ice
threats, as well as the procedures and equipment necessary to respond
to these hazards. Furthermore, operators need to demonstrate that they
would be capable of responding to and managing these conditions to
prevent or minimize the risks associated with ice and adverse weather.
BOEM next proposes to require preliminary information concerning
SCCE capabilities, deployment of a relief well rig, and sharing of SCCE
and spill response and cleanup assets. The proposed informational
requirements concerning SCCE and relief well rigs relate to the
operator's preliminary plans for complying with BSEE's proposed
regulations at 30 CFR 250.471 and 250.472, which will be described
later.
Requiring information about how an operator intends to satisfy the
proposed BSEE regulations at proposed 30 CFR 250.471 and 250.472 would
allow consideration of these issues at an early planning stage, and
would further inform BOEM's review of proposed EPs under Sec. 550.202,
and other applicable laws. It would likewise reduce the risk of
discrepancy between reviews and approvals conducted at the EP stage and
an operator's later-submitted APD. While BOEM anticipates that elements
of the SCCE description required by proposed Sec. 550.220(c)(3) and
the relief well rig description required by proposed Sec.
550.220(c)(4) may be general at the EP stage, they must be detailed
enough for BOEM to confirm that the operator would have plans in place
for how it would conduct its operations safely, in conformance with
applicable regulations. The description would also need to be detailed
enough to enable BOEM to evaluate the potential environmental
implications of proposed SCCE and relief well rig staging and
operations. Proposed Sec. 550.220(c)(4) would set forth some of the
information expected to be available about the relief well rig when the
EP is submitted.
The proposed Sec. 550.220(c)(5) provision would add an
informational requirement concerning any agreements the operator might
have with third parties for the sharing of assets (e.g., SCCE, relief
rigs, and oil spill response resources) and/or any agreements to assist
each other in response and cleanup efforts in the event of a loss of
well control or other emergency. A cooperative, consortium-based model
should offer:
1. Logistical, operational, and commercial efficiencies;
2. Less duplication of personnel and equipment;
3. Reduced monetary cost of exploration;
4. Reduced environmental footprint;
5. Reduced social costs and interference with other users of the
OCS; and
6. A coordinated response and cleanup effort in the event of a loss
of well control.
BOEM's environmental impact analyses have repeatedly shown that the
presence of vessels, aircraft, and other equipment within the Arctic
region could result in adverse impacts to subsistence activities and to
environmental resources (e.g., noise impacts on marine mammals,
increased risk of bird or marine mammal collisions, increased risk of
fuel spills, and increased air emissions). The potential effects would
be compounded if multiple operators--each fielding its own fleet of
drilling, resupply, and emergency response vessels--were to engage in
activities simultaneously. Avoiding duplication of relief well rigs,
oil spill response assets, and other emergency response vessels and
equipment would be an effective means to minimize environmental and
social impacts.
BOEM and BSEE strongly encourage operators proposing exploratory
drilling activities on the Arctic OCS to enter into mutual aid
agreements for the sharing of vessels, relief well rigs, and other
assets or services associated with responding to an oil spill or other
emergency. Notice of these arrangements would inform BOEM's and BSEE's
safety and environmental review of proposed activities to ensure
operators are fully prepared to respond to a loss of well control.
Also, BOEM and BSEE expect that operators, when planning a response to
a loss of well control, would ensure that an effective and immediate
removal, mitigation, or prevention of a discharge could be achieved, to
the greatest extent practicable, using private sector capability.
Finally, proposed Sec. 550.220(c)(6) would add an informational
requirement concerning the conclusion of on-site operations at the end
of the season. An operator would include a projected date, and
information used to determine the date, when on-site operations would
be completed based on ice conditions that will likely exist in the
relevant operational area (using current Federal ice and weather
forecasts or other reliable forecasting systems). An operator would
also provide a projected date, and supporting information, on when the
operator would stop drilling operations into zones capable of flowing
liquid hydrocarbons to the surface. That date would need to be
consistent with the relief rig planning requirements under proposed 30
CFR 250.472 and with the estimated timeframe for deployment of a relief
rig under proposed Sec. 550.220(c)(4).
There is no single, definitive ``end of drilling season'' in the
Arctic OCS. The projected end-of-season dates in any specific EP should
be based on a variety of factors, including the operator's equipment,
procedures, and capability to effective ly manage and mitigate risk
that are reasonably likely to occur. Other factors include, but are not
limited to, the prevailing meteorologic and oceanic conditions, which
vary from year to year, and the location of proposed drilling. For
example, in a year when the encroachment of sea ice is projected to
occur later, an operator may be able to justify a later end of
[[Page 9931]]
season and avoid the need to cease drilling operations earlier than
necessary. By contrast, in a year when the onset of sea ice is
projected to occur earlier, the operator would need to plan to conclude
on-site operations earlier.
In projecting when to conclude on-site operations, BOEM and BSEE
expect operators to be flexible and fully responsive to the latest ice
and weather forecasts and the best available information for ensuring
optimal timing for the end of on-site operations. Of course, after an
EP is approved, an operator may request approval to revise its EP if
available information regarding its operations and anticipated
meteorologic and oceanic conditions change.
For example, BOEM's approval for Shell's 2012 Arctic operations
required drilling operations in zones where measurable quantities of
liquid hydrocarbons were capable of flowing into the well to be
concluded 38 days prior to November 1, based on satellite imagery
showing the five-year historical average of earliest sea ice
encroachment over Shell's drill site and estimates of the time needed
to drill a relief well. The purpose of this drilling hiatus was to
reduce project risk by assuring a greater opportunity for response and
cleanup in the unlikely event of a late season oil spill.
BOEM and BSEE invite comments on what kinds of Arctic weather and
ice forecasting options are currently (or expected to be) available for
use by operators. In addition, comments may address other factors that
should be considered in determining when on-site operations are
expected to be completed, or when drilling into certain hydrocarbon
zones should cease each year, given an operator's response and cleanup
capabilities.
C. Additional Regulations Proposed by BSEE
Authority
The authority citation for 30 CFR part 250 would be amended to add
reference to 33 U.S.C. 1321(j)(1)(C). This statutory provision, in
addition to section 5 of the OCSLA (43 U.S.C. 1334), provides authority
to DOI for the portions of the proposed revisions to Sec. 250.300
related to preventing discharge of petroleum-based mud and cuttings
from operations that use petroleum-based mud. For further explanation
of those provisions, see the discussion under that section.
Definitions (Sec. 250.105)
This section would be revised to add definitions for Arctic OCS,
Arctic OCS Conditions, Cap and Flow System, Capping Stack, Containment
Dome, and Source Control and Containment Equipment. For an explanation
of the definitions of Arctic OCS and Arctic OCS Conditions, see the
discussion of definitions at the beginning of the Section-by-Section
analysis. The remaining definitions are necessary because these
proposed regulations would require the defined systems and equipment
under identified circumstances. In addition, the definition of District
Manager would be revised for activities on the Alaska OCS such that
District Manager would mean Regional Supervisor, because the Regional
Supervisor in BSEE's Alaska OCS region performs the District Manager's
duties.
Cap and Flow System--this term would be defined to mean an
integrated suite of equipment and vessels, including a capping stack
and associated flow lines, that, when installed or positioned, is used
to control the flow of fluids escaping from the well by conveying the
fluids to the surface to a vessel or facility equipped to process the
flow of oil, gas, and water. A cap and flow system is a high pressure
system that includes the capping stack and piping necessary to convey
the flowing fluids through the choke manifold to the surface equipment.
When a responsible party has been able to successfully cap a well, but
conditions will not allow the well to be shut in (e.g., due to damage,
equipment failure or pressure constraints), the cap and flow system
allows the well cap to be used as a connection for the flow lines that
transport well fluids to the surface for capture and disposition. In
some circumstances, this can relieve the pressure on the capping device
or tubulars at the well head or in the well while maintaining or
reestablishing control of the produced fluids, or a portion thereof.
Capping Stack--this term would be defined to mean a mechanical
device that can be installed on top of a subsea or surface wellhead or
BOP to stop the flow of fluids into the environment. A capping stack's
primary function is to stop the uncontrolled flow of fluids from a well
to the environment in the event that other intervention methods, such
as a BOP, would fail. The capping stack is attached to a connector or
pipe stub located on or in the well to achieve a pressure-tight seal
that would either stop the flow or direct it into a conduit that would
transmit the fluids to a surface facility that is able to store,
process, or properly dispose of the fluids. Capping stacks may be
deployed from the surface to the well head, as needed, or prepositioned
below the riser system when the BOP is located on the deck of a MODU.
The pre-positioned capping stack may be created by adapting an
auxiliary subsea intervention device to meet the requirements of this
proposed rule.
Containment Dome--this term would be defined to mean a non-
pressurized container that can be used to collect fluids escaping from
the well or equipment below the sea surface or from seeps by suspending
the device over the discharge or seep location. A containment dome,
also known as a ``sombrero,'' ``cofferdam,'' or ``hat,'' captures
fluids after they have escaped the well, subsea equipment, or a seep,
but before they have reached the surface. It consists of a structure
that has the ability to capture fluids rising through the water column
and to convey the fluids to a surface vessel or facility for processing
or disposal. If a cap and flow system is unable to stop or control the
flow of fluids to the environment, or the well system is so damaged
that a capping stack cannot make a successful connection, the
containment dome system would be needed to capture the hydrocarbons
flowing to the environment.
Source Control and Containment Equipment (SCCE)--SCCE would be
defined to mean the capping stack, cap and flow system, containment
dome, and/or other subsea and surface devices, equipment, and vessels
whose collective purpose is to control a spill source and stop the flow
of fluids into the environment or to contain fluids being discharged
into the environment for proper processing or disposal. This definition
is useful for referring collectively to the various independent
elements of an operator's SCCE in portions of the proposed rule that
would apply to any such equipment and its capabilities as a unified
system, rather than a specific type of SCCE (see, e.g., proposed Sec.
250.470(f)). The SCCE serves the purpose of stopping or minimizing the
flow of hydrocarbons into the environment after a loss of well control
event has occurred. The term ``surface devices'' within the definition
of SCCE refers to equipment mounted or staged on a barge, vessel, or
facility. The purpose of this equipment is to separate, treat, store
and/or dispose of fluids conveyed to the surface by the cap and flow
system or the containment dome. The SCCE, however, does not include a
BOP or similar equipment that is used in ordinary operations and
functions to maintain well control under normal operational conditions
or to prevent a loss of well control. Finally, ``subsea devices''
includes, but is not limited to,
[[Page 9932]]
remotely operated vehicles (ROV), anchors, buoyancy equipment,
connectors, cameras, controls and other subsea equipment necessary to
facilitate the deployment, operation and retrieval of the SCCE.
What incidents must I report to BSEE and when must I report them?
(Sec. 250.188)
The current regulation requires 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 proposes to add a new paragraph
(c) to this section that would require 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 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.
Sea ice, if not properly managed, can have a major effect on
exploratory drilling operations. Spring and summer thawing can produce
large ice masses on the waters overlying the Arctic OCS, which could
cause substantial damage to exploratory drilling equipment and render
operations unsafe, leading to injury, loss of life, or environmental
harm. For example, if the well is not properly protected, sea ice that
is moving through the surrounding water could cause a loss of well
control by damaging the well head and triggering the discharge of
hydrocarbons into the marine environment. Ice management activities, as
described in an operator's ice management plan, could include
physically changing the direction of an ice floe or using ice breaking
techniques in order to minimize the likelihood of damage to the
exploratory drilling equipment.
It is essential for operators to remain in close communication with
BSEE about sea ice in the area that has the potential to affect
operations. Just as the operator needs to have sufficient time to 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.
The proposed paragraph (c) would require the operator to
immediately notify the BSEE inspector on location or the Regional
Supervisor of any event that, pursuant to the hazard thresholds
identified in its EP, would trigger a heightened observation
requirement, or could potentially result in the need to physically
manage ice, initiate operations to secure the well, or move the
drilling rig to avoid a threat caused by floating ice. This provision
would also require immediate oral notification of the commencement and
completion of any ice management activities.
The oral report required by this provision could be a simple direct
oral notification of the basic facts surrounding the relevant
circumstances, and would not need to contain all of the detail required
of oral reports pursuant to Sec. 250.189. The proposed provision would
also require a follow-up written report regarding any ice management
activities undertaken by the operator that must be submitted within 24
hours following completion of those activities.
BSEE proposes this tighter 24-hour timeline (as opposed to, and in
lieu of, the standard 15 day window under Sec. 250.190) due to the
immediacy of the threats and concerns presented by circumstances
requiring ice management activities, and the need for BSEE to remain
abreast of those events in its regulatory and safety oversight role.
The written report may be submitted via email or other electronic means
to the inspector or Regional Supervisor and must conform to the content
requirements set forth in Sec. 250.190.
Finally, BSEE proposes to require that operators submit an
immediate oral report of any ``kicks'' or operational issues that are
unexpected and could result in the loss of well control. Operators on
the Alaska OCS currently have to report kicks at the end of every day
on the well activity report Form BSEE-0133, as required by Sec.
250.468. However, the proposed requirements of this section mean
operators would not be allowed to wait until the end of the day or some
time later to fill out a form. If a kick occurred, they would have to
provide an immediate oral report. The nature of Arctic OCS Conditions,
as defined in this proposed rule, demonstrates that responding to a
spill in the Arctic region would be a difficult task. Reporting kicks
right away is a safety measure that can improve the ability of both
inspectors and operators to potentially prevent a loss of well control.
Documents incorporated by reference. (Sec. 250.198)
The proposed rule would add subsection (h)(89) to existing Sec.
250.198 as a reference to the American Petroleum Institute (API)
proposed draft Recommended Practice (RP) 2N, Recommended Practice for
Planning, Designing, and Constructing Structures and Pipelines for
Arctic Conditions, Third Edition. This document will be a voluntary
consensus standard addressing the unique Arctic OCS Conditions that
affect the planning, design, and construction of systems used in Arctic
and sub-Arctic environments. This API document--which is virtually
identical to a standard previously issued by the International
Organization for Standardization (ISO), ``Petroleum and Natural Gas
Industries Arctic Offshore Structures,'' First Edition (2010) (ISO
19906)--would be appropriate for certain aspects of drilling
operations, such as accounting for the severe weather and thermal
effects on structures, maintenance procedures, and safety. Since this
proposed rule is focused on the exploratory drilling phase of
operations on the Arctic OCS, certain portions of API RP 2N, Third
Edition (such as those related to issues regarding structural and
pipeline integrity) would not be relevant to the exploration stage.
However, many elements of that document, when published, could be
effectively applied to equipment used in exploratory drilling
operations on the Arctic OCS. Therefore, proposed Sec. Sec.
250.198(h)(89) and 250.470(g) would incorporate appropriate elements of
API RP 2N, Third Edition, for purposes of APD information requirements.
A voluntary consensus standard indicates acceptance and recognition
across the industry that certain technology is feasible. For example,
API standards are created with input from oil and gas operators,
drilling contractors, service companies, consultants, and regulators.
Even though the development of a consensus standard does not
necessarily represent a unanimous agreement by the developing body's
members, the API process provides a means for industry and regulatory
bodies to provide input into the development of protocols for the
highly specialized equipment and procedures used in oil and gas
operations. In the National Technology Transfer and Advancement Act of
1995 (Pub. L. 104-113, 15 U.S.C. 3701 note), Congress directed Federal
agencies to use technical standards that are developed or adopted by
voluntary consensus standards bodies in lieu of government-unique
standards, unless inconsistent with applicable law or otherwise
impractical (see OMB Circular A-119 (Revised), February
[[Page 9933]]
1998, available at www.standards.gov/standards_gov/nttaa.cfm).
BSEE frequently uses standards (e.g., codes, specifications, RPs)
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 final regulations without
publishing the standards in their entirety in the Code of Federal
Regulations, a practice known as incorporation by reference. The legal
effect of incorporation by reference is that the incorporated standards
become regulatory requirements. Material incorporated in a final rule,
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 its final regulations. BSEE currently incorporates by reference over
100 consensus standards in its offshore regulations governing 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 in a final rule by
publishing the document title, edition, date, author, publisher,
identification number and other specified information in the Federal
Register. 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 in a final rule is limited to
the specific edition approved by the Director of the Federal Register.
Availability of Incorporated Documents for Public Viewing
When a copyrighted industry standard is incorporated by reference
into our regulations, BSEE is obligated to observe and protect that
copyright. We typically provide members of the public with Web site
addresses where these standards may be accessed for viewing--sometimes
for free and sometimes for a fee. The decision to charge a fee is made
by each standards development organization. The API provides free
online public access to at least 160 key industry standards, including
a broad range of technical standards. Those standards represent almost
one-third of all API standards and include all that are safety-related
or are incorporated into Federal regulations. These standards are
available for review, and hard copies and printable versions will
continue to be available for purchase through API. BSEE proposes to
incorporate, with certain exclusions discussed later in this proposed
rule, draft proposed API RP 2N, Third Edition, which is available for
free public viewing during the API balloting process on API's Web site
at http://mycommittees.api.org/standards/ecs/sc2/default.aspx (click on
the title of the document to open). When finalized by API, that
standard will be available for free public viewing on API's Web site
at: http://publications.api.org.\5\
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\5\ To access a standard at that API Web site, first log-in or
create a new account, accept API's ``Terms and Conditions,'' then
click on the ``Browse Documents'' button, and then select the
applicable category (e.g., ``Exploration and Production'') for the
particular standard(s) you wish to review.
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In addition, as explained later in this proposed rule, BSEE is
considering incorporating by reference ISO 19906 in lieu of API RP 2N,
Third Edition. ISO standards are available for purchase from ISO at
ISO's publications Web site at: http://www.iso.org/iso/home/store/catalogue_ics.htm or from commercial vendors.\6\
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\6\ Copies of the ISO standards referred to in this proposed
rule may also be viewed, upon request, at BSEE's Regional Offices
for Alaska (3801 Centerpoint Dr., Suite 500, Anchorage, AK; 907-334-
5300), the Pacific (760 Paseo Camarillo, Camarillo, CA; 805-384-
6300), and the Gulf of Mexico (1201 Elmwood Park Blvd., Nw Orleans,
LA; 1-800-672-2627) and at BSEE's Houston office (701 San Jacinto
St., Rm. 115, Houston, TX; 713-220-9201).
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For the convenience of the viewing public who may not wish to
purchase or view incorporated documents online, they may be inspected,
upon request, at our office, 381 Elden Street, Room 3313, Herndon,
Virginia 20170 (phone: 703-787-1587); or at the National Archives and
Records Administration (NARA). For information on the availability of
materials at NARA, call 202-741-6030, or go to: www.archives.gov/federal-register/cfr/ibr-locations.html.
If API RP 2N, Third Edition, is incorporated into the final rule,
it would continue to be made available for public viewing, when
requested, at the addresses indicated in the prior paragraph. Specific
information on where incorporated documents can be inspected or
obtained is also found at Sec. 250.198, Documents incorporated by
reference.
Pollution prevention. (Sec. 250.300)
This section would revise BSEE's pollution prevention regulation as
it pertains to Arctic OCS exploratory drilling operations. Spent mud
and cuttings are generated during exploratory drilling. Drilling mud
may be entirely water-based or may include petroleum (i.e., oil) as a
component. Cuttings generated using petroleum-based mud would be oil-
contaminated, and the discharge of the mud or cuttings into the
environment would result in discharge of that oil into the environment.
The proposed rule would add provisions in paragraphs (b)(1) and (b)(2)
requiring that, during exploratory drilling operations on the Arctic
OCS, the operator must capture all petroleum-based mud, and associated
cuttings from operations that use petroleum-based mud, to prevent their
discharge into the marine environment. These subparagraphs would also
clarify the Regional Supervisor's discretionary authority to require
operators to also 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, based on factors including, but not limited to:
1. The proximity of the exploratory drilling operations to
subsistence hunting and fishing locations;
2. The extent to which discharged mud or cuttings may cause marine
mammals to alter their migratory patterns in a manner that interferes
with subsistence activities; or
3. The extent to which discharged mud or cuttings may adversely
affect marine mammals, fish, or their habitat.
BSEE regulates discharges of mud and cuttings from OCS facilities
under the OCSLA, which contemplates the imposition of environmental
safeguards for oil and gas activities on the OCS and mandates that they
be conducted in a manner that prevents or minimizes the likelihood of
damage to the environment. The President has also delegated authority
to the Secretary (further delegated to BSEE) to regulate discharges of
oil under Section 311 of the CWA, 33 U.S.C. 1321, which calls for the
issuance of regulations establishing procedures, methods, and equipment
to prevent discharges of oil and hazardous substances from offshore
facilities, and to contain such discharges. BSEE's pollution prevention
regulations are intended to complement requirements imposed by the EPA
under the CWA. For example, in November 2012, the EPA issued general
National Pollutant Discharge Elimination System (NPDES) permits
authorizing certain discharges from oil and gas exploratory facilities
to Federal waters in the Beaufort Sea and the Chukchi Sea, including
certain discharges of water-based drilling fluids and drill cuttings,
subject to effluent limitations and other requirements. Of note, the
EPA NPDES permits do not allow the discharge of
[[Page 9934]]
oil-based drilling fluids, or the discharge of water-based drilling
fluids and drill cuttings during the fall bowhead whale hunt in the
Beaufort Sea. BSEE's proposed regulations clarify the Regional
Supervisor's authority to impose operational measures that complement
EPA's discharge limitations by considering potential impacts to
specific components of the Arctic environment, such as subsistence
activities, marine resources, and coastal areas.
The discharge of mud and cuttings has the potential to affect
marine mammals, fish, and their habitat, as well as subsistence
activities present in the Arctic region. As noted earlier, subsistence
hunting is central to the food supply and cultural traditions of many
Alaska Natives. BSEE proposes to clarify its authority to limit
discharges of any mud and cuttings having the potential to adversely
impact marine wildlife or to disrupt subsistence hunting activities.
For example, existing environmental analyses show that the release
of drill cuttings and drilling mud would result in increased turbidity
and concentrations of total suspended solids in the water column, which
could displace marine mammals from the drill sites and could adversely
affect habitat and prey within and around the drill site (see Shell
Gulf of Mexico, Inc.'s Revised Chukchi Sea Exploration Plan Burger
Prospect Environmental Assessment (2011)). In addition, subsistence
hunters, who rely on traditional ecological knowledge, have expressed
concern to BOEM and BSEE that whales are capable of detecting the odors
from mud and cuttings and will avoid areas where these discharges
occur, resulting in similar effects. Hunting farther away from shore to
find displaced whales can increase transit time, reduce the likelihood
of successful harvests, increase exposure to adverse weather and
dangerous sea states, and increase safety concerns for subsistence
hunters. Finally, the farther away whales are harvested from a
community, the greater the length of towing time necessary to bring the
animals back to shore for processing. This increased tow time could
negatively affect the viability of the meat and blubber for food
because of spoilage.
Marine mammal migrations and subsistence hunting patterns vary
greatly in different areas of the Arctic region and at different times
of the year. These proposed rules would therefore clarify the Regional
Supervisor's discretion to require the capture of water-based mud and
cuttings, taking into account location- and season-specific
circumstances (such as subsistence hunting). In addition, other
relevant circumstances, such as applicable provisions of a NPDES
general permit, can be considered when exercising that discretionary
authority. BSEE invites comments on the potential costs to the industry
of limiting or prohibiting the discharge of mud and cuttings that
otherwise would not be prohibited by the NPDES general permits.
When and how must I secure a well? (Sec. 250.402)
The current regulation requires, among other things, that operators
install a downhole safety device at an appropriate depth whenever there
is an interruption in drilling operations. BSEE proposes to add a new
paragraph (c)(1), which would require exploratory drilling operators on
the Arctic OCS to ensure that any equipment left on, near, or in a
temporarily abandoned well that has penetrated below the surface casing
be secured in a way that would protect the well head and prevent or
minimize the likelihood of the integrity of the well or plugs being
compromised. The primary concern this proposed language is designed to
address is the possibility that ice floes could sever, dislodge, or
drag any exploration-related equipment, obstructions or protrusions
left on the well or the adjacent seafloor. The proposed language,
however, is drafted to encompass damage from any foreseeable source.
The provision in paragraph (c)(1) is designed to be performance-based,
would allow operators to devise optimal strategies for identifying and
accounting for threats to the integrity of equipment left on the OCS,
and would be limited only to exploration wells that have penetrated
below the surface casing. However, for exploration wells located in an
area subject to ice scour, based on a shallow hazards survey, proposed
paragraph (c)(2) would require a mudline cellar or equivalent means of
protection. The BSEE Regional Supervisor will evaluate, during the APD
process, whether a proposed equivalent approach is sufficiently
protective.
There are a number of problems that could occur if operators did
not adhere to this proposed requirement. For example, if an ice floe
were to contact equipment left on, near, or in a well that had
penetrated hydrocarbons, the impact could damage the well and
potentially compromise the cement, casing, or safety valves and plugs
inside the well and could result in the discharge of hydrocarbons.
What additional information must I submit with my APD? (Sec. 250.418)
BSEE proposes to add a new paragraph (k) to this section, providing
that the information identified in proposed Sec. 250.470 must be
submitted with an APD for exploratory drilling on the Arctic OCS. The
information required in the proposed section would be necessary to
inform BSEE's evaluation of APDs for Arctic OCS exploratory drilling
operations (see discussion of proposed Sec. 250.470).
When must I pressure test the BOP system? (Sec. 250.447)
The current regulation requires operators to pressure test a BOP
system when it is installed, at specified time intervals, and prior to
drilling out each string of casing or a liner. BSEE proposes to revise
paragraph (b) of this section to require a BOP pressure test frequency
of one test every 7 days for Arctic OCS exploratory drilling
operations. However, there is some debate over whether more frequent
testing, beyond the 14-day test frequency prescribed by existing
regulations, would be necessary or advisable.
The effectiveness of hydrostatic pressure testing of BOPs has been
questioned in the past. The industry has argued that increasing the
number of pressure tests: (1) may reduce the reliability of the
equipment by degrading the sealing capability of the elements within
the BOP stack; and (2) does not necessarily demonstrate the future
performance of the equipment. Furthermore, the industry has claimed
that the requirement for operators to stop drilling operations to
perform a pressure test could ultimately increase the likelihood of an
incident occurring. Due to these safety and cost concerns, the industry
has sought to reduce the current testing frequency for this equipment
(i.e., to longer than every 14 days).
Ensuring the proper functioning of a BOP, which is a critical line
of defense against loss of well control, is essential to Arctic OCS
drilling operations. BSEE is concerned that the integrity of BOPs could
be compromised by Arctic conditions; in particular, BSEE is concerned
about the possible effects of extreme weather conditions on BOPs
maintained on surface vessels or facilities (such as jackup rigs). At
this time, pressure tests and functional tests are the primary methods
for ensuring the performance of BOPs. A 7-day BOP testing cycle was
proposed by Shell in 2012, and ultimately approved by BSEE, and we
propose to require a similar
[[Page 9935]]
testing frequency for all Arctic OCS exploratory drilling operations.
BSEE specifically requests comments on the appropriateness of the
proposed 7-day testing frequency to demonstrate the reliability of the
equipment under Arctic conditions. BSEE also requests that commenters
identify any additional safety issues that might arise from this
increased testing and that would be unique to Arctic operations. In
addition, BSEE invites comments on all potential drilling impacts
related to the proposed 7-day testing frequency.
Note that the only proposed changes to the existing BOP testing
regulation are the phrases specific to exploratory drilling on the
Arctic OCS. The remaining language is identical to the wording
currently at Sec. 250.447(b) and is duplicated in this proposed rule
for readability.
What are the real-time monitoring requirements for Arctic OCS
exploratory drilling operations? (Sec. 250.452)
BSEE proposes to add a new performance-based section in Part 250
that would require real-time data gathering on the BOP control system,
the fluid handling systems on the rig, and, if a downhole sensing
system is installed, the well's downhole conditions during Arctic OCS
exploratory drilling operations. In addition, this section would
require operators to transmit immediately the data during operations to
an onshore location, identified to BSEE prior to well operations, where
it must be stored and monitored by personnel who would be capable of
interpreting the data and have the authority, in consultation with rig
personnel, to initiate any necessary action in response to abnormal
events or data. Such personnel must also have the capability for
continuous and reliable contact with rig personnel, to ensure the
ability to communicate information or instructions between the rig and
onshore facility in real-time, while operations are underway.
This section would be added, in part, based on multiple
recommendations from various Deepwater Horizon investigation reports.
Having the real-time, well-related data available to onshore personnel
would increase the level of oversight of well conditions during
operations. Onshore personnel could review data and help rig personnel
conduct operations in a safe manner. Also, onshore personnel would be
able to assist the rig crew in identifying and evaluating abnormalities
that might arise during operations. This section would also require
that the real-time monitoring data be available to BSEE upon request,
to enable BSEE to perform its oversight role and to monitor responses
to events as they unfold. Finally, this section would, consistent with
Sec. Sec. 250.466 and 250.467, require that the data gathered be
stored at a designated location for recordkeeping purposes after
operations have concluded, to enable BSEE to perform audits,
investigations, or other types of analyses, as part of its regulatory
oversight functions.
The following undesignated centered heading would be inserted above
proposed Sec. 250.470:
Additional Arctic OCS Requirements
What additional information must I submit with my APD for Arctic OCS
exploratory drilling operations? (Sec. 250.470)
BSEE proposes to add Sec. 250.470, which would require operators
to provide Arctic OCS-specific information with their APDs for
exploratory drilling. The proposed informational requirements in the
new section would be necessary to inform BSEE's evaluation of APDs for
Arctic OCS exploratory drilling operations.
Paragraph (a), Fitness for Service
This provision would require operators to submit a detailed
description of the environmental, meteorologic and oceanic conditions
expected at the well site(s); how their equipment, materials, and
drilling unit will be prepared for service in the conditions, and how
the drilling unit will be in compliance with the requirements of Sec.
250.417. For this proposed requirement, BSEE would expect the operator
to identify the specific drilling units proposed for use during its
operations, verify that the identified equipment and materials are fit
for service, and that the drilling units conform to the fitness for
service requirements of Sec. 250.417. It is important that operators
provide this level of detail to ensure that the equipment, materials,
and drilling units proposed for use in Arctic OCS exploratory drilling
are capable of performing their respective tasks under Arctic OCS
Conditions.
The information requested by this proposed section for drilling
units is not in addition to the requirements of Sec. 250.417, but
rather is designed to make clear that, to satisfy the fitness
requirements of Sec. 250.417, operators would need to provide details
regarding Alaska OCS Conditions. Further, BSEE does not currently have
an existing provision for drilling equipment and materials that
requires the same level of detail found in Sec. 250.417 for drilling
units.
BSEE's current regulations concerning fitness for other types of
equipment and material are more general and performance-based than the
requirements proposed in this rule for Arctic OCS operations.
Additionally, since SCCE is a new suite of equipment and materials
proposed by this rule, there are no existing fitness for service
regulations covering these items. Therefore, the information required
under proposed paragraph (a) for equipment and materials would be new.
Paragraph (b), Well-specific Transition Operations
This provision would require operators to submit ``[a] detailed
description of all operations necessary in Arctic OCS Conditions to
transition the rig from being under way to conducting drilling
operations and from ending drilling operations to being under way, as
well as any anticipated repair and maintenance plans for the drilling
unit and equipment.'' BSEE does not intend for this provision to
require operators to resubmit any information already submitted to
BOEM. Rather, BSEE would expect operators to have a fairly detailed
plan when they submit their APD, including information such as the
identity of equipment and vessels to be used, dates of planned
operations, and a description of how the equipment and vessels would be
designed for and be capable of performing in Arctic OCS Conditions. For
transition operations, BSEE would need details about all of the
activities necessary to begin and end drilling operations, and to move
from one drilling location to the next. Examples of the types of
activities BSEE would expect an operator to describe include, but are
not limited to: recovering the subsea equipment, including the marine
riser and the lower marine riser package; recovering the BOP;
recovering the auxiliary sub-sea controls and template; laying down the
drill pipe and securing the drill pipe and marine riser; securing the
drilling equipment; transferring the fluids for transport or disposal;
securing ancillary equipment like the draw works and lines; refueling
or transferring fuel; offloading waste; recovering the ROVs; picking up
the oil spill prevention booms and equipment; and offloading the
drilling crew.
Finally, BSEE would require information regarding any specific
repair and maintenance plans for the drilling unit and equipment
associated with commencement or completion of drilling operations. All
of the required information would facilitate BSEE's
[[Page 9936]]
understanding of an operator's program and ensure that the operator
complies with lease stipulations, EP conditions, and other permitting
requirements.
Paragraph (c), Well-specific Drilling Objectives and Contingency Plans
This provision would require operators to submit ``[w]ell-specific
drilling objectives, timelines, and updated contingency plans for
temporary abandonment of the well.'' Whereas the corresponding
provisions of the proposed IOP and current EP regulations (e.g., Sec.
550.211) relate more broadly to the objectives and timelines of the
overall proposed exploratory drilling activities, this provision would
require an operator to provide ``well-specific'' information at the APD
stage. This information would include the operator's detailed schedule
of the following:
1. When they will spud the particular well (i.e., begin drilling
operations at the well site) identified in the APD;
2. How long will it take to drill the well;
3. Anticipated depths and geologic targets, with timelines;
4. When the operator expects to set and cement each string of
casing;
5. When and how the operator would log the well;
6. The operator's plans to test the well;
7. When and how the operator would abandon the well, including
specifically addressing plans for how to move the rig off location and
how the operator would meet the requirements of proposed Sec.
250.402(c);
8. A description of what equipment and vessels would be involved in
the process of temporarily abandoning the well due to ice; and
9. An explanation of how these elements would be integrated into
the operator's overall program.
Examples of the information the operator would be required to
provide include, but are not limited to: the location(s) to which the
rig would be moved; the operator's plans for safely securing the well
prior to leaving the drill site; how temporary abandonment would affect
the operator's seasonal drilling plans, including its remaining
schedule of operations at each well; and how crew logistics, such as
transportation to and from a drilling rig, would be affected.
It should be noted that the contingency plans proposed in this
section of the rule are different from the contingency plans required
for ``icing or ice-loading'' under existing Sec. 250.417(c)(2). That
phrase refers to ice build-up on the vessel or equipment itself,
whereas the focus of proposed Sec. 250.470(c) is on ice management,
meaning the contingency plans for response to the presence of ice in
the water, such as temporary abandonment of a well until the ice in the
water passes, or management through some other technique. For oil and
gas exploration, ice management is an Arctic OCS-specific issue that
does not occur elsewhere on the OCS. However, icing and ice-loading can
occur during operations on other parts of the OCS, outside of the
Arctic.
Paragraph (d), Weather and Ice Forecasting and Management
This performance-based provision would require an operator to
submit: a detailed description of its ``weather and ice forecasting
capability for all phases of the drilling operation, including how [it]
will ensure continuous awareness of potential weather and ice hazards
at, and during transition between, wells;'' its ``plans for managing
ice hazards and responding to weather events;'' and verification that
it has the capabilities described in its EP. Verification could be
provided, for example, by providing appropriate supporting documents
(e.g., contracts) for the forecasting and ice management capabilities.
BSEE needs to know the details for how the operator would implement
the policies and/or plans for managing ice and weather events,
identified to BOEM, for the drilling operations proposed in the APD. It
is anticipated that the operator may not know the specific details
about each vessel and piece of equipment that contributes to its
weather and ice forecasting and management capabilities when describing
those capabilities to BOEM, in connection with the IOP and the EP.
Also, more detailed plans for managing ice hazards or weather events
may be necessary and appropriate given the timing and location of the
specific well at issue than may have been available or appropriate for
the IOP and EP. Further, BSEE anticipates that weather and ice
monitoring and forecasting capabilities may evolve between the approval
of the EP and the submittal of the APD, which could yield better data,
especially when operations commence. Therefore, this proposed provision
would require the operator to submit the specific detailed information
to BSEE in connection with its APD and also to describe, in more detail
and closer in time to commencement of drilling, how it would implement
its weather and ice forecasting and management plan.
BSEE would expect operators to identify the specific weather and
ice forecasting equipment and vessels that they intend to utilize,
including the name of the contractor that would deliver satellite
imagery, if applicable. Such information should also be specific to the
location and operations associated with the well that is the subject of
the particular APD.
Finally, BSEE would require that an operator's weather and ice
management capabilities would be uninterrupted for the entirety of
their operations while on the Arctic OCS. This provision proposes that
there would be no gap in weather and ice monitoring activities,
including during transit between wells. This is to ensure that, upon
arrival at a new well location, there are no unexpected weather or ice
hazards that would interfere with drilling operations at the new
location, or would pose a threat to the safety or integrity of the
drilling equipment or personnel. The purpose of this proposed
requirement is to ensure that hazards to drilling operations are
avoided or managed before they could become a danger or an interruption
to operations.
Paragraph (e), Relief Rig Plan
Paragraph (e) would require operators to provide, with their APD,
information concerning how they would comply with the relief rig
requirements of proposed Sec. 250.472. See the discussion of that
provision for an explanation of the nature of, and need for, those
requirements.
Paragraph (f), SCCE Capabilities
Paragraph (f) would require operators who propose to use a MODU to
conduct exploratory drilling operations on the Arctic OCS to provide
with their APD information concerning their required SCCE capabilities
when they are drilling below or working below the surface casing,
including a statement that the operator owns, or has a contract with a
provider for, SCCE capable of controlling and/or containing its
identified WCD. Ensuring that an operator would be capable of
responding to a loss of well control is one of the key goals of this
proposed rule. In other parts of the OCS (e.g., the Gulf of Mexico),
there are several well-established contractors readily available to
operators and extensive operations and infrastructure within the region
from which resources could be drawn to respond to an event. However,
resources are limited in the Arctic region due to the remote location
and relative lack of infrastructure and operations. Therefore,
operators proposing to conduct exploratory drilling on the Arctic OCS
must demonstrate that they would have access to, and be capable of
promptly deploying, adequate SCCE. Operators
[[Page 9937]]
must also describe how they would inspect, test, and maintain this
equipment in order to ensure that it would remain fully functional and
ready for use. These proposed requirements would help assure BSEE that
operators conducting exploratory drilling under Arctic OCS Conditions
are capable of: (1) Regaining control after a loss of well control
event or (2) containing escaping fluids from a loss of well control
event. The information requirements of paragraph (f) would include:
1. A detailed description of the operator's or its contractor's
SCCE capabilities. The description must include operating assumptions
and limitations and information demonstrating that the operator would
have access to and the ability to deploy such equipment necessary to
regain control of the well. This description would allow BSEE to verify
the location and availability of this equipment for compliance with
proposed Sec. 250.471.
2. An inventory of the equipment, supplies, and services the
operator owns or has a contract for locally and regionally, including
the identification of each supplier. This information is important
because BSEE would need to verify the existence, condition, and
location of the equipment that the operator describes in its plans.
3. Where SCCE capabilities are obtained through contracting, proof
of contracts or membership agreements with cooperatives, service
providers, or other contractors, including information demonstrating
the availability of the personnel and/or equipment on a 24-hour per day
basis during operations below the surface casing. In an effort to
minimize the environmental and social footprint of, and economic
impediments to, Arctic OCS operations, BSEE is encouraging operators to
share resources, especially standby equipment. This provision would
facilitate the identification of those assets, and would allow BSEE to
verify the contractual basis of any agreements necessary to provide the
services required.
4. A description of the procedures for inspecting, testing, and
maintaining SCCE. SCCE is intended to be standby equipment. However,
BSEE needs to be assured that the equipment would remain able to
function if it were needed. This provision would allow BSEE to verify
that the operator, or contractor, has procedures in place for
inspecting, testing, and maintaining the equipment so that it would be
ready for use, if necessary. Operators are already required under
existing regulations at Sec. 250.1916 to retain the information
requested by this proposed new paragraph. The proposed provision would
require that operators who propose to conduct exploratory drilling on
the Arctic OCS submit this information in conjunction with their APD.
5. A description of the operator's plan to ensure that personnel
are trained to deploy and operate the equipment and that they would
maintain ongoing proficiency in source control operations. Standby
crews who are not used regularly to perform their dedicated functions
would not develop the necessary skills unless they are properly
trained, and would not maintain those skills unless that training is
reinforced by practice. It is therefore imperative that the operator
demonstrate that these personnel have a plan for acquiring, and the
ability to maintain, the proficiency necessary to respond when called
upon. This requirement would allow BSEE to review those plans and
verify that the proficiencies have been acquired and would be
maintained.
Paragraph (g), API RP 2N, Third Edition
Paragraph (g) would require that operators explain how they
utilized API RP 2N, Third Edition, in planning their Arctic OCS
exploratory drilling operations. The API is updating this RP by
adopting the entirety of ISO standard ``Petroleum and natural gas
industries Arctic offshore structures,'' First Edition (2010) (ISO
19906). Since the requirements of this proposed rule are limited only
to exploratory drilling operations, operators would not be expected to
provide an explanation of how they utilized the entire API RP 2N, Third
Edition. This performance-based requirement would be limited to those
portions of that document that are specifically relevant for
exploratory drilling operations. BSEE proposes to exclude the following
sections of API RP 2N, Third Edition, from incorporation:
1. sections 6.6.3 through 6.6.4;
2. the foundation recommendations in section 8.4;
3. section 9.6;
4. the recommendations for permanently moored systems in section
9.7;
5. the seismic analysis recommendations for pile foundations in
section 9.10;
6. section 12;
7. section 13.2.1;
8. sections 13.8.1.1, 13.8.2.1, 13.8.2.2, 13.8.2.4 through
13.8.2.7;
9. sections 13.9.1, 13.9.2, 13.9.4 through 13.9.8;
10. sections 14 through 16; and
11. section 18.
Sections 6.6.3 and 6.6.4 would be excluded because they address
different types of conditions for ice gouging and/or scouring than are
anticipated to occur during the Alaska Arctic open water drilling
season. The foundation criteria of section 8.4, the piled structure
criteria of section 9.6, the requirements for permanently moored
systems in section 9.7, and the requirements for seismic analysis of
pile foundations in section 9.10 would be excluded because this rule
only applies to MODUs drilling on a temporary basis, as opposed to the
more permanent types of structures addressed in those provisions.
Similarly, section 12 would be excluded because it applies only to
fixed concrete structures and is outside the scope of this proposed
rule. Section 13.2.1 (design philosophy for floating structures) would
be excluded because similar ice forecasting and management issues are
covered separately under proposed Sec. 250.470(d). Sections 13.8.1.1,
13.8.2.1, 13.8.2.2, 13.8.2.4 through 13.8.2.7, 13.9.1, 13.9.2, and
13.9.4 through 13.9.5, would be excluded because they cover vessel
design and procedures requirements under USCG jurisdiction. Sections
13.9.6 (inspection and maintenance), 13.9.7 (operations and planning
for safety of personnel, the environment, and equipment), and 13.9.8
(ice management plans) would be excluded because similar requirements
are addressed by other provisions of this proposed rule. Section 14
would be excluded because it relates only to subsea production systems
while this proposed rule applies to MODUs engaged in exploratory
drilling activities and because this rule proposes a different set of
requirements for BOPs from that set forth in section 14.3.3. Section 15
(topsides design and operation) would be excluded because it does not
generally apply to MODUs, and any parts that could be utilized for
MODUs fall under USCG jurisdiction. Section 16 (ice engineering topics)
would be excluded because it applies to structures that will remain in
the ice and does not apply to MODUs. Section 18 (escape, evacuation and
rescue) would be excluded because its provisions are already addressed
under existing 30 CFR part 250 Subpart S and USCG rules.
BSEE recognizes that, when applied to MODUs, many of the structural
criteria of API RP 2N, Third Edition, are regulated by the USCG and may
be covered by Class requirements for marine structures. Classification
is a determination made by private organizations (in accordance with
USCG
[[Page 9938]]
requirements) that a vessel has been constructed and maintained in
compliance with industry standards to be fit for a particular service,
in this case Ice Class 3. Therefore, application of API RP 2N, Third
Edition, for the purposes of this proposed rule would be limited to the
non-marine structural components of MODUs. For example, Class
requirements do not cover the derrick, plumbing, pipes, tubing, and
pumps that are all also structural components of a MODU and that fall
under BSEE jurisdiction. If incorporated in the final rule, BSEE would
expect operators to comply with API RP 2N, Third Edition, for MODU
components within BSEE jurisdiction. BSEE and the USCG have signed a
Memorandum of Agreement for MODUs outlining the allocation of
responsibilities between the agencies for fixed offshore facilities
available at: www.bsee.gov/BSEE-Newsroom/Publications-Library/Interagency-Agreements/; click on the link for 2013 BSEE/USCG MOA: OCS-
08.
BSEE specifically requests comment on proposed draft API RP 2N,
Third Edition, and on the extent to which BSEE should incorporate its
provisions when finalized into the regulations. As an alternative to
incorporation of API RP 2N, Third Edition, BSEE is considering
incorporation by reference of ISO 19906, the ISO Arctic standard on
which API RP 2N, Third Edition, is based. If BSEE incorporates the ISO
standard in lieu of the API standard, the final rule would exclude the
sections of the ISO standard corresponding to the excluded sections of
API RP 2N previously discussed. BSEE requests comments on whether and
to what extent BSEE should incorporate ISO 19906 in lieu of proposed
draft API RP 2N, Third Edition.
BSEE is also considering incorporating the ISO standard ``Petroleum
and natural gas industries--Site-specific assessment of mobile offshore
units--Part 1: Jack-ups,'' First Edition (2012) (ISO 19905-1), into the
final rule, with application limited only to Arctic OCS exploratory
drilling operations. ISO 19905-1 may be better suited than API RP 2N
(or ISO 19906) to guide structural components for jack-up rigs. The API
RP 2N (or ISO 19906) and ISO 19905-1 documents together would provide
the most comprehensive structural requirements for the use of a jack-up
rig in Arctic conditions. BSEE requests comments on the extent to which
ISO 19905-1 should be incorporated into these proposed Arctic
regulations.\7\
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\7\ Copies of ISO 19905-1 may be purchased from ISO on its Web
site (at http://www.iso.org/iso/home/store/catalogue_ics.htm) or
from commercial vendors. Copies of the ISO standards referred to in
this proposed rule may also be viewed, upon request, at BSEE's
Herndon, VA, office (at the address previously) indicated or at
BSEE's Regional Offices for Alaska, the Pacific, and the Gulf of
Mexico.
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What are the requirements for Arctic OCS source control and
containment? (Sec. 250.471)
BSEE proposes to require operators to continue to adhere to all
applicable source control and containment requirements in the current
regulations, and to meet additional SCCE requirements for Arctic OCS
exploratory drilling operations. BSEE is required to ensure that
offshore oil and gas operations are conducted safely and in a manner
that protects the environment from harm as a result of those
operations. As stated earlier, the waters and surrounding environment
of the Arctic region support a wide variety of marine mammals and other
wildlife, including several Endangered Species Act (ESA) listed species
and designated critical habitat. Furthermore, U.S. obligations under
Article 4 of the Arctic Council's Agreement on Cooperation on Marine
Oil Pollution Preparedness and Response in the Arctic, require that,
for ``areas of special ecological significance,'' each party ``shall
establish a minimum level of pre-positioned oil spill combating
equipment, commensurate with the risk involved, and programs for its
use[.]'' The Arctic contains areas of ecological significance to the
Nation as a whole, and especially to Alaska Native communities.
Therefore, it is imperative that any loss of well control during
oil and gas exploratory drilling operations is corrected and/or
contained as quickly as possible to minimize the impact of oil
pollution on the environment. To accomplish this task, it would be
necessary to have all equipment needed to cap and/or contain the
release of fluids readily available in the event of a loss of well
control during Arctic OCS exploratory drilling operations. Further,
operations on the Arctic OCS are distinct from operations on any other
part of the OCS. The logistics and the transit times necessary to
respond to a well control event on the Arctic OCS, coupled with the
difficulties associated with oil spill response operations in Arctic
OCS Conditions, require the operator to plan for and be prepared for
contingencies that would be more straightforward to address in other
theaters. There is limited ability in the Arctic region to summon
additional source control and containment resources. Accordingly,
operators working there must plan for response redundancies and
planning complexities not required elsewhere.
The proposed requirements would apply to all exploratory drilling
operations using a MODU on the Arctic OCS, regardless of the BOP
configuration employed by the operation. These provisions are designed
to ensure that each operator using a MODU would have access to, and
could promptly and effectively deploy and operate, surface and subsea
control and containment equipment in the event of a loss of well
control. In particular, BSEE would require each operator to have the
ability, in the event of a loss of well control, to cap the well and to
capture, contain, and process or properly dispose of any fluids
escaping from the well. All SCCE must be mobilized (i.e., begin
transit) to the well immediately upon a loss of well control. The rule
would specifically provide that the SCCE is only necessary when
drilling below or working below the surface casing.
This new section would require compliance with the following source
control and containment requirements for all exploration wells drilled
on the Arctic OCS.
Paragraph (a), Drilling Below or Working Below the Surface Casing
Paragraph (a) would require that the operator, when using a MODU to
drill below or work below the surface casing, have access to a capping
stack positioned to arrive at the well within 24 hours after a loss of
well control, and a cap and flow system and a containment dome
positioned to arrive at the well within 7 days after a loss of well
control. These technologies are important because they have, either
individually or in sequence, been proven to be effective at reacquiring
control of wells and/or containing the flow of hydrocarbons after
primary well control measures (such as well design and a BOP) have
failed to prevent a well control event. The SCCE is intended to provide
redundancy in the event of a loss of well control. Some of the well
control events for which this equipment would be deployed could require
a relief well to permanently plug and abandon the uncontrolled well.
On the Arctic OCS, the exploratory drilling operator would not be
considered to have the required SCCE unless it is secured in advance
and has the capability of arriving at the well
[[Page 9939]]
within the required timeframes. In the event that a BOP or other
prevention mechanism fails to stop the flow of fluids, capping stacks
would be necessary to provide an additional means to control flow from
the well, where a stub or connector is accessible. Capping stacks are
the preferred immediate first level redundancy, with the goal of
controlling the well and stopping the discharge of fluids, and should
be positioned so that they will arrive at the well within 24 hours
after a loss of well control. Incidents in which the connectors or
tubulars are not damaged would lend themselves to the use of a capping
stack.
If the tubulars are damaged and the pressure cannot be managed with
the capping stack, the remainder of the cap and flow system must be
used as a secondary response. It must be positioned so that it will
arrive at the well within 7 days of a loss of well control and designed
to capture the WCD identified in the EP. If the cap and flow system
were unable to stop or control the flow of fluids to the environment,
or the well system were damaged to the point that the capping stack
could not make a connection, the containment dome system, which also
must be positioned to arrive at the well within 7 days of a loss of
well control, would need to be used to capture the hydrocarbons flowing
to the environment, as a tertiary response. Thus, the SCCE system, as a
whole, would provide a level of redundancy and flexibility necessary to
operate on the Arctic OCS.
BSEE specifically requests comment on all of the proposed
timeframes for arrival of SCCE at the well in the event of a loss of
well control. In particular, BSEE invites comments on whether such
timeframes are appropriate, from a logistical and feasibility
perspective, to address a loss of well control. BSEE also requests
comment on whether the cap and flow system and containment dome could
be available and positioned to arrive at the well within 3 days, or
some shorter amount of time than 7 days.
Paragraph (b), Stump Test
Paragraph (b) would require monthly stump tests of dry-stored
capping stacks, and stump tests prior to installation for pre-
positioned capping stacks. The presence of the equipment alone is not
sufficient to ensure the reliability of the system. Testing of the
equipment must be done on a regular basis. This proposed rule would
impose a requirement that any capping stack that is dry stored must be
stump tested (function and pressure tested to prescribed minimum and
maximum pressures on the deck in a stand or stump where it could be
visually observed) monthly. The rule would also require that pre-
positioned capping stacks be tested prior to each installation on a
well to assure BSEE that no damage was done during the prior deployment
or transit.
Paragraph (c), Reevaluating SCCE for Well Design Changes
Paragraph (c) would require a reevaluation of the SCCE capabilities
if the well design changes because some well design changes may impact
the WCD rate. If the operator proposes a change to a well design that
impacts the WCD rate, the operator must provide the new WCD rate
through an Application for Permit to Modify (APM), as required by Sec.
250.465(a). The operator must then verify that the SCCE would either be
modified to address the new rate or that the previously proposed system
would be adequate to handle the new WCD to demonstrate ongoing
compliance with the SCCE capability requirements previously addressed.
Paragraph (d), SCCE Tests or Exercises
Paragraph (d) would require the operator to conduct tests or
exercises of the SCCE when directed by the Regional Supervisor. Similar
to the requirement that equipment be tested periodically, BSEE has
concluded that there is a need to ensure that personnel are prepared
and that they, and the SCCE, would be capable of performing as
intended. Therefore, BSEE proposes to require that operators conduct
tests and exercises (including deployment), at the direction of the
Regional Supervisor, to verify the functionality of the systems and the
training of the personnel.
Paragraphs (e) and (f), SCCE Records Maintenance
Paragraph (e) would require the operator to maintain records
pertaining to testing, inspection, and maintenance of the SCCE for at
least 10 years, and make them available to BSEE upon request. This
information would facilitate a review of the effectiveness of the
operator's inspection and maintenance procedures and provide a basis of
review for performance during any drill, test, or necessary deployment.
Because of the limited drilling season on the Arctic OCS, the 10-year
record retention requirement is necessary in order to ensure the
availability of a meaningful longitudinal data set. Additionally, the
limited drilling season means that this equipment would be infrequently
used and might be stored for long periods of time between seasons.
Thus, a 10-year record retention requirement is necessary to ensure
enough cumulative data is gathered to assess overall equipment
performance and trends.
Paragraph (f) would require the operator to maintain records
pertaining to use of the SCCE during testing, training, and deployment
activities for at least 3 years and to make them available to BSEE upon
request. The use of the equipment during testing and training
activities and actual operations must be recorded, along with any
deficiencies or failures. These records would allow BSEE to address any
issues arising during the usage and to document any trends or time-
dependent problems that would develop over the record retention period.
In the event that the equipment is used in a well control incident, the
records are necessary to document the effectiveness of the response and
functioning of the equipment.
Paragraphs (g) and (h), Mobilizing and Deploying SCCE
Paragraph (g) would require operators to mobilize (i.e., initiate
transit of) SCCE to a well immediately upon a loss of well control and
deploy (i.e., position for use) and use SCCE. Paragraph (h) would give
the Regional Supervisor the authority to require the operator to deploy
and use SCCE independent of an operator's determination of whether or
not to deploy and use SCCE. Requiring immediate mobilization would
prevent operators from delaying the transit of SCCE equipment to the
well in the hope that other source control or containment methods will
be successful. This provision would ensure that all SCCE is available
and ready for use. Also, this provision is being proposed to clarify
the Regional Supervisor's discretion to require the deployment and use
of SCCE in the event of a loss of well control or for purposes of SCCE
training and exercises. The Regional Supervisor's authority is
specifically addressed here to allow the Regional Supervisor to act in
a timely manner should a loss of well control occur.
What are the relief rig requirements for the Arctic OCS? (Sec.
250.472)
As demonstrated by past loss of well control events around the
globe, in some cases it may be necessary to drill a relief well to
permanently plug an uncontrolled well. The SCCE is an interim solution
designed to minimize environmental harm from well control events, but
the ultimate solution may need to be accomplished by a relief well.
Arctic OCS exploratory drilling operations would take place in a region
that has little or no infrastructure, that
[[Page 9940]]
is subject to variable and sometimes extreme weather, and in which
transportation systems could be interrupted for significant periods of
time. Also, Arctic OCS exploratory drilling operations are complicated
by the fact that they currently take place only during the ``open water
season,'' or that period of time in the summer and early fall when ice
hazards can be physically managed and there is no continuous ice layer
over the water. Outside of that window, ice encroachment may complicate
or prevent drilling and transit operations, and for that reason it is
critical to ensure that drilling (including relief well drilling if
necessary) and other operations affected by sea ice are concluded
before ice encroachment. Furthermore, if there is a loss of well
control during the drilling season, it is also important to ensure
that, if a relief rig is necessary to stop the uncontrolled flow of
oil, the relief rig is available and able to complete all necessary
operations in as short a time as possible. Thus, while conducting
exploratory drilling operations below the surface casing on the Arctic
OCS, it is essential to position or designate a relief rig in a
location that would enable it to transit to the well site, drill a
relief well, plug the original well, plug the relief well, and
demobilize from the site prior to expected seasonal ice encroachment.
This would require the cessation of exploratory drilling or other work
below the surface casing far enough in advance of the expected return
of seasonal ice to allow for completion and abandonment of a relief
well.
The proposed rule would establish a 45-day maximum limit on the
time necessary to complete relief well operations. This timeframe is
necessary to acknowledge the relative lack of infrastructure and active
operations from which response resources could be drawn in the region,
as well as the grave threats of a prolonged loss of well control to the
Arctic environment. If an operator were to use a pure standby rig
(i.e., a rig that is not otherwise operating in the Arctic), Dutch
Harbor is the nearest deep-water port where the standby rig could be
stationed. BSEE estimates that it would take 20 days to get the rig
ready and to transit from the nearest U.S. deep-water port (Dutch
Harbor) to the farthest well location (Beaufort leases), 20 days to
drill the relief well, and 5 days to plug the uncontrolled well, test
it, and move off the well site. If, on the other hand, an operator were
to use a second drilling rig to serve as a relief rig for another
drilling rig, the time required to complete relief well operations
could be much shorter than 45 days because the second rig would already
be operating in the Arctic OCS and would require shorter transit time
than a standby relief rig staged in Dutch Harbor or at another
location.
BSEE considered imposing prescriptive geographic limitations on the
staging of relief rigs in proximity to exploratory drilling operations,
but chose instead to propose a performance-based requirement to provide
operators the flexibility to choose how best to comply with the relief
rig obligations. Operators would need to demonstrate their ability to
complete relief well operations within a maximum of 45 days, subject to
BSEE's review in the APD process (see proposed Sec. 250.470(e)). The
proposed rule would also authorize the Regional Supervisor to direct an
operator to begin drilling the relief well.
The relief rig could be stored in harbor, staged idle offshore, or
actively working, as long as it would be capable of physically and
contractually meeting the proposed 45-day maximum timeframe. However,
any relief rig must be a separate and distinct rig from the primary
drilling rig to account for the possibility that the primary rig could
be destroyed or incapacitated during the loss of well control incident.
Of course, an 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
under Arctic OCS Conditions, and the time necessary to complete the
requisite operations once on-site. Thus, BSEE specifically requests
comment on whether the maximum time limit for deploying a relief rig
and drilling a relief well should be more or less than 45 days.
The proposed rule expressly provides that the relief rig would only
be necessary when drilling below or working below the surface casing
(i.e., where contact with hydrocarbons capable of flowing into the well
could occur). BSEE recognizes that the proposed relief rig requirement
may effectively limit the number of days an operator can work below the
surface casing at the end of each drilling season. The actual length of
this limitation would depend on the operator's plans for staging and
deploying a relief rig and could extend up to 45 days before the end of
the drilling season (e.g., the projected return of sea ice). During
this period, however, an operator may be able to conduct a number of
different operations at the well site that do not involve work below
the surface casing. Such work can significantly advance an exploratory
drilling project and can help an operator prepare to conduct work below
the surface casing during the following drilling season. BSEE requests
comments on the different types of work (above the surface casing) that
could be performed during the time period set aside for a relief well
to be drilled, if needed, as well as the economic benefits and costs
associated with this work.
While a relief well is the most reliable, and in some circumstances
the only available, solution to kill and permanently plug an out-of-
control well, there could be circumstances in which control could be
regained without intervention by a relief well. Accordingly, BSEE also
requests comment on whether there are any alternative technological
methods, in addition to a relief well, to kill and permanently plug an
out-of-control well before seasonal ice encroachment. Comments should
include, where possible, specific technological solutions, descriptions
of the conditions under which an alternative method could successfully
kill and permanently plug a well, and any research that would
demonstrate the effectiveness of such an alternative.
For example, some stakeholders have proposed that the use of subsea
shut-in devices (SIDs) located on the seafloor could help significantly
reduce the risk of a release of hydrocarbons if the BOP system fails.
SID equipment is specifically designed to act as a redundant safety
system and ensure the safe and timely shut-in of a well in an
emergency. Although BSEE believes that timely access to a relief rig is
the surest way to permanently resolve a WCD event in the Arctic, the
use of SIDs could reduce the risk of a release of hydrocarbons and
potentially justify giving operators more flexibility in the staging of
relief rigs.
Thus, BSEE requests comments on alternative compliance approaches
and specifically requests data on the performance of SIDs, including
operational issues (such as timeframes needed to activate such
alternatives). In particular, BSEE requests comments on appropriate
staging requirements for a relief rig assuming that an SID has been
installed at the exploration well. Comments are also requested on the
need for an operator to have an in-season relief well drilling
capability if an SID is used at a location that is not subject to ice
scouring.
BSEE also requests information or data comparing the relative
safety and environmental risk levels, as well as the costs, of the
equipment and procedures
[[Page 9941]]
that would be required under the proposed regulations to the risks and
costs of equipment and procedures under any suggested alternative
approach.
In any case, BSEE's existing regulations allow operators the
flexibility to develop new technological solutions and to seek approval
for the use of those solutions to fulfill their regulatory obligations.
Under 30 CFR 250.141, operators may request approval to use alternative
equipment or procedures for any specified requirement, provided that
the operator is able to demonstrate an equivalent or improved level of
safety and environmental protection. This performance-based provision
is a key part of BSEE's regulatory program, which is a combination of
prescriptive and performance-based requirements, because it gives
operators the ability to comply with regulatory requirements through a
variety of methods if they can make the necessary demonstrations to
BSEE. It also serves to encourage the development and utilization of
alternative technologies to satisfy the specific requirements contained
in the regulations.
What must I do to protect health, safety, property, and the environment
while operating on the Arctic OCS? (Sec. 250.473)
BSEE proposes to add a new Sec. 250.473 that would require
performance-based measures in addition to those listed in Sec. 250.107
to protect health, safety, property, and the environment during
exploratory drilling operations on the Arctic OCS.
Paragraph (a) would require that all equipment and materials
proposed for use in exploratory drilling operations on the Arctic OCS
be rated or de-rated for service under conditions that could be
reasonably expected during operations. Arctic OCS Conditions place
strains on operating equipment not experienced elsewhere on the OCS.
This necessitates that such equipment be rated or de-rated for use
under such conditions in order to ensure that it could operate safely
and effectively.\8\ For example, cranes must be designed to withstand
ice loads that can be anticipated to build up during Arctic OCS
operations and operational limitations of components under extreme cold
temperatures (e.g., reduced tensile strength) must be understood and
accounted for. Also, capping and containment equipment must be
specifically designed to withstand the demands of regional conditions.
The Arctic Council made similar recommendations for equipment and
materials in its 2009 report on Arctic oil and gas operations (see
Arctic Council--Arctic Offshore Oil and Gas Guidelines (2009)).
---------------------------------------------------------------------------
\8\ It is likely that Arctic Conditions could have an adverse
impact on the performance of some equipment and result in this
equipment being operated below the rated maximum performance level.
---------------------------------------------------------------------------
BSEE's existing regulation at Sec. 250.418(f) requires that
operators include in their APD ``evidence that the drilling equipment,
BOP systems and components, diverter systems, and other associated
equipment and materials are suitable for operating'' in areas subject
to subfreezing conditions, while proposed Sec. 250.473(a) would
establish a requirement for use of appropriately rated or de-rated
equipment and materials. Operators may ensure that proposed materials
and equipment are rated or de-rated appropriately by referencing
manufacturer specifications and would not need to obtain equipment or
material rating by an independent third-party rating entity. Upon
finalization of this provision, failure to use appropriately rated or
de-rated equipment and materials could subject an operator or its
contractor to enforcement action by BSEE.
Paragraph (b) would require operators to employ measures to address
human factors associated with weather conditions that can be reasonably
expected during Arctic OCS exploratory drilling operations. This
provision is designed to ensure safety of the workforce and protection
of the environment by requiring operators to account for weather
conditions that might impact decision-making and personnel health and
safety. On the Arctic OCS, the workforce would encounter harsh
environmental conditions, including extreme cold, snow, ice, and
freezing spray, which could cause, among other medical conditions,
frost bite and breathing difficulties that can impair performance and
judgment. Measures that operators would be required to use to address
human factors include, but are not limited to, provision of proper
attire and equipment, construction of protected work spaces, and
management of shifts.
What are the auditing requirements for my SEMS program? (Sec.
250.1920)
In 2013, BSEE published an update to Subpart S, which established
additional measures operators must take to manage safety and to protect
the environment during their OCS operations. The requirements under
this subpart are designed to be performance-based to allow operators to
tailor their management systems to their particular operations,
including operations on the Arctic OCS. For example, a hazards analysis
for a facility on the Arctic OCS would account for the types of hazards
expected on the Arctic OCS, like ice floe. Similarly, Job Safety
Analyses must account for Arctic OCS Conditions, such as ice, extreme
cold, snow, and freezing spray. BSEE would not consider an operator's
SEMS to be effective under Sec. 250.1924 if it were not specifically
tailored to the Arctic OCS Conditions reasonably anticipated at the
facility in question.
Similarly, existing Sec. Sec. 250.1914 and 250.1924 give BSEE
broad authority to require that operators on the Arctic OCS provide
BSEE with information such as the names of contractors and the specific
scope of their duties and timelines for performance in support of an
operator's drilling activities. For example, if an operator planned to
use a contractor for waste disposal, cementing, or logging, BSEE would
expect the operator to inform BSEE of this intent, along with any other
operations contracted out, and the names of those contractors. Because
the existing performance-based SEMS regulations are adequate to cover
Arctic OCS operations when properly implemented, no major modifications
are needed to Subpart S for the Arctic OCS. However, additional
provisions are necessary to bolster auditing expectations for Arctic
OCS exploratory drilling operations.
This rule proposes to increase the audit frequency and facility
coverage for intermittent Arctic OCS exploratory drilling operations.
While operators are generally required to conduct their SEMS audit
every 3 years after their initial audit, BSEE believes it would be
critical to perform a SEMS audit of Arctic OCS exploratory drilling
operations and all related infrastructure each year in which drilling
is conducted, because of the particularly challenging conditions and
high-risk nature of those activities. This Arctic OCS audit would
require operators to ensure that all safety systems are in place and
functional prior to commencing or resuming, activities for a new
drilling season, as well as to conduct the offshore portion of the
audit while drilling is under way. An operator conducting Arctic OCS
exploratory drilling operations may not combine its Arctic OCS facility
audit(s) with audits of its non-Arctic OCS facilities to satisfy the
facility sampling requirements incorporated into Subpart S.
As with SEMS audits in other OCS regions, there would be an onshore
and offshore portion. However, for Arctic OCS exploratory drilling
operations, an operator would be required to submit a separate audit
report and corrective
[[Page 9942]]
action plan (CAP) for the onshore and offshore portions of its audit.
To provide an opportunity for BSEE to review the onshore portion of the
audit report and CAP prior to commencement of drilling, they must be
submitted no later than March 1st in any year in which drilling is
planned. The operator would also be required to start and close the
offshore portion of the audit within 30 days after first spudding of
the well or entry into an existing wellbore for any purpose from that
facility. The operator would be required to submit the audit report and
CAP from the offshore portion of the audit within 30 days of the close
of that portion of the audit. This is designed to enable the auditors
to analyze offshore operations while they are actively underway, and to
ensure that BSEE is made aware of any issues surrounding those
operations as soon as practicable. To ensure that any critical problems
that are revealed by the audit are addressed, BSEE would be able to
order all or part of the operations to be shut down, if necessary.
Oil Spill Response
Part 254--Oil-Spill Response Requirements for Facilities Located
Seaward of the Coast Line
Definitions. (Sec. 254.6)
This section would include a revised definition of Adverse weather
conditions and add new definitions of Arctic OCS and Ice intervention
practices. These definitions are necessary because they are important
in establishing the standard for response capability based on
environmental conditions unique to the Arctic region.
Adverse weather conditions--The current regulations contain a
definition for the term ``adverse weather conditions,'' which means
conditions under which spill response activities are difficult but
nevertheless required to proceed. The concept reflects the fact that
operators are required to pursue oil spill response activities in all
but the most severe conditions where such activities would become
particularly dangerous or impossible. This term is important,
especially for Arctic OCS exploratory drilling, because it describes
the difficult conditions in which a response is still expected to occur
and excludes conditions that present too much of a risk to responder
health and safety for a response to proceed. Operators are expected to
consider the delays and challenges resulting from adverse weather when
developing their OSRP. The resulting response strategies should reflect
the right type and amount of resources necessary to effectively respond
to a WCD scenario that would include adverse weather conditions on the
Arctic OCS and should factor in anticipated disruptions or delays that
could result from operational periods where conditions would exceed
safe operating parameters and prohibit spill response activities from
occurring.
BSEE proposes to add more specific weather terms, i.e., extreme
cold, freezing spray, snow, and extended periods of low light, to this
definition for clarity regarding the weather conditions in which we
expect lessees or operators to be able to conduct response operations
on the Arctic OCS. The addition of this terminology is intended to
ensure that operators procure equipment that could respond in these
difficult, but feasible, conditions and utilize spill response
technology that would be suitable for weather conditions encountered
within the Arctic region. With this outcome in mind, we considered
establishing quantitative descriptions specific to ice and temperature.
For example, to ensure that identified response capabilities would be
able to operate in certain levels of ice, one option considered was to
include 30 percent ice coverage as a condition under which BSEE would
expect response activities to proceed. However, BSEE concluded that
using qualitative terms would allow the maximum flexibility in
determining the appropriate performance-based approach necessary to
respond quickly and effectively to an operator's WCD to the maximum
extent practicable, under conditions reasonably anticipated during
operations. This could encourage research and development, including
Federally funded projects, to continue to enhance the standard response
capabilities.
Arctic OCS -- For an explanation of the definition of Arctic OCS,
see the definitions discussion at the beginning of the Section-by-
Section analysis.
Ice intervention practices--This new term describes the equipment,
vessels, and procedures used to increase the effectiveness of response
techniques and equipment in encountering and mitigating the impacts of
spilled oil when sea ice is present. After oil spreads over a broad
area, the ability to recover, burn, or disperse oil depends on the rate
at which the oil can be identified, tracked, and encountered (i.e.,
encounter rate). When ice is present during efforts to mitigate the
impacts of spilled oil, the ice could act as a barrier that would
obscure, limit, or prevent access to the oil, and could also interfere
with the proper operation of response equipment. Accordingly, ice
presents unique and significant challenges, and it is important that
operators develop equipment and strategies to respond to such
challenges.
The other purpose of this definition is to specifically
differentiate terminology used to describe tactics for responding to
oil in water containing sea ice from terminology used to describe
resources and tactics employed to manage ice during drilling
operations. An operator's OSRP must address ice intervention practices
specifically intended to increase the effectiveness of an oil spill
response operation. This term relates to a new requirement for the
``emergency response action plan'' section of OSRPs for Arctic OCS
facilities, proposed at Sec. 254.80(a). Please refer to the discussion
related to that provision for further explanation of the need for, and
importance of, this item in operators' OSRPs.
Spill response plans for facilities located in Alaska State waters
seaward of the coast line in the Chukchi and Beaufort Seas. (Sec.
254.55)
The OSRPs for facilities in State waters seaward of the coast line
must be submitted to BSEE for approval and must comply with the
requirements in Subpart D. The proposed provision would require the
OSRP for any facility conducting exploratory drilling from a MODU in
Alaska State waters seaward of the coast line within the Beaufort or
Chukchi Seas to address the additional requirements set forth in the
new proposed Subpart E, discussed in detail later. BSEE has determined
that the considerations justifying the various provisions of proposed
Subpart E would also apply to these operations.
Some requirements in Subpart E address planning and exercises
related to the use of source control and subsea containment equipment
such as capping stacks or containment domes. Operators would be
required to have access to and use this equipment when conducting
exploratory drilling from a MODU on the Arctic OCS, pursuant to
proposed regulations in Part 250, but those conducting similar
activities in State waters are not currently subject to the same
requirements. The State of Alaska, however, has State requirements for
source control. As such, a response plan covering operations in State
waters of the Beaufort or Chukchi Seas must address how the source
control procedures selected to comply with State law would be
integrated into the planning, training, and exercise requirements of
proposed Sec. Sec. 254.70(a), 254.90(a), and 254.90(c).
[[Page 9943]]
Subpart E--Oil-Spill Response Requirements for Facilities Located on
the Arctic OCS
Purpose (Sec. 254.65)
This rulemaking proposes to create a new Subpart E, in order to
provide owners and operators of exploratory drilling facilities on the
Arctic OCS with additional requirements for oil spill response
preparedness that would address the challenging conditions that
operators would likely encounter on the Arctic OCS. The main purpose
for the proposed language is to establish specific planning
requirements that would maximize oil spill response technology
application and emphasize a complete response system that would be
designed to address the environmental and logistical challenges
inherent to spill response activities in the Arctic OCS region. This
would include planning for a WCD that occurs late in the drilling
season.
BSEE chose to create a new subpart instead of incorporating the
specific requirements throughout its existing regulatory provisions.
This is similar to the approach that was taken to address requirements
specific to State waters in Subpart D. It is important to note that
Subpart E would add requirements for operations on the Arctic OCS and
that all other applicable requirements in Part 254 would still apply.
BSEE chose to reserve Sec. Sec. 254.66 through 254.69; Sec. Sec.
254.71 through 254.79; and Sec. Sec. 254.81 through 254.89 within
proposed Subpart E.
What are the additional requirements for facilities conducting
exploratory drilling from a MODU on the Arctic OCS? (Sec. 254.70)
BSEE proposes to add Sec. 254.70 that would address general oil
spill response planning requirements for operators using MODUs to
conduct exploratory drilling on the Arctic OCS. These requirements
include incorporating the support mechanisms for capping stacks, cap
and flow systems, containment domes, and other similar subsea and
surface devices and equipment and vessels, required by proposed Sec.
250.471, into oil spill response incident action planning. They would
also require operators to address the influence of adverse weather
conditions on responders' health and safety during spill response
activities. Finally, they would require operators, prior to resuming
seasonal exploratory drilling activities, to review their OSRPs, and
modify as necessary, to address changes to the location or status of
response resources or the arrangements for supporting logistical
infrastructure arising from extended periods of time without drilling.
Paragraph (a) would address the need to integrate emergency well
control and containment equipment and personnel into spill response
planning to ensure coordination during a loss of well control event.
Regaining control over the well and containing discharged liquids is
the first line of response to a well control incident, following
failure of primary prevention devices. Accordingly, it is critical that
those efforts be integrated and coordinated with the spill response
efforts designed to remove or treat oil in the water that would proceed
at the same time. Although requirements for well control and
containment equipment operability and safe use fall under regulations
based on the OCSLA, its integration with the oil spill response
activities is imperative. Active information sharing through
coordinated planning efforts will ensure that oil spill response and
source control and containment operations would be synergistic and
mutually understood when called upon to function together in the event
of a loss of well control.
Paragraph (b) would address responder health and safety by ensuring
that the correct resources would be available to protect responders
from hazards specific to the Arctic region. It is critical for
operators to address in their OSRPs the influence of adverse weather
conditions, including extreme cold, snow, ice, freezing spray, and
extended periods of low light, on spill response personnel. These
conditions could impair human decision-making and physical abilities
and create risks to personnel, operations, and the environment.
Accordingly, this provision would require that operators describe in
their OSRPs the steps they would take to address those factors to
ensure that their planned oil spill response activities could be
conducted in a safe and effective manner. The types of considerations
that BSEE would expect to be addressed include, but are not limited to,
proper attire and equipment, protected work spaces, and proper shift
management. The objective would be to ensure that the equipment needed
to protect human health against adverse weather conditions would be
available immediately when a response is required.
Paragraph (c) would address specific challenges to maintaining
preparedness to respond to a spill when drilling is seasonal and there
are extended periods without any risk of an oil discharge. One of the
substantial challenges presented by operations on the Arctic OCS is the
seasonal drilling limitation resulting from the prevalence of sea ice
on portions of the waters overlying the Arctic OCS during all but the
summer and early fall months. This limitation precludes active
exploratory drilling operations from MODUs on the OCS for up to 8
months of the year, potentially leaving associated response equipment,
materials, and personnel idle for extended periods of time or leading
to their use in other regions of the OCS or elsewhere.
It is important for operators to ensure that their spill response
capabilities would not deteriorate or lose their effectiveness due to
such extended periods of inactivity and to ensure that they would
remain capable and adequate to conduct a quick and effective response
to an oil spill during active exploratory drilling operations. While
BSEE encourages owners or operators with approved OSRPs to commit to a
continuous exercise, training, and equipment maintenance regime that
inherently builds response skills over time, the Arctic OCS seasonal
drilling limitations challenge the practicality of continuously
maintaining these capabilities while there is not a risk of a
discharge. To address this challenge, BSEE would require that owners or
operators, in connection with seasonal exploratory drilling activities,
review and submit modifications to their OSRP as appropriate, to
demonstrate that all required resources would be ready, before oil is
handled, stored, or transported, to respond to a spill to the maximum
extent practicable. This OSRP review and update would address resource
allocations, changes, and, most importantly, the re-establishment of
resource readiness well before there is a risk of discharge. BSEE would
review and approve proposed OSRPs for resource maintenance during
extended periods without drilling activity through established OSRP
approval, modification, revision, and update processes described in
Sec. Sec. 254.2, 254.30, and 254.53, and the proposed update described
in this section.
What additional information must I include in the ``Emergency response
action plan'' section for facilities conducting exploratory drilling
from a MODU on the Arctic OCS? (Sec. 254.80)
BSEE also proposes to create a new Sec. 254.80 that would focus on
additional information requirements for the emergency response action
plan section of an OSRP when the operator proposes to conduct
exploratory drilling operations from a MODU on the Arctic OCS. The
additional requirements would include specifics regarding ice
[[Page 9944]]
intervention practices, staging considerations, and tracking abilities.
Sea ice could reduce the effectiveness of spill response techniques
by limiting access to spilled oil and decreasing oil encounter rates.
Therefore, in paragraph (a), BSEE would require Arctic OCS exploratory
drilling operators to describe their ice intervention practices and how
they would improve the effectiveness of spill response equipment and
response strategies in the presence of sea ice. Increasing oil
encounter rates when sea ice is present maximizes efficiency in
removing or mitigating the adverse impacts from oil in the water as
quickly and effectively as possible. The necessary practices and
equipment would work to mitigate the impacts of ice on response
operations and extend the period in which oil spill response activities
could occur. They would also ensure that appropriate ice management
vessels would be included when determining equipment requirements that
would enhance all response options and strategies included in the plan.
Operators must ensure that they would have the capability to
initiate a rapid response to the site of an offshore oil spill, as well
as to sustain and, when necessary, repair response equipment on-site
without having to rely on shore-based assets that could become
inaccessible due to weather conditions or other factors. Due to the
remote locations where Arctic OCS exploratory drilling operations would
occur, and the limited infrastructure and logistical support
capabilities in the coastal communities, operators would need to
consider strategic staging locations and support mechanisms for
effectively deploying and resupplying oil spill response resources. For
the Arctic OCS, initial response capabilities, in many instances, would
need to be based offshore to effectively meet the requirements in Part
254. Pursuant to paragraph (b)(1), operators would be required to
describe how they would maintain assets in close proximity to
exploratory drilling operations to ensure that adequate response times
would be achievable and response operations would be sustainable. The
weather conditions that are common to the area (e.g., dense fog, high
sea states) often preclude access to the area by small vessels and
aircraft for days at a time. The ability to mount and maintain an
expeditious response once a release occurs would be negatively impacted
if response assets or supporting materials were significantly delayed
from arriving at the spill site due to inclement weather. Accordingly,
operators must establish an offshore resource management system to
ensure that vessels and equipment would be readily available, along
with sufficient personnel and berthing, to carry out response
activities.
The limited support and response capabilities and capacities that
exist in most Alaska coastal communities mandate that operators provide
for nearly all aspects of an oil spill response on the Arctic OCS.
Paragraph (b)(2) would require operators to identify how they intend to
ensure an immediate and uninterrupted flow of supplies, response
equipment, personnel, and shore-based support services to sustain the
response activities until terminated by the Unified Command.\9\ The
components of the logistics supply chain include, but are not limited
to: Personnel and equipment transport services; airfields and types of
aircraft that can be supported; capabilities to mobilize supplies
(e.g., response equipment, fuel, food, fresh water) and personnel to
the response sites; onshore staging areas, storage areas that may be
used en route to staging areas, and camp facilities to support response
personnel conducting offshore, nearshore and shoreline response; and
management of recovered fluid and contaminated debris and response
materials (e.g., oiled sorbents), as well as waste streams generated at
offshore and on-shore support facilities (e.g., sewage, food, and
medical). Operators must also plan to implement mitigation measures to
reduce the impacts that surged personnel, equipment, and increased
activity would have on communities where staging areas, camp
facilities, and waste handling sites are established.
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\9\ The Unified Command is a response construct under the
incident command system headed by Federal authorities and
coordinated with the State and other parties.
---------------------------------------------------------------------------
In paragraph (c), BSEE proposes to require operators to describe
how they would maintain an effective tracking and management system
that is able to locate in real time all response equipment and
personnel conducting response activities, or transiting to and from the
response site(s), and to maintain a current picture of resources
entering and exiting staging areas and the operational status of those
resources. This system would be essential to provide the Unified
Command with information necessary to ensure that sufficient personnel
and equipment would be available to meet the response needs.
Part 254 requires operators to describe all equipment they plan to
use to respond quickly and effectively to an oil spill to the maximum
extent practicable. For oil spill response planning, BSEE would not
consider it adequate preparedness for an operator to assume that the
Federal On-Scene Coordinator would call upon assets under the control
of other entities during a response. As previously mentioned in the
Part 550 discussion, it is important to note that an effective and
immediate removal or mitigation of a discharge must be achieved to the
maximum extent practicable by private sector efforts.
What are the additional requirements for exercises of your response
personnel and equipment for facilities conducting exploratory drilling
from a MODU on the Arctic OCS? (Sec. 254.90)
BSEE proposes to create a new Sec. 254.90 that would require
operators to incorporate the additional requirements contained within
proposed Sec. Sec. 254.70 and 254.80 into their oil spill response
training and exercise activities; would require operators to provide
notice of the commencement of covered operations; and would clarify the
authority of the Regional Supervisor to conduct exercises, prior to and
during exploratory drilling operations, to test response preparedness.
These requirements are all essential to ensuring and verifying an
operator's readiness to conduct response activities on the Arctic OCS.
As described previously with respect to proposed Sec. 254.70(a),
it is essential that the relevant support mechanisms (personnel,
materials, and vessels) for capping stacks, cap and flow systems, and
containment domes, and other similar subsea and surface devices and
equipment and vessels, be integrated and coordinated with the spill
response planning and activities that would take place alongside them,
and that those arrangements are suitable for deployment on the Arctic
OCS. Accordingly, proposed Sec. 254.90(a) would require that operators
incorporate the required personnel and equipment into spill-response
training and exercises to ensure the necessary and appropriate level of
coordination between source control and subsea containment activities
and spill response activities.
Similarly, to ensure that these training and exercise activities
would accurately reflect and test the full scope of response
capabilities necessary for Arctic OCS operations, proposed Sec.
254.90(a) would also require that operators incorporate other proposed
response plan features from proposed Sec. Sec. 254.70 and 254.80 into
those activities. As outlined in proposed Sec. 254.90(c), the Regional
Supervisor
[[Page 9945]]
may direct operators to deploy response resources, as part of announced
or unannounced exercises, to verify an operator's preparedness for
responding to a spill on the Arctic OCS. These exercises might include
the deployment of capping stacks, cap and flow systems, containment
domes, or other supporting equipment in order to test their integration
and coordination with other oil spill response activities. However,
SCCE is not required to be deployed under the annual and triennial
equipment deployment requirements outlined in Sec. 254.42(b)(2).
Finally, proposed Sec. 254.90(b) would require operators planning
to conduct exploratory drilling from a MODU on the Arctic OCS to
provide 60-days' notice before handling, storing, or transporting oil
to give BSEE adequate opportunity to verify that the operator's
personnel and equipment are in compliance with existing regulations.
[[Page 9946]]
D. Arctic Exploratory Drilling Process Flowchart
BILLING CODE 4310-VH-; 4310-MR-P
[GRAPHIC] [TIFF OMITTED] TP24FE15.006
BILLING CODE 4310-VH-; 4310-MR-C
[[Page 9947]]
V. Conclusion
Overall, the proposed rule would further the Nation's energy goals
in prudently exploring frontier areas, such as those in the Arctic OCS,
by establishing operating models and requirements tailored specifically
to the extreme, unpredictable, and rapidly changing conditions that
exist in the Arctic region. The proposed regulations reflect the need
for earlier and more comprehensive planning of operations, particularly
with respect to emergency response and safety systems. The proposed
Arctic OCS exploratory drilling rule would institutionalize a proactive
approach to safety. Vulnerabilities would be identified in the planning
phase and corrections would be made to reduce the likelihood of an
incident occurring. The proposed rule would also ensure that those
plans would be carried forward and executed in a manner that would
ensure safety and environmental protection under the challenges
presented to operations by Arctic OCS Conditions.
Finally, the proposed rule would integrate emergency response,
comprehensive operational and safety planning, contractor oversight,
and upfront mutual aid agreements. The proposed combination of
prescriptive and performance-based requirements would precipitate
robust consideration of how safe exploration of the Arctic region is to
be achieved.
VI. Procedural Matters
A. Regulatory Planning and Review (E.O. 12866 and E.O. 13563)
Changes to Federal regulations must undergo several types of
economic analyses. First, E.O. 12866 and E.O. 13563 direct agencies to
assess the costs and benefits of available regulatory alternatives and,
if regulation is necessary, to select a regulatory approach that
maximizes net benefits (accounting for the potential economic,
environmental, public health, and safety effects). E.O. 13563
emphasizes the importance of quantifying both costs and benefits,
reducing costs, harmonizing rules, and promoting flexibility. Under
E.O. 12866, an agency must determine whether a regulatory action is
significant and, thus, subject to the requirements of the E.O. and OMB
review. Section 3(f) of E.O. 12866 defines a ``significant regulatory
action'' as any rule that:
1. Has an annual effect on the economy of $100 million or more, or
adversely affects in a material way the economy, a sector of the
economy, productivity, competition, jobs, the environment, public
health or safety, or State, local, or tribal governments or communities
(also referred to as ``economically significant'');
2. Creates serious inconsistency or otherwise interferes with an
action taken or planned by another agency;
3. Materially alters the budgetary impacts of entitlement grants,
user fees, loan programs, or the rights and obligations of recipients
thereof; or
4. Raises novel legal or policy issues arising out of legal
mandates, the President's priorities, or the principles set forth in
E.O. 12866.
B. E.O. 12866
E.O. 12866 provides that OMB's Office of Information and Regulatory
Affairs will review all significant rules. Pursuant to the procedures
established to implement Sec. 6 of E.O. 12866, OMB has determined that
this proposed rule is significant because the estimated annual costs or
benefits exceed $100 million in at least one year of the analysis
period. The following discussion summarizes the economic analysis; a
more detailed Initial RIA can be found in the regulatory docket for
this proposed rule at www.regulations.gov (in the Search box, use BSEE-
2013-0011). BOEM and BSEE request comments on the assumptions used in
the Initial RIA and on other possible alternatives to consider,
including alternatives to the specific provisions contained in the
proposed rule.
1. Need for Regulation
This proposed rule seeks to enhance requirements for safe,
effective, and responsible Arctic OCS oil and gas activities. Although
there is currently a comprehensive OCS oil and gas regulatory program,
DOI engagement with partners and stakeholders, including environmental
groups and Alaska Natives, reveals the need for new and enhanced
regulatory measures for Arctic OCS exploratory drilling. The current
rulemaking focuses primarily on reasonably foreseeable Arctic OCS
exploratory drilling activities that use MODUs, and on related
operations during the Arctic open-water drilling season (generally late
June to early November). After the proposed requirements for
exploratory drilling are finalized and applied to those activities, DOI
will be able to assess whether it should apply similar requirements to
development drilling.
This proposed rule builds on input received from partners and
stakeholders, key components of Shell's 2012 Arctic exploratory
drilling program, and the additional measures BOEM and BSEE required
Shell to perform under existing regulatory authorities. After
considering the input received and our direct experience from Shell's
2012 Arctic operations, BOEM and BSEE have concluded that additional
exploratory drilling regulations would enhance and clarify existing
regulations and would be appropriate as a part of the Arctic OCS oil
and gas regulatory framework.
The proposed rule would further the Nation's interest in exploring
frontier areas, such as those in the Arctic OCS region, safely and
responsibly, and would establish specific operating models and
requirements that account for both the extreme, changing conditions
that exist on the Arctic OCS and Alaska Natives' cultural traditions
and need to access subsistence resources. The proposed regulations
would require comprehensive planning of operations, especially for
emergency response and safety systems. The proposed rule would seek to
institutionalize a proactive approach to offshore safety. A goal of the
proposed rule is to identify potential vulnerabilities early in the
planning process so that corrections can be made to decrease the
potential of an incident occurring. The requirements in the proposed
rule also are designed to ensure that those plans would be executed in
a safe and environmentally protective manner despite the challenges the
Arctic OCS presents.
In particular, this proposed rule would address several important
objectives, including ensuring that operators:
i. Design and conduct exploration programs in a manner suitable for
Arctic OCS conditions;
ii. Develop an IOP that would address all phases of their proposed
Arctic OCS exploration program and submit the IOP to BOEM at least 90
days in advance of filing an EP;
iii. Have access to and the ability to promptly deploy SCCE while
drilling below or working below the surface casing;
iv. Have access to a separate relief rig located so that it could
timely drill a relief well, in the event of a loss of well control,
under the conditions expected at the site;
v. Have the capability to predict, track, report, and respond to
ice conditions and adverse weather events;
vi. Effectively manage and oversee contractors; and
vii. Develop and implement OSRPs designed and executed in a manner
suitable for the unique Arctic OCS operating environment and have the
necessary equipment, training, and
[[Page 9948]]
personnel for oil spill response on the Arctic OCS.
The following provisions of the proposed rule are expected to
result in additional costs, above the baseline, to the affected
industry:
i. Additional Incident reporting requirements;
ii. Additional pollution prevention requirements;
iii. Additional requirements for securing wells;
iv. Additional BOP pressure testing requirements;
v. Real-time monitoring requirements;
vi. Additional information requirements for APDs;
vii. Incorporation of proposed draft API RP 2N, Third Edition;
viii. Additional SCCE requirements;
ix. Relief rig requirements;
x. Additional auditing requirements;
xi. Real-time location tracking requirements;
xii. IOP requirements;
xiii. Additional requirements for EPs; and
xiv. Industry familiarization with the rule.
2. Alternatives
As explained in the Initial RIA, BOEM and BSEE have considered
three alternatives for dealing with the safety and environmental
concerns that exploratory drilling activities on the Arctic OCS have
raised:
i. Promulgate the rule changes described in this proposed rule; or
ii. Promulgate the rule changes described in the proposed rule
without including the 7-day BOP pressure testing requirement for Arctic
OCS exploratory drilling operations (in Sec. 250.447 of the proposed
rule); or
iii. Take no regulatory action and continue to rely on existing oil
and gas regulations, industry standards, and operator prudence.
BSEE has decided not to issue a proposed rule without the 7-day BOP
testing requirement. The additional testing requirement would help
ensure that BOPs deployed in the Arctic OCS function properly and
reduce the risk of blowouts. BSEE has determined that the total cost to
industry of including this requirement is approximately $135.1 million
over the 10-year analysis period (with 7 percent discounting). The cost
summary tables below present the total costs of the proposed rule with
and without the additional BOP pressure testing requirements.
BOEM and BSEE also have decided to move forward with this proposed
rule, in lieu of taking no regulatory action, because relying on the
regulatory status quo would not address the safety and environmental
concerns in the Arctic region that partners and stakeholders have
raised, and thus would not achieve the objectives of this proposed
rule. In addition, the proposed rule would confer additional
protections on the environment and Alaska Native cultural activities.
3. Economic Analysis
BOEM and BSEE evaluated the potential cost impacts of the proposed
rule against the baseline. The analysis reflects only the activities
and capital investments the proposed rule requires that represent a
change from the baseline. The analysis covers 10 years (2015 through
2024) to ensure it captures important benefits and costs that could
result from the proposed rule.\10\ When summarizing the costs and
benefits, we present the estimated annual effects and the 10-year
discounted totals using discount rates of 3 and 7 percent, per OMB
Circular A-4, ``Regulatory Analysis.'' BOEM and BSEE welcome comments
on this analysis, including comments on the assumptions, the baseline,
the methods used, and on the potential sources of data or information
on the costs and potential benefits of this proposed rule.
---------------------------------------------------------------------------
\10\ As explained in the Initial RIA, we used a 10-year period
for this analysis because of the uncertainty associated with
predicting industry's activities and the advancement of technical
capabilities. For example, the costs associated with a particular
new technology may decrease as the technology is adopted more
broadly over time. In other cases, an existing technology may be
replaced by a lower-cost alternative. Extrapolating results beyond
this 10-year time frame would produce more ambiguous results and,
therefore, be disadvantageous in determining actual costs and
benefits likely to result from this proposed rule.
---------------------------------------------------------------------------
i. Assumptions
The baseline refers to existing regulatory requirements, industry
standards, and operator prudence. According to OMB's Circular A-4, the
baseline should be ``the best assessment of the way the world would
look absent the proposed action.'' Thus, the economic analysis excluded
activities or capital investments that existing regulations require as
well as impacts resulting from the incorporation of industry standards
with which industry voluntarily complies. The baseline also includes
only costs associated with requirements that BOEM or BSEE have
previously routinely imposed in other regions under their existing
regulatory authorities, but does not include the costs described as
follows:
a. Relief Rig Capital Costs: The proposed rule requires Arctic OCS
operators to have access to a separate relief rig located such that it
could timely drill a relief well if a loss of well control were to
occur and drilling a relief well becomes necessary. Although a relief
rig was required by DOI during Shell's 2012 Arctic operations, and
although BOEM and BSEE anticipate that we would exercise our existing
authorities to require a relief rig for any future exploratory drilling
on the Arctic OCS, we chose not to include the capital costs associated
with staging a relief rig that may not be conducting exploratory
drilling (i.e., a standby rig) in the baseline.\11\ Instead, we
conservatively chose to include such costs as part of the costs of the
rule, in the detailed economic analysis contained in the Initial RIA.
These costs are estimated at $276 million per year per standby rig.
---------------------------------------------------------------------------
\11\ Although Shell included a relief rig requirement in its
Beaufort Sea and Chukchi Sea EPs for the 2012 season (which BOEM
approved and which were subsequently incorporated in Shell's APDs,
as approved by BSEE), BOEM would have required that a relief rig be
included in Shell's EPs under the authority currently found in 30
CFR 550.213 and 550.220 in any event.
---------------------------------------------------------------------------
Based on EPs and other information, however, BOEM and BSEE believe
that, in the future operators would likely designate a second operating
rig to be a relief rig (instead of staging a dedicated standby relief
rig) because, over time, the increased presence of multiple operating
rigs on the Arctic OCS would make it easier for one operating rig to be
designated as a relief rig for another operating rig. Nonetheless,
because an operator may choose to deploy a dedicated standby relief
rig, the economic analysis conservatively includes the estimated costs
for a standby rig for 2015 and 2016.
In addition, costs associated with documenting a relief rig plan
are not included in the baseline for the analysis and are included in
the economic analysis.
b. Relief Rig Activity Costs: The proposed rule would establish a
45-day maximum limit on the time necessary to complete the relief well
operations activities. This provision effectively would require the
cessation of exploratory drilling or other work below the surface
casing far enough in advance of the expected return of seasonal ice to
allow for completion and abandonment of a relief well. BOEM and BSEE
approved plans for Shell's 2012 Arctic operations required drilling
operations in zones that can support the flow of liquid hydrocarbons in
measurable quantities into the well to be concluded 38 days before
November 1, based on satellite imagery showing the 5-year historical
average of earliest encroachment of sea ice over the applicant's drill
site and the estimated time required to drill a relief well. Thus,
[[Page 9949]]
the baseline for this analysis includes this 38-day requirement from
2012. Accordingly, the potential costs of the proposed 45-day maximum
timeframe include only the costs of the additional 7 days (45 days
minus 38 days) not included in the baseline, during which drilling or
work below the surface casing could not take place.
We recognize that the requirement to have the capability to drill a
relief well to permanently kill an out-of-control well may lead to a
reduction in the number of days during which operators can perform work
below the surface casing during the drilling season. There will be
costs and benefits associated with this requirement. Those costs
(including ``opportunity costs'') may also include costs resulting from
a reduction in the number of wells that can be drilled during the term
of the lease under which the operator is conducting exploratory
drilling operations.
The Initial RIA for the proposed rule discusses the challenges
associated with estimating opportunity costs. Because the Arctic OCS is
a frontier area for drilling operations, there are very few data points
that would provide the basis for accurate estimates. Any attempt to
calculate opportunity costs would have to take into account the
significant number of uncertainties associated with exploratory
drilling, the nature of the economic benefits sought to be achieved by
such operations (e.g. booking reserves), and a variety of other
factors. These factors will often depend upon the decisions an operator
makes on how to conduct drilling operations during each drilling season
and the nature of the opportunities for other productive use of the
assets.
Data available to BOEM and BSEE indicate that the estimated daily
operating cost of a drilling rig located in the Arctic OCS is
approximately $2 million. This estimate includes all of the costs
associated with operating a rig (e.g., including the costs of the rig
crew). This figure is based upon an analysis of the daily costs of rigs
currently operating in the Gulf of Mexico, adjusted significantly
upward to account for the harsh operating conditions in the Arctic. The
actual operating costs for a rig operating in the Arctic OCS will
likely vary greatly from season to season. Industry data presented in
the course of this rulemaking indicated that the fixed costs of
drilling in the Arctic for one season are $1.2 billion, which,
amortized over an entire 100-day season of drilling, is equivalent to
$12 million per day in sunk costs.\12\
---------------------------------------------------------------------------
\12\ During a meeting conducted with OMB pursuant to E.O. 12866,
Shell stated that its total costs for a 100-day drilling season were
$1.5 billion and that 80% of those costs ($1.2 billion) were
``sunk.'' Dividing these costs by 100 (the assumed length of the
drilling season) yields an estimate of $12 million per day. These
costs have not been independently validated by BOEM and BSEE, and it
is not known if the industry figure provided already included the
expected return on capital.
---------------------------------------------------------------------------
Any calculation of opportunity costs should include an estimated
return on investment. Such a calculation could be based on the OMB
Circular A-4 estimate of the average before-tax rate of return to
private capital in the U.S. economy (7 percent) or could be based on
the industry stated average return on capital (10 percent).
Any calculation of opportunity costs should also estimate the
number of days per season that the operator could not conduct work
below the surface casing. While the proposed rule would impose a
maximum period of 45-days for a relief rig to deploy and complete a
relief well and, thus, a maximum of 45-days during which work below the
surface casing would not occur, the actual number of days during which
an operator would not be able to conduct drilling or other work below
the surface casing is subject to a number of variables. As discussed
previously, we estimate that it would take 20 days to prepare and
transport a rig from the nearest U.S. deep water port (Dutch Harbor) to
the farther well location (Beaufort leases), 20 days to drill the
relief well, and five days to plug the uncontrolled well, test it, and
move off the well site. Further, the actual time needed for completing
a relief well operation would vary depending on a number of factors.
For example, the estimated actual time needed would depend on how an
operator proposes to stage a relief rig; e.g., if it chooses to deploy
a dedicated standby relief rig or to designate a second operating rig
as a relief rig. In the latter case, a relief rig operating in the near
vicinity of the primary rig, as proposed by Shell in its revised
Exploration Plan for 2015,\13\ may be able to reach the site of a
blowout and complete a relief well in as little as 25 days, assuming no
transit time for the rig.
---------------------------------------------------------------------------
\13\ http://www.boem.gov/EP-PUBLIC-VERSION/.
---------------------------------------------------------------------------
Moreover, other work, which will likely have significant economic
benefit, may continue under the proposed rule during the period that
work below the surface casing is not allowed, providing economic
benefits from other activities that could be conducted during this
period (for example, in 2012, Shell drilled top holes during the period
it was not allowed to drill into hydrocarbon bearing zones). If the
alternative work was of similar economic value, there would be no
opportunity cost. However, it is likely the alternative work would have
a lesser value than the forgone work, and thus only partially offset
the opportunity cost.
The Initial RIA assumes that, during 10 years of exploratory
drilling operations, primary rigs (up to four per season during 2018-
2024) will conduct a total of 32 drilling campaigns. During those
drilling campaigns, costs associated with each rig will be highly
variable. Current estimates of these costs range from $ 2 million to
$12 million per day. The breadth of this range, combined with the
number of significant additional variables (number of days affected;
rate of return), makes it difficult to estimate a range of annual
opportunity costs. Additional data related to operating costs,
forecasted positioning of relief rigs, the economic effect of operating
two rigs in theater during the same season, and other significant
variables may provide the basis for meaningful estimates of annual
opportunity costs associated with the requirement that a relief rig be
able to deploy and complete a relief well within 45 days of the end of
the drilling season. We encourage comments on such estimated costs, as
well as benefits, with supporting data, including data on the uses to
which a primary rig could be put during the time it is not working
below the surface casing. Any such estimates should, if appropriate,
include estimated return on capital that would be forgone as a result
of these requirements.
c. BOP Pressure Testing Requirements: We do not include the 7-day
BOP pressure-testing requirements in the baseline for the analysis
because, although Shell agreed to this requirement as a condition of
its 2012 operations, Shell ultimately did not conduct these BOP
pressure tests during that operating season. Thus, we conservatively
include the costs associated with the increased BOP pressure testing
requirements in the analysis of the costs for Alternative 1.
Based on BOEM's and BSEE's knowledge of operators engaged in, or
likely to be engaged in, Arctic OCS exploration activities, we also
made several assumptions about the number of operators, rigs, and wells
operating on the Arctic OCS over the 10-year analysis period. We based
all assumptions on our experience with recent and expected industry
practices for operators on the Arctic OCS, including information
submitted to
[[Page 9950]]
BOEM and BSEE by lessees and operators and other available information
related to planned or potential industry exploratory activities for the
analysis period. Exhibit 1 presents these assumptions. We seek comments
on the reasonableness of these assumptions.
Exhibit 1. Assumptions About the Affected Population of Operators and
Drilling Operations
--------------------------------------------------------------------------------------------------------------------------------------------------------
Inputs 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
--------------------------------------------------------------------------------------------------------------------------------------------------------
Operators..................................................... 1 1 1 3 3 3 3 3 3 3
Primary rigs.................................................. 2 2 2 4 4 4 4 4 4 4
Standby relief rig \1\........................................ 1 1 0 0 0 0 0 0 0 0
Exploratory wells drilled each year........................... 2 4 4 4 4 6 6 6 6 6
Applications for permit to drill.............................. 2 4 4 4 4 6 6 6 6 6
Exploration plans............................................. 1 2 2 2 2 2 2 2 2 2
Integrated operations plans................................... 2 2 2 2 2 2 2 2 2 2
Oil spill response plans...................................... 2 2 2 2 2 2 2 2 2 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Standby relief rigs are rigs that are not conducting exploratory drilling and are assumed to incur different costs than relief rigs that are
conducting exploratory drilling (i.e., ``primary rigs'').
Other data inputs and assumptions common to many of the
calculations include the following:
d. SCCE and Resource Sharing: The proposed rule requires operators
to have access to, and the ability to promptly deploy, SCCE while
conducting Arctic OCS exploratory drilling or work below the surface
casing. In the cost analysis, we assume that the operator conducting
exploratory drilling beginning in 2015 already owns the required SCCE.
We also assume that the operator with two primary rigs in 2017 will use
one set of SCCE to satisfy the SCCE requirements for both of its rigs.
Finally, we assume that, of the two operators entering in 2018, one
will purchase the SCCE and the other will select the least-cost means
to comply with the proposed rule and enter into resource sharing with
an operator who has already purchased the SCCE.
Because the industry does not currently engage in resource sharing
on the Arctic OCS, BOEM and BSEE have no details on how the process
would be conducted and whether or to what degree, for example, an
operator would charge for access to equipment. The SCCE resource-
sharing assumptions represent the most likely scenario based on BSEE's
knowledge of the industry. BOEM and BSEE also considered a low-cost
scenario and a high-cost scenario that vary the assumptions for
resource sharing and purchase of SCCE by operators. The Initial RIA for
the proposed rule discusses the costs associated with these scenarios.
e. Daily Rig Operating Costs: Based on BSEE estimates and cost
estimation methodologies from the BOEM Case Study, we assume that rigs
on the Arctic OCS have a daily operating cost of $2 million. For the
purposes of the analysis, we assume that the daily rig operating costs
remain constant over the 10-year analysis period. We also assume that
the drilling season on the Arctic OCS lasts 138 days.\14\
---------------------------------------------------------------------------
\14\ We assume a 138-day drilling season for all purposes other
than the prior discussion of opportunity costs, which uses a 100-day
drilling season as assumed in the industry presentation to OMB. See
n.13.
---------------------------------------------------------------------------
f. BSEE Burden to Review Paperwork Submissions: For each paperwork
submission, we assume that for every hour that industry devotes to
compile and submit information, BSEE will need one half hour to review
the submission.\15\
---------------------------------------------------------------------------
\15\ The submissions to BOEM under Part 550 of the proposed rule
do not follow this standard review estimate because these
submissions would require a more time-intensive review by several
employees.
---------------------------------------------------------------------------
g. Wage Rates and Loaded Wage Factors: For this analysis, we
obtained median industry wage rates from the Bureau of Labor Statistics
May 2012 Occupational Employment Statistics for the industry labor
categories. We also obtained wage rates for BOEM and BSEE personnel
from the Office of Personnel Management 2012 General Schedule for the
government labor categories. To account for employee benefits, we
multiplied the hourly wage rates by appropriate loaded wage factors to
generate hourly compensation rates. The Initial RIA for the proposed
rule includes details on wage rates and loaded wage factors used in the
analysis.
4. Costs
The analysis presented in the Initial RIA describes the potential
costs of the proposed rule compared to the baseline. Exhibit 2, which
follows, summarizes these proposed requirements and their associated
costs to industry and government. Please see the Initial RIA for
details on the exact assumptions and calculations.
i. Additional Incident Reporting Requirements: Operators would be
required 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, the start and termination of such
activities, and any ``kicks'' or operational issues that are unexpected
and could result in the loss of well control. Operators also would be
required to submit a follow-up written report regarding any ice
management activities undertaken within 24 hours, following completion
of those activities.
ii. Pollution Prevention Requirements: Operators would be required
to capture all petroleum-based mud and cuttings from operations that
use petroleum-based mud. In addition, these subparagraphs clarify the
Regional Supervisor's discretionary authority to require operators to
capture all water-based muds 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.
iii. Additional Requirements for Securing Wells: Operators that
move a drilling rig off a well prior to completion or permanent
abandonment would be required to ensure that any equipment left on,
near, or in a well bore that has penetrated below the surface casing is
positioned to protect the well head and prevent or minimize the
likelihood of compromising the down-hole integrity of the well or well
plug effectiveness. Additionally, in areas of ice scour, operators
would be required to use a well cellar or an equivalent means of
minimizing the risk of damage to the wellhead.
iv. Additional BOP Pressure Testing Requirements: Operators
conducting Arctic OCS exploratory drilling operations would be required
to begin testing the BOP system before midnight on the seventh day
following the conclusion of the previous test. This proposed
requirement would represent
[[Page 9951]]
an increased testing frequency (compared to the current requirement for
testing every 14 days).
v. Real-time Monitoring Requirements: These proposed new real-time
monitoring requirements for Arctic OCS exploratory drilling operations
include real-time data gathering and monitoring capability for data on
the BOP control system, the fluid handling systems on the rig, and the
well's downhole conditions. They also include onshore data
transmission, monitoring, storage, and notification and availability of
data to BSEE.
vi. Additional Information Requirements for APDs: This provision
would require operators to submit Arctic OCS-specific information with
APDs for Arctic OCS exploratory drilling. This includes a detailed
description of how the drilling unit, equipment, and materials will be
prepared for service in Arctic OCS Conditions. Operators would be
required to submit a detailed description of all operations necessary
in Arctic OCS Conditions to transition the rig from being underway to
commencing drilling operations and from concluding drilling operations
to being underway, as well as any anticipated repair and maintenance
plans for the drilling unit and equipment. Operators would also be
required to submit well-specific drilling objectives, timelines, and
updated contingency plans for temporary abandonment of the well.
Finally, operators would be required to submit information on weather
and ice forecasting capability for all phases of drilling operations.
vii. Incorporation of Proposed Draft API RP 2N, Third Edition: This
provision would require operators to submit a detailed description of
how the relevant aspects of proposed draft API RP 2N, Third Edition,
``Planning, Designing, and Constructing Structures and Pipelines for
Arctic Conditions,'' are addressed in the planning of exploratory
drilling operations. API RP 2N is a voluntary consensus standard that
addresses the unique Arctic conditions that affect the planning,
design, and construction of systems used in Arctic and sub-Arctic
environments.
viii. Additional SCCE Requirements: There are several proposed SCCE
requirements, including equipment, stump testing, well design change
information requirements, test and exercise, records maintenance, and
documentation. Because the industry does not currently engage in
resource sharing on the Arctic OCS, BOEM and BSEE do not have details
on how that process would be conducted and whether, for example, an
operator would charge for access to equipment. The SCCE resource
sharing assumptions represent the most likely scenario based on BSEE's
knowledge of the industry. BSEE also considered a low cost scenario and
a high cost scenario for these proposed requirements that vary the
assumptions for resource sharing and purchase of SCCE by operators. See
Section 4.e of the Initial RIA for details on the costs associated with
these scenarios.
ix. Relief Rig Requirements: When conducting exploratory drilling
or working below the surface casing, operators on the Arctic OCS would
be required to have a relief rig, different from their primary drilling
rig, staged in a location such that it can arrive on site, drill a
relief well, kill and abandon the original well, and abandon the relief
well prior to expected seasonal ice encroachment at the drill site, but
no later than 45 days after the loss of well control. In estimating the
costs of this provision, BSEE included relief rig equipment capital
costs and relief rig documentation costs, but did not include potential
costs of the maximum 7 additional days (above the baseline) that
drilling or work below the surface casing could not take place each
season as a result of the maximum 45-day timeframe. ISOBSEE lacks data
on how such a limitation would affect future exploratory drilling
operations. BSEE requests information on the potential costs, if any,
due to the cessation of drilling or other work below the surface casing
up to 7 days (beyond the baseline) earlier than would otherwise occur
without the proposed relief rig requirement. Any such comments should
account for the benefits of other operations (such as maintenance and,
in some cases, drilling a second top hole) that could continue on the
site after drilling or work below the surface casing ceases.
x. Additional Auditing Requirements: This provision would increase
the SEMS audit frequency and facility coverage for Arctic OCS
exploratory drilling operations.
xi. Real-time Location Tracking Requirements: This proposed
provision describes additional information requirements for the
emergency-response action plan section of the OSRP for operators
conducting exploratory drilling on the Arctic OCS. Operators would be
required to describe how they would maintain an effective tracking and
management system that is able to locate in real-time all response
equipment and personnel conducting response activities, or transiting
to and from the response site(s), and to maintain a current picture of
resources entering and exiting staging areas and the operational status
of those resources.
xii. IOP Requirements: The proposed rule would require operators
proposing to conduct exploratory drilling operations on the Arctic OCS
to develop an IOP for each proposed exploratory drilling program on the
Arctic OCS, and to submit the IOP to BOEM at least 90 days in advance
of filing an EP.
xiii. Planning Information Requirements to Accompany EPs: This
includes proposed additional information requirements for planning
information that must accompany EPs for operators proposing to conduct
exploration activities in the Arctic OCS Region.
xiv. Industry Familiarization with the New Rule: Assuming the new
regulation takes effect, industry would need to read and interpret the
rule. Through this review, operators would familiarize themselves with
the structure of the new rule and identify any new provisions relevant
to their operations. Operators also would evaluate whether they must
take any new action to achieve compliance with the rule.
Exhibit 2--10-Year Average Annual Costs by Provision (with no
discounting)
------------------------------------------------------------------------
10-year average 1-year average
annual costs: annual costs:
alternative 1 alternative 2
Provision (with 7-day BOP (without 7-day
testing BOP testing
requirement) requirement)
------------------------------------------------------------------------
a. Additional Incident Reporting $5,374 $5,374
Requirements.....................
b. Additional Pollution Prevention $13,585 $13,585
Requirements.....................
c. Additional Requirements for $24,000,000 $24,000,000
Securing Wells...................
[[Page 9952]]
d. Additional BOP Pressure Testing $19,2000,000 $0
Requirements.....................
e. Real-time Monitoring $2,208,000 $2,208,000
Requirements.....................
f. Additional Information $16,771 $16,771
Requirements for APDs............
g. Incorporation of API RP 2N, $9,240 $9,240
Third Edition....................
h. Additional SCCE Requirements... $31,471,823 $31,471,823
i. Relief Rig Requirements........ $55,208,133 $55,208,133
j. Additional Auditing $249,482 $249,482
Requirements.....................
k. Real-time Location Tracking $121,044 $121,044
Requirements.....................
l. IOP Requirements............... $125,167 $125,167
m. Planning Information $28,702 $28,702
Requirements to Accompany EPs....
n. Industry Familiarization with $313 $313
the New Rule.....................
TOTAL......................... $132,657,635 $113,457,635
------------------------------------------------------------------------
We also estimated the costs for Alternative 1, the proposed rule
with the additional BOP pressure testing requirement, and Alternative
2, the proposed rule without the additional BOP pressure testing
requirements. Exhibit 3 summarizes the costs for both alternatives
using discount rates of 3 percent and 7 percent. Alternative 1, the
proposed rule, would result in economic costs of $1.2 billion with 3-
percent discounting and $1.1 billion with 7-percent discounting over 10
years. This estimate assumes the cost associated with staging a standby
relief rig as outlined in Section VI.B.3.(i.e., Relief Rig Capital
Costs.
Exhibit 3--Summary of Monetized Costs \1 2\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Industry costs: Industry costs: Government costs Total costs: Total costs:
alternative 1 alternative 2 ---------------------- alternative 1 alternative 2
Year -------------------------------------------- -------------------------------------------
A B C D = A + C E = B + C
--------------------------------------------------------------------------------------------------------------------------------------------------------
2015...................................... 294,689,955 288,689,955 155,932 294,845,887 288.845,887
2016...................................... 304,631,665 298,631,665 171,956 304,803,620 298,803,620
2017...................................... 35,717,099 23,717,099 162,221 35,879,320 23,879,320
2018...................................... 322,562,375 298,562,375 225,779 322,788,154 298,788,154
2019...................................... 52,406,644 28,406,644 214,296 52,620,941 28,620,941
2020...................................... 62,678,863 38,678,863 172,010 62,850,873 38,850,873
2021...................................... 63,065,863 39,065,863 225,271 63,291,135 39,291,135
2022...................................... 63,129,138 39,129,138 225,271 63,354,409 39,354,409
2023...................................... 62,678,863 38,678,863 172,010 62,850,873 38,850,873
2024...................................... 63,065,863 39,065,863 225,271 63,291,135 39,291,135
Undiscounted 10-year total................ 1,324,626,328 1,132,626,328 1,950,018 1,326,576,346 1,134,576,346
PV 10-year total with 3% discounting...... 1,221,896,314 1,057,816,579 1,701,450 1,223,597,763 1,059,518,028
PV 10-year total with 7% discounting...... 1,110,686,488 975,624,608 1,441,797 1,112,128,285 977,066,405
Annualized with 3% discounting............ 143,243,524 124,008,373 199,462 143,442,986 124,207,835
Annualized with 7% discounting............ 158,136,768 138,906,995 205,279 158,342,048 139,112,275
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Totals might not add because of rounding.
\2\ For explanation of the 3-percent and 7-percent discounting methodology, see n. 2 in Exhibit 24 of the Initial RIA.
5. Benefits
Many of the potential benefits of the proposed rule--based
primarily on preventing or reducing the duration or severity of
catastrophic oil spills--are difficult to quantify. The proposed rule
would benefit society and the environment by reducing the potential for
an incident resulting in an oil spill and, if an incident does occur,
by reducing the duration or severity of the spill. The objective of the
proposed rule is to ensure safe and responsible oil and gas drilling on
the Arctic OCS resulting in increased safety for personnel; protection
of the coastal, human, and marine environments and of species; and
reducing potential conflicts between OCS oil and gas activities and the
Alaska Natives' ability to conduct subsistence activities. The
magnitude of these benefits, however, is uncertain and highly dependent
on the actual reduction in the probability of incidents and the
effectiveness of stopping or containing a spill already underway.
The following break-even analysis describes the reduction in the
duration of a catastrophic oil spill that would be needed to generate
certain quantifiable benefits equal to or greater than the estimated
costs associated with this proposed rule. In addition, because the
probability and length of a catastrophic oil spill would be reduced,
other benefits--beyond what we captured in
[[Page 9953]]
the break-even analyses--would result from the proposed rule. Due to
challenges in measuring these additional benefits, we do not offer a
quantitative assessment of them; instead, we present a qualitative
discussion.
i. Break-Even Analysis: BOEM and BSEE conducted a break-even
analysis of the proposed rule (Alternative 1) because of the
difficulties associated with estimating the benefits of reducing the
probability and consequences of a catastrophic oil spill and the
uncertainty and measurement problems associated with several categories
of benefits.\16\
---------------------------------------------------------------------------
\16\ A catastrophic oil spill is a low-probability, high-
consequence event because it is an event that occurs infrequently,
but has large consequences when it does occur. For such events, it
is difficult to know with any certainty the probability of the event
actually occurring, or to precisely determine the reduction in the
probability of occurrence that a proposed regulation would actually
achieve. In addition, the consequences of an oil spill depend on
several factors, including the type and amount of oil, the location
of the spill, the areal distribution of the release, the sensitivity
of the ecosystem affected, and the weather.
---------------------------------------------------------------------------
For the proposed rule, using the estimated discounted costs at 3
and 7 percent and the potential benefits (in terms of avoided costs of
incidents), we calculated a break-even number of avoided days of
spilled oil if a catastrophic oil spill were to occur. This estimate
reflects the number of avoided days of spilled oil needed for the
proposed rule to achieve at least zero net benefits. Any avoided days
of spilled oil greater than these break-even points result in the
proposed rule's achieving positive net benefits, should a catastrophic
spill occur (i.e., it is cost-beneficial). We also show the estimated
total cost of a catastrophic oil spill relative to the total cost of
the proposed rule. Exhibit 4 presents the total cost of a catastrophic
spill and the 10-year cost of the rule.
Exhibit 4--Total Cost of a Catastrophic Oil Spill Compared to the 10-year Cost of the Rule
----------------------------------------------------------------------------------------------------------------
Cost of a spill ($ millions) 10-year cost of the rule ($
-------------------------------------- millions)
Location -------------------------------------
Low High 7% Discounting 3% Discounting
----------------------------------------------------------------------------------------------------------------
Chukchi Sea......................... $10,074.2 $15,752.6 $1,112 $1,224
Beaufort Sea........................ 12,155.9 27,771.5 1,112 1,224
----------------------------------------------------------------------------------------------------------------
Quantifiable costs of a catastrophic oil spill in the Chukchi Sea
range from $10.07 billion to $15.75 billion and in the Beaufort Sea
from $12.16 billion to $27.77 billion. Thus, quantifiable costs of an
oil spill are more than the cost of the proposed rule; however, the
probability of a catastrophic oil spill is very low. A catastrophic
spill resulting from exploratory drilling on the Arctic OCS, for
example, is considered unlikely due to the nature of the geology,
shallow water depth, and simplicity of the wells. However, due to the
limited drilling history on the Arctic OCS, projections cannot be made
with certainty. Exhibit 5 presents a summary of the results of the
break-even analysis for the proposed rule; a full description of the
results and methodology is contained in the Initial RIA.
Exhibit 5--Break-even Results: Number of Days of Oil Spill Prevented
--------------------------------------------------------------------------------------------------------------------------------------------------------
10-year cost of the rule ($ Break-even number of days
Cost of spill per millions) -------------------------------------
Location day ($ millions) --------------------------------------
7% Discounting 3% Discounting 7% Discounting 3% Discounting
--------------------------------------------------------------------------------------------------------------------------------------------------------
Chukchi Sea.............................................. $177.5 $1,112 $1,224 6.3 6.9
Beaufort Sea............................................. 113.6 1,112 1.224 9.8 10.8
--------------------------------------------------------------------------------------------------------------------------------------------------------
Over the 10-year cost analysis period, the number of avoided/
reduced days of a catastrophic oil spill needed to break-even is
between 6.3 and 6.9 days for the Chukchi Sea and 9.8 and 10.8 days for
the Beaufort Sea. To provide context, the BOEM Case Study estimates
that the duration of a catastrophic incident in the Chukchi Sea could
be between 40 and 75 days and an incident in the Beaufort Sea could be
between 60 and 300 days. One of the key goals of the proposed SCCE and
relief rig provisions is to reduce the duration of such a spill should
one occur.
BOEM and BSEE believe that this break-even analysis is an
appropriate way to evaluate the costs and benefits of the proposed rule
under the circumstances. However, we invite comments on the
assumptions, data, and methods used in this break-even analysis, as
described fully in the Initial RIA. We also invite comments on whether
there is a better alternative method for evaluating the costs and
benefits of the proposed rule.
ii. Qualitative Benefits: Because BOEM and BSEE used a conservative
approach in the valuation of an oil spill in the break-even analysis,
the identified cost of a catastrophic oil spill can be considered a
lower bound of the true cost of such an event to society and of the
potential benefits from preventing such an event. Although the break-
even analysis captures some of the environmental damage associated with
a catastrophic oil spill, the analysis is limited because it only
considers the environmental amenities that researchers could identify
and monetize. Natural resource valuation is complex; many factors
contribute to how society values a resource, including both use and
non-use values of the resources. Many use values can be estimated by
behavior and market transactions (for example, using the harvest value
of yields in the Arctic OCS region). Many other use values, however,
might not be related to a market and are, therefore, difficult to
monetize. For example, Alaska Native communities place a high value on
the cultural amenities related directly to the use of the region.
Because communities do not trade cultural amenities in markets, we are
unable to estimate a direct value of these resources.
Non-use values are much harder to estimate; common non-use values
include existence values and bequest
[[Page 9954]]
values. Individuals place a value on environmental amenities by knowing
that preservation and protection of the region exists even if those
individuals do not intend to visit the region. Bequest values relate to
individuals placing a value on the preservation of regions for future
generations even if they do not intend to use the resource themselves.
For example, many non-native Alaskans, and many other Americans who do
not live in Alaska, place a very high value on protecting the health of
the ecosystem, including the sensitive environment and wildlife, of
this largely frontier area. Thus, the impact of a catastrophic oil
spill, would have extremely high cultural and societal costs, and
prevention of such a catastrophe would have correspondingly high
cultural and societal benefits. Capturing these complex values is
difficult because they are not traded in markets. Because we are unable
to monetize all aspects of the consequences of an oil spill, the
estimate we used in the break-even analysis captures only a portion of
the value to society.
The objective of the proposed rulemaking is to ensure safe and
responsible oil and gas drilling on the Arctic OCS, which would result
in increased safety for personnel, protection of the marine environment
and species, protection of Alaska Natives' cultural values, and removal
of impediments to Alaska Natives' subsistence use. In addition, the
proposed rule achieves better coordination among BSEE, BOEM, and other
government agencies. For example, the information required in proposed
Sec. 550.204 would facilitate interagency coordination between DOI and
other relevant Federal agencies, as recommended in the 60-Day Report.
Exhibit 6 presents the provisions of the proposed rule along with
their primary qualitative benefits, such as improving oversight of
operations by Federal agencies, minimizing natural resource and
ecosystem impacts, reducing the risk of a spill, improving containment
of a spill, and a general benefit.
Exhibit 6--Examples of Qualitative Benefits by Provision
------------------------------------------------------------------------
Provision Primary benefits
------------------------------------------------------------------------
a. Additional Incident Reporting Improves oversight of
Requirements. operations by Federal
agencies.
b. Pollution Prevention Requirements...... Minimizes natural resource
impacts.
c. Additional Requirements for Securing Reduces risk of a spill.
Wells.
d. Additional BOP Pressure Testing Reduces risk of a spill.
Requirements.
e. Real-time Monitoring Requirements...... Reduces risk of a spill.
f. Additional Information Requirements for Improves oversight of
APDs. operations by Federal
agencies.
g. Incorporation of API RP 2N, Third Reduces risk of a spill.
Edition.
h. Additional SCCE Requirements........... Improves containment of a
spill.
i. Relief Rig Requirements................ Improves containment of a
spill.
j. Additional Auditing Requirements....... Improves oversight of
operations by Federal
agencies.
k. Real-time Location Tracking Improves oversight of
Requirements. operations by Federal
agencies.
l. IOP Requirements....................... Reduces risk of a spill.
m. Planning Information Requirements to Improves oversight of
Accompany EPs. operations by Federal
agencies.
n. Industry Familiarization with the New General.
Rule.
------------------------------------------------------------------------
6. Conclusion
The proposed rule would reduce both the overall risk of oil spills
on the Arctic OCS and the consequences of a spill if one were to occur.
We conducted a break-even analysis of the benefits of the proposed
rule. In addition, we included a qualitative discussion of potential
benefits of the proposed rule that could not be quantified or
monetized. The break-even analysis showed that for the Chukchi Sea, a
minimum reduction of 6.3 to 6.9 days for a catastrophic oil spill would
result in a cost-beneficial rule over the 10-year study period. For the
Beaufort Sea, we estimated that a minimum reduction of between 9.8 and
10.8 days for a catastrophic oil spill would result in a cost-
beneficial rule over the 10-year study period.
In addition to the quantifiable benefits, there are significant
qualitative benefits, including protection of Alaska Native
communities' cultural resources and subsistence needs and other
unquantifiable environmental, cultural, and societal benefits.
Accordingly, BOEM and BSEE have determined that the benefits of the
proposed rule justify its potential costs and that it is appropriate to
proceed with this proposed rule.
C.E.O. 13563
E.O. 13563 reaffirms the principles of E.O. 12866 while calling for
improvements in the Nation's regulatory system to promote
predictability, to reduce uncertainty, and to use the best, most
innovative, and least burdensome tools for achieving regulatory ends.
In addition, E.O. 13563 directs agencies to consider regulatory
approaches that reduce burdens and maintain flexibility and freedom of
choice for the public where these approaches are relevant, feasible,
and consistent with regulatory objectives. It also emphasizes that
regulations must be based on the best available science and that the
rulemaking process must allow for public participation and an open
exchange of ideas. We developed this proposed rule in a manner
consistent with these requirements. BOEM and BSEE worked closely with
engineers and technical staff to ensure this rulemaking follows sound
engineering principles and options through research, standards
development, and interaction with industry.
D. Regulatory Flexibility Act
The Regulatory Flexibility Act (RFA), 5 U.S.C. 601-612, requires
agencies to analyze the economic impact of proposed regulations when a
significant economic impact on a substantial number of small entities
is likely and to consider regulatory alternatives that will achieve the
agency's goals while minimizing the burden on small entities. In
addition, the Small Business Regulatory Enforcement Fairness Act of
1996, 5 U.S.C. 601note, requires agencies to produce compliance
guidance for small entities if the rule has a significant economic
impact. For the reasons explained in this section, BOEM and BSEE have
concluded that the proposed rule is likely to have a significant
economic impact on a substantial number of small entities and,
therefore, a regulatory flexibility analysis is required. This Initial
Regulatory Flexibility Analysis assesses the impact of the proposed
rule on small entities, as defined by the applicable Small Business
Administration size standards.
1. Description of the Reasons Why Action by the Agency Is Being
Considered
Although a comprehensive OCS oil and gas regulatory program exists,
DOI engagement with partners and stakeholders reveals the need for new
and revised regulatory measures for exploratory drilling by floating
drilling vessels and ``jackup rigs'' (collectively
[[Page 9955]]
known as MODUs) on the Arctic OCS. The U.S. Arctic region, as
recognized by the U.S. and defined in the U.S. Arctic Research and
Policy Act of 1984, encompasses an extensive marine and terrestrial
area; but this proposed rule focuses solely on the OCS within the
Beaufort Sea and Chukchi Sea Planning Areas.
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, reinforce the need to develop additional measures
specifically tailored to the operational and environmental conditions
of the Arctic OCS. After considering the input provided by various
partners and stakeholders and DOI's direct experience from Shell's 2012
Arctic operations, BOEM and BSEE have concluded that additional
exploratory drilling regulations would enhance and clarify existing
regulations and would be appropriate for a more holistic Arctic OCS oil
and gas regulatory framework.
This proposed rulemaking is intended to ensure that Arctic OCS
exploratory drilling operations are conducted in a safe and responsible
manner that considers the unique conditions of Arctic OCS drilling and
Alaska Natives' cultural traditions and need to access subsistence
resources. The Arctic region is known for its oil and gas resource
potential, its vibrant ecosystems, and the Alaska Native communities.
Extreme environmental conditions, geographic remoteness, and a relative
lack of fixed infrastructure and existing operations characterize the
region. These factors are key in considering the feasibility,
practicality, and safety of conducting offshore oil and gas activities
on the Arctic OCS.
This proposed rule would add to and revise existing regulations in
30 CFR parts 250, 254, and 550 for Arctic OCS oil and gas activities.
The proposed rule would focus on Arctic OCS exploratory drilling
activities that use MODUs and related operations during the Arctic OCS
open-water drilling season. This proposed rule would address several
important issues and objectives, including ensuring that operators:
i. Design and conduct exploration programs in a manner suitable for
Arctic OCS conditions;
ii. Develop an IOP that would address all phases of the proposed
Arctic OCS exploration program and submit the IOP to BOEM at least 90
days in advance of filing the EP;
iii. Have access to and the ability to promptly deploy SCCE, while
drilling below or working below the surface casing;
iv. Have access to a separate relief rig located so that it could
timely drill a relief well, in the event of a loss of well control,
under the conditions expected at the site;
v. Have the capability to predict, track, report, and respond to
ice conditions and adverse weather events;
vi. Effectively manage and oversee contractors; and
vii. Develop and implement OSRPs designed and executed in a manner
suitable for the unique Arctic OCS operating environment and have the
necessary equipment, training, and personnel for oil spill response on
the Arctic OCS.
The proposed rule would further the Nation's interest in exploring
frontier areas, such as those in the Arctic region, and would establish
specific operating models and requirements for the extreme, changing
conditions that exist on the Arctic OCS. The proposed regulations would
require comprehensive planning of operations, especially for emergency
response and safety systems. The proposed rule would seek to
institutionalize a proactive approach to offshore safety. A goal of the
proposed rule is to identify possible vulnerabilities early in the
planning process so that corrections can be made to decrease the
potential for an incident occurring. The requirements in the proposed
rule also are designed to ensure that those plans would be executed in
a safe and environmentally protective manner, despite the challenges
the Arctic presents.
2. We identified the following provisions of the proposed rule as
having a cost to industry:
i. Additional incident reporting requirements;
ii. Pollution prevention requirements;
iii. Additional requirements for securing wells;
iv. Additional BOP pressure testing requirements;
v. Real-time monitoring requirements;
vi. Additional information requirements for APDs;
vii. Incorporation of proposed draft API RP 2N;
viii. Additional SCCE requirements;
ix. Relief rig requirements;
x. Additional auditing requirements;
xi. Real-time location tracking requirements;
xii. IOP requirements;
xiii. Additional requirements for EPs; and
xiv. Industry familiarization with the rule.
3. Succinct Statement of the Objectives of, and Legal Basis for, the
Proposed Rule
The objectives and legal basis are described in part II,
Background, of the proposed rule.
4. Description of and, Where Feasible, an Estimate of the Number of
Small Entities to Which the Proposed Rule Will Apply
The RFA defines small entities as small businesses, small
nonprofits, and small governmental jurisdictions. We have identified no
small nonprofits or small government jurisdictions that the proposed
rule would impact, so this analysis focuses on impacts on small
businesses (hereafter referred to as ``small entities''). A small
entity is one that is ``independently owned and operated and which is
not dominant in its field of operation.'' \17\ The definition of small
business varies from industry to industry to capture industry size
differences properly.
---------------------------------------------------------------------------
\17\ See 5 U.S.C. 601.
---------------------------------------------------------------------------
The proposed rule would affect operators and holders of Federal oil
and gas leases that could conduct exploratory drilling on the Arctic
OCS. According to BOEM's list of leaseholders on the Arctic OCS as of
May 2014, 10 businesses hold leases on the Arctic OCS.\18\ Three of
these businesses are anticipated to conduct exploratory drilling on the
Arctic OCS over the next 10 years, although any business holding a
lease could conduct exploratory drilling on the Arctic OCS and would
thus be subject to the requirements of this proposed rule.
---------------------------------------------------------------------------
\18\ See www.boem.gov/uploadedFiles/BOEM/About_BOEM/BOEM_Regions/Alaska_Region/Leasing_and_Plans/Leasing/Alaska_Lease_Holdings_by_Owner_or_Partial_Owner.pdf.
---------------------------------------------------------------------------
Businesses subject to this rule fall under North American Industry
Classification System codes 211111 (Crude Petroleum and Natural Gas
Extraction) and 213111 (Drilling Oil and Gas Wells). For these
classifications, a small business is defined as one with fewer than 500
employees. Based on this criterion, only one business currently holding
a Federal oil and gas lease on the Arctic OCS is considered small.
Although BOEM and BSEE do not expect a small entity to conduct
exploratory drilling on the Arctic OCS during the 10-year analysis
period, any business holding a lease could operate on the Arctic OCS.
Using the number of businesses holding such leases as the universe
subject to this rule, 10 percent (1 of 10) of the firms are considered
small. Thus, the proposed rule would affect a ``substantial number'' of
small
[[Page 9956]]
entities, defined by BOEM and BSEE as 10 percent or more of the
potentially affected entities. Thus, although we do not expect that a
small entity would conduct exploratory drilling during the analysis
period, to be conservative, we have conducted this RFA analysis to
demonstrate the likely effects the proposed rule would have on a
hypothetical small operator.
5. Description of the Projected Reporting, Recordkeeping and Other
Compliance Requirements of the Proposed Rule, Including an Estimate of
the Classes of Small Entities That Will Be Subject to the Requirement
and the Type of Professional Skills Necessary for Preparation of the
Report or Record
BOEM and BSEE have estimated the incremental costs for small oil
and gas leaseholders that decide to engage in exploratory drilling on
the Arctic OCS. This analysis reflects only costs associated with
activities and capital investments required by the proposed rule that
represent a change from the baseline. The baseline for this proposed
rule includes existing regulations, standard industry practices,
operator prudence, and assumptions based on requirements for Shell's
2012 Arctic OCS operations that were imposed by BOEM or BSEE under
their existing regulatory authorities.\19\ Cost estimates included in
this analysis for the provisions of the proposed rule are those
presented in detail in the Initial RIA.
---------------------------------------------------------------------------
\19\ See the Initial RIA for the proposed rule for details on
baseline assumptions. We state all costs in 2012 constant dollars.
---------------------------------------------------------------------------
i. Total Cost Estimates by Provision
BOEM and BSEE assessed the costs associated with the proposed
regulation by estimating the cost for a hypothetical small operator. We
assumed that this operator would conduct an exploratory drilling
program with one rig, two wells, two APDs, and one OSRP, IOP, and EP
each. For each provision, we estimated the per-rig, per-well/APD, per-
OSRP, per-IOP, and per-EP cost, where applicable. Following is a
summary of the unit costs using the estimates developed in the RIA.\20\
Please refer to the Initial RIA for details on the cost estimates.
---------------------------------------------------------------------------
\20\ Totals might not add because of rounding.
---------------------------------------------------------------------------
For the incident reporting activities, we estimated the per-rig
cost at $1,146, including both the costs for ice movement activity oral
reports ($313 per rig) and the costs associated with written reports
($834 per rig). For the pollution prevention requirements, we estimated
the costs per rig to capture and transport mud and cuttings to be
$4,245. For the additional requirements for securing wells, we included
both the capital costs ($2,000,000) and the labor and operational costs
($3,000,000) for a total per-well cost of $5,000,000.
We assessed the costs for Alternative 1 (the proposed rule with the
additional BOP pressure-testing requirements) and Alternative 2 (the
proposed rule without the additional BOP pressure-testing
requirements). For the additional BOP pressure-testing requirements
included under Alternative 1, BSEE included the per-rig labor cost of
$6,000,000. These costs are not included in the cost estimates for
Alternative 2. (See Section 6 following for details on the
alternatives.) For the proposed real-time monitoring requirements, we
estimated a per-rig labor cost of $690,000. For the proposed additional
information requirements for the APDs, we estimated a per-rig labor
cost of $1,491 and a per-well labor cost of $1,305. For the proposed
incorporation of draft API RP2N, Third Edition, we estimated a per-rig
labor cost of $1,918. For the enhanced auditing requirements, we
estimated a per-rig labor cost of $129,000. For the proposed real-time
tracking requirements, we estimated a per-OSRP labor cost of $401.
In addition, we included a cost of $102,624 ($63,274 upfront cost
plus $39,350 annual cost) per rig to account for the purchase,
operation, and maintenance of an Automatic Identification System (AIS)
as an example of costs to comply with the real-time tracking
requirements for oil spill response resources.\21\ For the proposed IOP
requirements, we estimated a per-IOP labor cost of $8,633. For the
proposed planning information requirements to accompany the EPs, we
estimated a per-EP labor cost of $4,316. Finally, we estimated a per-
operator cost of $1,042 for the time needed for an operator to become
familiar with the rule.
---------------------------------------------------------------------------
\21\ As explained in the initial RIA, proposed Sec. 254.80(c)
does not require any specific real-time tracking system, so we used
AIS as a representative system for costs analysis purposes.
---------------------------------------------------------------------------
The proposed SCCE requirements have several different cost
components for both rigs and wells. We estimated a one-time capital
cost per rig of $270,000,000 and an annual redeployment cost of
$1,200,000 per rig. For the aggregate cost of the SCCE, we varied the
assumptions for purchase and redeployment costs based on whether the
operator purchases the equipment or engages in resource sharing, as
discussed later. For the Regional Supervisor-initiated tests, we
estimated a per-rig cost of $500,000. For the stump tests, we assumed
that the operator would use a pre-positioned capping stack (PPCS) and
estimated that each PPCS stump test costs $160,208 per well. We assumed
one stump test before installation on each well and one stump test
before deployment. Although the operator could instead use a dry-stored
capping stack, we conservatively assumed that the operator would use a
PPCS, which results in higher costs. For the proposed information
requirements for the well design change, we estimated a per-well labor
cost of $959. We also estimated a per-well labor cost of $1,174 to
maintain the SCCE records and a per-well labor cost of $5,755 for the
APD documents. The total SCCE requirements sum to $271,700,000 per rig
and $328,305 per well.\22\
---------------------------------------------------------------------------
\22\ These totals are derived, respectively, as follows:
($270,000,000 + $1,200,000 + $500,000) and ($160,208 + $160,208 +
$959 + $1,174 + $5,755).
---------------------------------------------------------------------------
For the proposed relief rig requirements, we included the costs
associated with the proposed information documentation requirements for
the relief rig. We estimated the labor cost associated with the
documentation requirements for the relief rig to be $14,591 per rig. As
discussed in the Initial RIA, we do not include costs associated with
the proposed 45-day maximum limit on the time necessary to complete the
required relief rig activities under Section 250.472 because we lack
information regarding potential costs, if any, above the baseline that
might accrue from the cessation of drilling or other work below the
surface casing under this proposed requirement.
We present the least-cost means to comply with the proposed rule,
and thus assume that a small entity would not incur the costs of a
standby relief rig and would enter into a resource sharing agreement to
comply with the relief rig requirements. If, however, a small entity
chooses to deploy a dedicated standby relief rig to comply with
regulatory requirements, it could incur costs of approximately $276
million per rig, per season.
Exhibit 7 presents the unit costs per provision for a small
operator. These estimates include the full cost of the proposed SCCE
requirements, assuming no resource sharing with another operator, and
costs associated with the enhanced BOP pressure testing requirements
under Alternative 1.
[[Page 9957]]
Exhibit 7--Unit Cost of the Proposed Rule by Provision (with No Resource Sharing)
----------------------------------------------------------------------------------------------------------------
Cost per operator
Provision Cost per rig Cost per well/APD (EP/IOP/OSRP)
----------------------------------------------------------------------------------------------------------------
a. Additional Incident Reporting Requirements. $1,146 .................... ....................
b. Pollution Prevention Requirements.......... 4,245 .................... ....................
c. Additional Requirements for Securing Wells. .................... 5,000,000 ....................
d. Additional BOP Pressure Testing 6,000,000 .................... ....................
Requirements.................................
e. Real-time Monitoring Requirements.......... 690,000 .................... ....................
f. Additional Information Requirements for 1,491 1,305 ....................
APDs.........................................
g. Incorporation of draft API RP 2N, Third Ed. 1,918 .................... ....................
h. Additional SCCE Requirements............... 271,700,000 328,305 ....................
i. Relief Rig Requirements.................... 14,591 .................... ....................
j. Additional Auditing Requirements........... 129,000 .................... ....................
k. Real-time Location Tracking Requirements... 102,624 .................... 401
l. IOP Requirements........................... .................... .................... 8,633
m. Planning Information Requirements to .................... .................... 4,316
Accompany Eps................................
n. Industry Familiarization with the New Rule. .................... .................... 1,042
-----------------------------------------------------------------
Total Annual Cost Per Rig/Well/Operator 278,645,016 5,329,610 14,393
\1\......................................
----------------------------------------------------------------------------------------------------------------
\1\ Totals might not add because of rounding.
ii. Total Cost Burden for Small Entities
We calculated the cost to a single small operator under different
alternatives and differing assumptions regarding resource sharing of
the SCCE. We assumed that the SCCE purchase cost would be $270,000,000
and the annual redeployment cost would be $1,200,000.
We estimated the highest-cost scenario for a small operator to
present the most conservative estimate possible of the potential for a
significant economic impact. Under this highest-cost scenario, the
small operator would need to purchase and deploy the SCCE (i.e., no
resource sharing) and would be subject to the additional BOP pressure-
testing requirements under Alternative 1. We also estimated the costs
of Alternative 2 (i.e., no additional BOP pressure-testing
requirements) assuming no resource sharing of SCCE. Under the lowest-
cost scenario, the small operator would employ resource sharing of SCCE
and would not be subject to the additional BOP pressure-testing
requirements (as in Alternative 2). We also estimated the costs of
Alternative 1 assuming resource sharing of SCCE.
Next, we estimated the average annual revenue of an affected small
operator. We used an annual revenue estimate of $45.7 million for the
small operator as calculated in the final RIA for BSEE's ``Oil and Gas
and Sulphur Operations on the Outer Continental Shelf: Oil and Gas
Production Safety Systems'' rulemaking (77 FR 50856, Aug. 22,
2012).\23\ We used this estimate of average annual revenue to calculate
the ratio of total costs of the proposed rule as a percentage of
average annual revenue to determine if the proposed rule would result
in a significant economic impact on small entities.
---------------------------------------------------------------------------
\23\ See 77 FR 50856 (August 22, 2012). The final RIA for that
rulemaking can be viewed at www.regulations.gov/#!documentDetail;D=BSEE-2012-0002-0047. The data in the source
document are from the Office of Natural Resources Revenue. The data
source reports the total 2009 small business revenue to be
$4,113,000,000. We calculated the average revenue per small business
by dividing the total small business revenue by the number of small
businesses ($4,113,000,000/90) to obtain an average of $45,700,000
per operator.
---------------------------------------------------------------------------
Exhibit 8 presents estimates of the total first-year costs to a
small operator under each scenario and the total first-year costs as a
percentage of average annual revenue. Under all scenarios, the first-
year costs as a percentage of revenue surpass the 1-percent threshold
used to define a significant economic impact. Even under the lowest-
cost scenario, assuming that the operator would engage in resource
sharing of the SCCE and would not be subject to the additional BOP
pressure-testing requirements (as in Alternative 2), the small operator
would experience a total first-year cost equal to 29 percent of their
average annual revenue. For the scenarios that assume no resource
sharing of SCCE, the total first-year costs as a percentage of revenue
are greater than 100 percent, indicating that the total first-year
costs the small operator would experience would be greater than its
total average annual revenue.\24\
---------------------------------------------------------------------------
\24\ As stated earlier, BOEM and BSEE do not expect an actual
small operator to conduct exploratory drilling on the Arctic OCS
during the 10-year period of this analysis, although we have
prepared this analysis to be conservative (since one current Arctic
OCS lessee is a small entity). Thus, this analysis considers the
average annual revenue of small OCS operators.
Exhibit 8--First-year Costs as a Percentage of Average Annual Revenue
per Operator
------------------------------------------------------------------------
Total first-year Total first-year
cost cost as percent of
Scenario ---------------------- revenue
---------------------
A B = A/$45.7 million
------------------------------------------------------------------------
Alternative 1 with No $289,318,628 633
Resource Sharing of SCCE...
Alternative 2 with No 283,318,628 620
Resource Sharing of SCCE...
Alternative 1 with Resource 19,318,628 42
Sharing of SCCE............
Alternative 2 with Resource 13,318,628 29
Sharing of SCCE............
------------------------------------------------------------------------
Exhibit 9 presents estimates of the total annual ongoing costs (the
costs in the second year and after) to a small operator under each
scenario, or the costs incurred on an annual basis after, and not
including, the first-year of the
[[Page 9958]]
analysis period. Exhibit 9 also presents the total annual ongoing costs
as a percentage of average annual revenue. Under all scenarios, the
annual ongoing costs as a percentage of revenue surpass the 1-percent
threshold used to define a significant economic impact. Under
Alternative 1, a small operator would experience total annual ongoing
costs equal to 42 percent of their average annual revenue, and under
Alternative 2, total annual ongoing costs to small operators would be
equal to 29 percent of average annual revenue. Costs after the first
year do not vary based on SCCE resource-sharing assumptions because we
assumed that SCCE capital costs (if any) would be incurred in the first
year.
BOEM and BSEE conclude that the proposed rule would have a
``significant economic impact'' on small operators because costs are
greater than 1 percent of revenue in every year of the analysis period.
Although costs are anticipated to be lower for operators after the
first year, during which the operator is assumed to purchase capital
equipment, annual costs are still estimated to be well above the 1-
percent threshold in the subsequent years of the 10-year analysis
period.
Exhibit 9--Annual Ongoing Costs as a Percentage of Average Annual
Revenue per Small Operator
------------------------------------------------------------------------
Total annual ongoing Total annual ongoing
cost cost as percent of
Scenario ---------------------- revenue
---------------------
A B = A/$45.7 million
------------------------------------------------------------------------
Alternative 1 with No $19,125,311 42
Resource Sharing of SCCE...
Alternative 2 with No 13,125,311 29
Resource Sharing of SCCE...
Alternative 1 with Resource 19,125,311 42
Sharing of SCCE............
Alternative 2 with Resource 13,125,311 29
Sharing of SCCE............
------------------------------------------------------------------------
The conclusion that the rule would have a ``significant economic
impact'' on small operators is based on past revenue of operators and
does not account for any potential increase in revenue that operators
might experience if Arctic OCS exploratory drilling operations lead to
production. Operators conducting exploratory drilling on the Arctic OCS
that experience a significant, economically viable discovery of oil or
natural gas and that proceed to the production phase could experience a
significant increase in revenue. Thus, the analysis presented in this
section could understate the revenue, resulting in an overstatement of
the impact of the rule when expressed as the ratio of costs to annual
revenue.\25\
---------------------------------------------------------------------------
\25\ Conversely, oil and gas exploration has inherent financial
risk in that the exploration activities might not yield an
economically viable discovery of oil or natural gas.
---------------------------------------------------------------------------
6. Identification of All Relevant Federal Rules That May Duplicate,
Overlap, or Conflict With the Proposed Rule
The proposed rule does not conflict with any relevant Federal rules
or duplicate or overlap with any Federal rules in any way that would
unnecessarily add cumulative regulatory burdens on small entities
without any gain in regulatory benefits.\26\ However, BOEM and BSEE
request comments identifying any Federal rules that may duplicate,
overlap, or conflict with the proposed rule.
---------------------------------------------------------------------------
\26\ The proposed revision to 30 CFR 250.300(b) that would
prohibit the discharge of petroleum-based mud and associated
cuttings may overlap with existing EPA general permits for the
Beaufort and Chukchi Seas under the National Pollution Discharge
Elimination System regulations (40 CFR part 122) while those permits
remain in effect. However, the proposed rule would not add any
regulatory burden to any small entity in that regard.
---------------------------------------------------------------------------
7. Description of Significant Alternatives to the Proposed Rule
Several provisions of the proposed rule are performance based,
which will enable operators to devise optimal strategies for reducing
the cost burden of the proposed rule. In addition, operators might be
able to reduce costs through resource sharing. BOEM and BSEE strongly
encourage operators proposing exploratory drilling activities on the
Arctic OCS to enter into mutual aid agreements for the sharing of
vessels, relief well rigs, and other assets or services associated with
responding to an oil spill or other emergency.
BOEM and BSEE have considered three major regulatory alternatives
for dealing with the safety and environmental concerns raised by
exploration activities on the Arctic OCS:
i. Promulgate the rule changes proposed in this proposed rule for
the Arctic OCS; or
ii. Promulgate the rule changes described in the proposed rule
without including the 7-day BOP pressure-testing requirement for Arctic
OCS exploratory drilling operations (in Sec. 250.447 of the proposed
rule); or
iii. Take no regulatory action and continue to rely on existing OCS
oil and gas regulations, industry standards, and operator prudency.
BSEE has decided not to issue a proposed rule without the 7-day BOP
testing requirement. Although maintaining the testing frequency at 14
days would reduce the total costs of the proposed rule, the additional
testing requirement is intended to help ensure that BOPs deployed in
the Arctic OCS function properly and reduce the risk of blowouts.
BOEM and BSEE also have decided to move forward with this proposed
rule, in lieu of taking no regulatory action, because relying on the
regulatory status quo would not address the safety and environmental
concerns partners and stakeholders have raised and thus would not
achieve the objectives of this proposed rule. In addition, the proposed
rule would confer additional protections on the environment and Alaska
Native cultural activities. Further, the projected potential for
impacts on small entities is mitigated by the fact that the agencies do
not anticipate any small entity independently pursuing exploration
drilling on the Arctic OCS during the 10-year analysis period.
E. Unfunded Mandates Reform Act of 1995 (UMRA)
This proposed rule would not impose an unfunded Federal mandate on
State, local, or tribal governments but would, if finalized, create a
Federal private sector mandate that could require expenditures
exceeding $100 million in a single year by offshore oil and gas
exploration companies operating on the Arctic OCS. Accordingly, DOI has
prepared written statements satisfying the applicable requirements of
the UMRA, 2 U.S.C. 1501 et seq. Those requirements are addressed in the
Initial RIA and initial RFA analyses for this proposed rule and in the
proposed rule itself.
Among other things, the proposed rule, Initial RIA, and/or Initial
RFA:
[[Page 9959]]
1. Identify the provisions of Federal law (OCSLA, CWA, and OPA)
under which this rule is being proposed;
2. Include a quantitative assessment of the anticipated costs to
the private sector (i.e., expenditures on labor and equipment) of the
proposed rule; and
3. Include qualitative and quantitative assessments of the
anticipated benefits of the proposed rule.
Since all of the anticipated expenditures by the private sector
analyzed in the Initial RIA and the Initial RFA analyses would be borne
by the offshore oil and gas exploration industry in the Arctic region,
the Initial RIA and Initial RFA analyses satisfy the UMRA requirement
to estimate any disproportionate budgetary effects of the proposed rule
on a particular segment of the private sector (i.e., the offshore oil
and gas industry).
As discussed in the Regulatory Planning and Review section of this
proposed rule, and explained fully in the Initial RIA, BOEM and BSEE
considered three major regulatory alternatives for dealing with the
safety and environmental concerns raised by exploration activities on
the Arctic OCS. BOEM and BSEE have decided to move forward with this
proposed rule, in lieu of the other alternatives, because those
alternatives would not as efficiently or effectively address the
safety, environmental or sociocultural concerns raised by various
stakeholders on the Arctic OCS or achieve the objectives of this
proposed rule.
BOEM and BSEE have determined that the proposed rule would not
impose any unfunded mandates or any other requirements on State, local
or tribal governments; thus, the proposed rule would not have
disproportionate budgetary effects on such governments. Assuming,
however, that the proposed rule might result in budgetary effects on
the Arctic region, BOEM and BSEE have determined that it is not
practical to accurately estimate such effects. Since the proposed rule
would not impose any requirements on any entities, other than companies
and their contractors engaged in Arctic OCS exploration activities, any
budgetary effects in that area would be at least indirect, secondary
results of actions or decisions taken by regulated (or unregulated)
entities, based on a variety of circumstances (such as the price of
oil, each entity's overall financial health, and the prospects of
success of any exploratory drilling). Because each of those factors is
variable and unpredictable, it is not practical to estimate how those
factors might affect an entity's future decisions, or what indirect
impacts, if any, such decisions could have on future regional budgets.
Similarly, BOEM and BSEE have determined that it is not reasonably
feasible to accurately estimate the potential effects, if any, of the
proposed rule on the National economy (e.g., productivity, economic
growth, employment, international competitiveness). The proposed rule,
if finalized, would only affect exploratory drilling activities on the
Arctic OCS, and any potential impact on the National economy would
depend on individual business decisions made by regulated entities
(e.g., whether or not to hire new employees). Moreover, any such
decisions would likely be either local or regional in effect and
unlikely to have any significant National economic impacts.
F. Takings Implication Assessment
Under the criteria in E.O. 12630, this proposed rule would not have
significant takings implications. The proposed rule is not a
governmental action capable of interference with constitutionally
protected property rights. A Takings Implication Assessment is not
required.
G. Federalism (E.O. 13132)
Under the criteria in E.O. 13132, this proposed rule would not have
federalism implications. This proposed rule would not substantially and
directly affect the relationship between the Federal and State
governments. To the extent that State and local governments have a role
in OCS activities, this proposed rule would not affect that role. A
Federalism Assessment is not required.
H. Civil Justice Reform (E.O. 12988)
This proposed rule complies with the requirements of E.O. 12988.
Specifically, this rule:
1. Meets the criteria of Sec. 3(a) requiring that all regulations
be reviewed to eliminate errors and ambiguity and be written to
minimize litigation; and
2. Meets the criteria of Sec. 3(b)(2) requiring that all
regulations be written in clear language and contain clear legal
standards.
I. Consultation With Indian Tribes (E.O. 13175)
Under the criteria in E.O. 13175, Consultation and Coordination
with Indian Tribal Governments (dated November 6, 2000), DOI's Policy
on Consultation with Indian Tribes (Secretarial Order 3317, Amendment
2, dated December 31, 2013), and the Alaska Native Corporation
Consultation Policy (dated August 12, 2012), we evaluated and
determined that the subject matter of this rulemaking would have tribal
implications for Alaska Natives. As described earlier, future Arctic
OCS exploratory drilling activities conducted pursuant to this proposed
rule could affect Alaska Natives, particularly their ability to engage
in subsistence and cultural activities.
BOEM and BSEE are committed to regular and meaningful consultation
and collaboration with tribes on policy decisions that have tribal
implications including, as an initial step, through complete and
consistent implementation of E.O. 13175, together with related orders,
directives, and guidance. Therefore, BOEM and BSEE, in coordination
with the Office of the Secretary of the Interior's Senior Alaska
Representative, engaged in listening sessions, 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 proposed rule.
Government-to-Government consultation was held in Barrow between
BOEM, BSEE, and the ICAS on June 6, 2013, to both provide background to
and obtain information from ICAS leaders and council members. The
following day, June 7, 2013, BOEM and BSEE met with leaders and council
members of the Native Village of Barrow in a separate Government-to-
Government consultation. All Alaska Native input provided during the
meetings was subsequently provided to DOI in writing and has been
included in the administrative record for this proposed rule.
BOEM and BSEE also held public listening sessions in South-central
Alaska (Anchorage) and on the North Slope (Barrow) on June 6 and 7,
2013. The BOEM Alaska Region notified Alaska Native Tribes and ANCSA
Corporations of the June 6 and 7, 2013, public listening sessions and
Government-to-Government consultations through phone calls, emails,
newspaper announcements, and BOEM's Web site.
A series of follow-on meetings and listening sessions were held
June 17-20, 2013, in Anchorage resulting, in part, in Government-to-
Government consultation between BOEM, BSEE, and the Native Village of
Nuiqsut and Government-to-ANCSA Corporation consultations between BOEM,
BSEE, and the NANA Regional Corporation and the Cully Corporation
(ANCSA Village Corporation) from Point Lay.
[[Page 9960]]
Among the most frequent input DOI received through listening
sessions and tribal consultation were comments relating to impacts on,
and protection of, subsistence hunting and fishing areas and species,
including consideration of mammal and fish migratory patterns, hunting
and fishing seasons, and impacts of pollutants and equipment movements.
Concerns also included the relative lack of infrastructure, such as
roads, housing, and equipment, in coastal communities near proposed
Arctic OCS oil and gas exploration areas, and inclusion of local Alaska
Natives in monitoring and other activities. Commenters also requested
that we incorporate traditional knowledge of the Arctic OCS into our
decision-making for proposed regulations. We reviewed all comments
received to date and have, where appropriate, crafted proposed measures
to address Alaska Native concerns. DOI intends to continue consultation
with affected tribes and ANCSA Corporations following publication of
the proposed rule.
J. E.O. 12898
E.O. 12898 requires Federal agencies to make achieving
environmental justice part of their mission by identifying and
addressing disproportionately high and adverse human health or
environmental effects of their programs, policies, and activities on
minority populations and low-income populations in the U.S. DOI has
determined that this proposed rule does not have a disproportionately
high or adverse human health or environmental effect on native,
minority, or low-income communities because its provisions are designed
to increase environmental protection and minimize any impact of
exploration drilling on subsistence hunting activities and Alaska
Native community resources and infrastructure.
K. Paperwork Reduction Act (PRA)
This rule contains new information collection (IC) requirements for
both BOEM and BSEE regulations, and a submission under the PRA is
required. Therefore, an IC request for each Bureau is being submitted
to OMB for review and approval under 44 U.S.C. 3501 et seq. The PRA
provides that an agency may not conduct or sponsor, and a person is not
required to respond to, an IC unless it displays a currently valid OMB
control number. The IC aspects affecting each Bureau are discussed
separately. Instructions on how to comment follow those discussions.
BOEM Information Collection--30 CFR Part 550
This proposed rule adds new requirements for submitting EPs and
other information before conducting oil and gas exploration drilling
activities on the Arctic OCS. The title of the collection for the
rulemaking is 30 CFR 550, Subpart B, Arctic OCS Activities--New. The
burdens for the current planning requirements under 30 CFR 550, Subpart
B, regulations are approved by OMB under Control Number 1010-0151
(190,480 hours, $3,713,665 non-hour costs; expiration 12/31/14; current
collection can be viewed at www.reginfo.gov/public/). When final
regulations become effective, the new IC burdens for this rulemaking
will be consolidated into the existing collection for Subpart B.
Respondents for this rulemaking are Federal oil, gas, or sulphur
lessees and/or operators on the Arctic OCS. Submissions are mandatory
and generally on occasion. BOEM collects the information to ensure that
planned operations will be safe; will not adversely affect the marine,
coastal, or human environments; will respond to the special conditions
on the Arctic OCS; and will conserve the resources of the Arctic OCS.
BOEM uses the information to ensure, through advanced planning, that
operators are capable of safely operating in the unique environmental
conditions of the Arctic and to make informed decisions on whether to
approve EPs as submitted or whether modifications are necessary. BOEM
also plans to share the preliminary information submitted in the IOP
with other relevant agencies to provide them the opportunity to engage
in constructive dialogue/feedback with operators, and each other, early
in the process.
The proposed rule adds new requirements under Sec. 550.204 for
operators to develop an IOP for each exploratory drilling program on
the Arctic OCS, and to submit it to BOEM at least 90 days in advance of
filing their EP. The IOP addresses all phases of the operator's
proposed Arctic exploration drilling activities at a strategic or
conceptual level, showing how operations will be designed, executed,
and managed as an integrated endeavor from start to finish.
The proposed rule also revises the IC for plans submission by
expanding the requirements under Sec. 550.220 to address the specific
conditions (e.g., ice management procedures) associated with oil and
gas activity on the Arctic OCS. The rule provisions are intended to
ensure that operators on the Arctic OCS design and conduct their
exploration drilling activities in a manner suitable for the area's
unique conditions.
BOEM estimates that the new requirements will add a total of 270
burden hours to the already approved burdens for plans. Because not all
EPs submitted to BOEM will involve Arctic OCS exploration drilling, we
are separating the Arctic-specific requirements and burdens from the
national EP requirements. The burden table that follows this paragraph
outlines the new and expanded requirements and burdens associated with
this rulemaking. BOEM has not identified any non-hour cost burdens
associated with these requirements.
Burden Breakdown
----------------------------------------------------------------------------------------------------------------
Average
Reporting & Recordkeeping number of Burden
Citation 30 CFR Part 550 Subpart B Requirement Hour burden annual hours
responses
----------------------------------------------------------------------------------------------------------------
Arctic Integrated Operations Plan (IOP)
----------------------------------------------------------------------------------------------------------------
New 204\1\................................ For New Arctic OCS 90 2 180
Exploration Activities:
Submit IOP, including all
required information.
----------------------------------------------------------------------------------------------------------------
Contents of Exploration Plans (EP)
----------------------------------------------------------------------------------------------------------------
206....................................... General requirements for Burdens already covered 0
220....................................... plans.. under plans in 1010-
Submit Alaska-specific 0151.
information..
--------------------------
[[Page 9961]]
Expanded 220.............................. For New Arctic OCS 15 2 30
Exploration Activities:
Submit required Arctic-
specific information with
EP, including confirmations.
Expanded 220.............................. For Existing Arctic OCS 30 2 60
Exploration Activities:
Revise and resubmit Arctic-
specific information, as
required.
--------------------------------------
Total Burden for Proposed Rule........ ............................. ........... 6 270
----------------------------------------------------------------------------------------------------------------
\1\ Industry already compiles this information internally for planning and contract oversight; therefore, the
burden expected is minimal, just to prepare and submit to BOEM.
BSEE Information Collection--30 CFR Parts 250 and 254
The title of the collection of information for this rule is 30 CFR
part 250, subparts A, D, S and 30 CFR part 254, Arctic Oil & Gas
Exploratory Drilling Operations--New. The proposed regulations
establish requirements for safe, responsible, and environmentally
protective Arctic OCS oil and gas exploration, and the information is
used in our efforts to protect life and the environment, conserve
natural resources, and prevent waste.
Potential respondents comprise Federal OCS oil, gas, and sulphur
operators and lessees on the Arctic OCS. The frequency of response
varies depending upon the requirement. Responses to this collection of
information are mandatory; they are submitted on occasion, annually, or
as a result of situations encountered, depending upon the requirement.
The IC does not include questions of a sensitive nature. BSEE will
protect proprietary information according to the Freedom of Information
Act (5 U.S.C. 552) and DOI's implementing regulations (43 CFR part 2),
30 CFR part 252, and 30 CFR 250.197, which address disclosure of data
and information to be made available to the public.
As discussed earlier in the preamble, the proposed rule encompasses
multiple subparts and focuses on Arctic OCS exploratory drilling
activities and related operations. This proposed rule revises several
existing collections under BSEE regulations. The requirements and
burdens for these regulations are currently approved by OMB under 30
CFR part 250, subpart A, 1014-0022, expiration 8/3/2017 (84,391 hours,
$1,371,458 non-hour cost burdens); subpart D, 1014-0018, expiration 10/
31/17 (102,512 hours); subpart S, 1014-0017, expiration 3/31/16
(651,728 hours, $9,444,000 non-hour cost burdens); and 30 CFR part 254,
1014-0007, expiration 12/31/2015 (60,198 hours); current collections
can be viewed at www.reginfo.gov/public/. When final regulations are
promulgated, the new IC burdens for these subparts/parts will be
incorporated into the respective collections of information for those
regulations.
The following table provides a breakdown of the paperwork and non-
hour cost burdens for this proposed rule. For the current requirements
retained in the proposed rule, we used the OMB approved estimated hour
and non-hour cost burdens, where discernible. However, there are
several new requirements in the proposed rule as follows:
1. Subpart A:
In Sec. 250.188(c), we have added immediate oral reporting of
anysea ice movement/conditions, start and termination of ice management
activities, or kicks or unexpected operational issues, and submission
of a written report within 24 hours after completing ice management
activities (+11 hours).
2. Subpart D:
In Sec. 250.452(a) and (b), we have added real-time data
gathering, monitoring, and storing related to the BOP control system,
fluid handling, and downhole conditions, etc.; notify BSEE of location
of data; make data available to BSEE upon request (+288 hours).
In Sec. 250.470, we have added information requirements including,
but not limited to, detailed descriptions of: Environmental,
meteorologic, and oceanic conditions expected at well site(s), and, how
drilling units and equipment will be prepared for service;
transitioning rig from being underway to drilling and vice versa, along
with anticipated repair and maintenance plans; specific drilling
objectives, timelines, and updated contingency plans for temporary
abandonment; weather and ice forecasting and management; compliance
with relief well rig requirements; SCCE capabilities, including, but
not limited to, submit equipment statement showing capable of
controlling WCD, explanation of your or your contractor's SCCE
capabilities; inventory of supplies and services, along with relevant
supplier information; proof of contracts or membership agreements to
provide SCCE or supplies, services; description of procedures for
inspecting, testing, and maintaining SCCE; how all personnel operating
SCCE received training to deploy and operate--including dates of prior
and planned training; and how the operator incorporated API RP 2N,
Third Edition, into its planned drilling operations (+324 hours).
In Sec. 250.471(c), (e), and (f), we propose to add requirements
that operators: Submit a reevaluation of SCCE capabilities, including
any new WCD rate, and demonstrate compliance with proposed Sec.
250.470(f); maintain all SCCE inspection and maintenance records for at
least 10 years; make records available to BSEE upon request; maintain
all records relating to use of SCCE during testing, training, and
deployment activities for at least 3 years; and make records available
to BSEE upon request (+100 hours).
In Sec. 250.472(c), we propose to add a provision stating that
operators may request approval for alternative compliance measures for
relief rig requirements in accordance with existing Sec. 250.141 (+0
hours).
3. Subpart S:
In Sec. 250.1920(b), (c), (d), and (e), the additional non-hour
cost burdens pertaining to Audit Service Provider (ASP) audits every
year in the Arctic in which exploration drilling is conducted would
apply (+$129,000 non-hour cost).
4. 30 CFR part 254:
Operators currently submit information with their spill response
plans (Sec. Sec. 254.20-29) that is related to the requirements in
this rulemaking under proposed Sec. Sec. 254.70, 254.80, and 254.90;
therefore, we believe that the current burden sufficiently covers the
[[Page 9962]]
proposed modifications. We have added a new requirement in Sec.
254.80(c) for submitting a description of the system used to maintain
real time monitoring (+12 hours).
Burden Table
----------------------------------------------------------------------------------------------------------------
Reporting and
Citation 30 CFR parts 250 and 254 recordkeeping Hour burden Average number of Annual burden
requirements annual responses hours
----------------------------------------------------------------------------------------------------------------
30 CFR Part 250, Subpart A
----------------------------------------------------------------------------------------------------------------
188(c); 190...................... NEW--Provide BSEE Oral 1.5.......... 2 notifications... 3.
immediate oral
report of sea ice
movement/
conditions; start
and termination
of ice management
activities; kicks
or unexpected
operational
issues.
188(c); 190...................... NEW--Submit a Written 4......... 2 reports......... 8.
written report
within 24 hours
after completing
ice management
activities.
------------------------------------------------------------------------------
Subtotal..................... .................. .................. 4 responses....... 11 hours.
----------------------------------------------------------------------------------------------------------------
30 CFR Part 250, Subpart D
----------------------------------------------------------------------------------------------------------------
418.............................. Additional information that is to be submitted with an APD 0.
is covered under the specific requirement listed in this
burden table under 30 CFR 250.470.
452(a), (b)...................... NEW--Immediately 12................ 1 transmittal..... 12.
transmit real-
time data
gathering and
monitoring to
record, store,
and transmit data
relating to the
BOP control
system, fluid
handling,
downhole
conditions; prior
to well
operations,
notify BSEE of
monitoring
location and make
data available to
BSEE upon
request.
452(b)........................... NEW--Store and 1................. 2 wells x 138 276.
monitor all drilling days =
information 276.
relating to Sec.
250.452(a); make
data available to
BSEE upon
request.
----------------------------------------
452(b)........................... Store and retain Burden covered under 30 CFR 250, 0.
all monitoring Subpart D, 1014-0018.
records per
requirements of
Sec. Sec.
250.466 and 467.
----------------------------------------
470(a); 417; 418................. NEW--Submit 10................ 1 submittal....... 10.
detailed
descriptions of
environmental,
meteorologic, and
oceanic
conditions
expected at well
site(s); how
drilling unit,
equipment, and
materials will be
prepared for
service; how the
drilling unit
will be in
compliance with
Sec. 250.417.
470(b); 418...................... NEW--Submit 4................. 2 each well-- 16.
detailed underway to
description of drilling;
transitioning rig drilling to
from being underway = 4.
underway to
drilling and vice
versa.
470(b); 418...................... NEW--Submit 2................. 2 submittals...... 4.
detailed
description of
any anticipated
repair and
maintenance plans
for the drilling
unit and
equipment.
470(c); 418...................... NEW--Submit well 4................. 2 submittals...... 8.
specific drilling
objectives,
timelines, and
updated
contingency plans
etc., for
temporary
abandonment.
470(d); 418...................... NEW--Submit 6................. 1 submittal....... 6.
detailed
description
concerning
weather and ice
forecasting for
all phases;
including how to
ensure continuous
awareness of
weather/ice
hazards at/
between each well
site; plans for
managing ice
hazards and
responding to
weather events;
verification of
capabilities.
470(e); 418; 472................. NEW--Submit a 140............... 1 explanation..... 140.
detailed
description of
compliance with
relief rig plans.
[[Page 9963]]
470(f); 471(c); 418.............. NEW--SCCE 60................ 2 submittals...... 120.
capabilities;
submit equipment
statement showing
capable of
controlling WCD;
detailed
description of
your or your
contractor's SCCE
capabilities
including
operating
assumptions and
limitations;
inventory of
local and
regional supplies
and services,
along with
supplier relevant
information;
proof of contract
or agreements for
providing SCCE or
supplies,
services;
detailed
description of
procedures for
inspecting,
testing, and
maintaining SCCE;
and detailed
description of
your plan
ensuring all
members of the
team operating
SCCE have
received training
to deploy and
operate, include
dates of prior
and planned
training.
470(g); 418...................... NEW--Submit a 20................ 1 submittal....... 20.
detailed
description of
utilizing best
practices of API
RP 2N during
operations.
471(c); 470(f); 465(a)........... NEW--Submit with 10................ 2 submittals...... 20.
your APM, a
reevaluation of
your SCCE
capabilities if
well design
changes; include
any new WCD rate
and demonstrate
that your SCCE
capabilities will
comply with Sec.
250.470(f).
471(e)........................... NEW--Maintain all 20................ 2 records......... 40.
SCCE testing,
inspection, and
maintenance
records for at
least 10 years;
make available to
BSEE upon
request.
471(f)........................... NEW--Maintain all 20................ 2 records......... 40.
records
pertaining to use
of SCCE during
testing,
training, and
deployment
activities for at
least 3 years;
make available to
BSEE upon
request.
----------------------------------------
472(c)........................... Request approval Burden covered under 30 CFR 250, 0.
for alternative Subpart A, 1014-0022
compliance for
relief rig
requirements.
------------------------------------------------------------------------------
Subtotal..................... .................. .................. 297 responses..... 712 hours
----------------------------------------------------------------------------------------------------------------
30 CFR Part 250, Subpart S
----------------------------------------------------------------------------------------------------------------
1920(b), (c), (e)................ ASP audit for High 1 operator x $129,000 audit for high activity = $129,000.
Activity Operator.
NOTE: An audit
once every 3
years in POCSR
and GOMR; an
audit in the
Arctic in every
year in which
drilling is
conducted..
----------------------------------------
1920(c).......................... Submit to BSEE Burden covered under 30 CFR 250, 0
after completed Subpart S, 1014-0017.
audit, an audit
report of
findings and
conclusions,
including
deficiencies and
required
supporting
information/
documentation.
----------------------------------------
1920(d).......................... Submit/resubmit a ..................
copy of your CAP
that will address
deficiencies
identified in
audit.
----------------------------------------------------------------------------------------------------------------
Subtotal..................... .................. .................. 1 response........ 0
--------------------------------------
$129,000 Non Hour Cost Burdens.
----------------------------------------------------------------------------------------------------------------
30 CFR Part 254, Subpart E
----------------------------------------------------------------------------------------------------------------
55; 70; 80; 90................... Submit spill Burden covered under 30 CFR 254, 1014- 0.
response plan for 0007.
OCS facilities
with all
information
required in
regulations and
related
documents.
----------------------------------------
80(c)............................ NEW--Submit a 6................. 2 descriptions.... 12.
description of
system used to
maintain real-
time location
tracking for all
response
resources.
----------------------------------------
90(a)............................ Include in your Burden covered under 30 CFR 254, 1014- 0.
training and 0007.
exercise
activities the
requirements of
this section.
----------------------------------------
[[Page 9964]]
90(b)............................ Notify BSEE 60
days prior to
handling,
storing, or
transporting oil.
------------------------------------------------------------------------------
Subtotal..................... .................. .................. 2 responses....... 12 hours.
Total Hour Burden............ .................. .................. 304 Responses..... 735 Hours.
--------------------------------------
.................. .................. $129,000 Non-Hour Cost Burdens.
----------------------------------------------------------------------------------------------------------------
Note: For FY 2015, we calculated the burden with 2 rigs (same operator), each rig drilling 1 well.
Commenting on Information Collections
As part of our continuing effort to reduce paperwork and respondent
burdens, BOEM and BSEE invite the public to comment on any aspect of
the reporting and recordkeeping burdens. If you wish to comment on the
IC aspects of these regulations, you may send your comments directly to
by email to OMB ([email protected]) or by fax 202-395-5806,
with a copy to BSEE (see Addresses section). Please identify your
comments with RIN: 1082-AA01. To see a copy of either IC request
submitted to OMB, go to www.reginfo.gov (select Information Collection
Review, Currently Under Review). You may obtain a copy of the
supporting statement for the new IC by contacting each Bureau's
Information Collection Clearance Officer: Cheryl Blundon, BSEE, (703)
787-1607, and Arlene Bajusz, BOEM, (703) 787-1025.
The OMB is required to make a decision concerning the ICs contained
in these proposed regulations between 30 and 60 days after publication
of this document in the Federal Register. Therefore, a comment to OMB
is best assured of having its full effect if OMB receives it by March
26, 2015.
BOEM and BSEE specifically solicit comments on the following
questions:
1. Is the proposed collection of information necessary for the
Bureaus to properly perform their functions, and will it be useful?
2. Are the estimates of the burden hours of the proposed collection
reasonable?
3. Do you have any suggestions that would enhance the quality,
clarity, or usefulness of the information to be collected?
4. Is there a way to minimize the IC burden on those who are to
respond, including through the use of appropriate automated electronic,
mechanical, or other forms of information technology?
In addition, the PRA requires agencies to estimate the total annual
reporting and recordkeeping non-hour cost burden resulting from the
collection of information. BSEE has identified one non-hour cost burden
in the BSEE Burden Table. We solicit your comments on any non-hour
costs. For reporting and recordkeeping only, your response should split
the cost estimate into two components: (1) Total capital and startup
cost component and (2) annual operation, maintenance, and purchase of
services component.
Your estimates should consider the costs to generate, maintain, and
disclose or provide the information. You should describe the methods
you use to estimate major cost factors, including system and technology
acquisition, expected useful life of capital equipment, discount
rate(s), and the period over which you incur costs. Generally, your
estimates should not include equipment or services purchased: (1)
Before October 1, 1995; (2) to comply with requirements not associated
with the IC; (3) for reasons other than to provide information or keep
records for the Government; or (4) as part of customary and usual
business or private practices.
L. National Environmental Policy Act of 1969 (NEPA)
BOEM and BSEE developed a draft Environmental Assessment (EA) to
determine whether this proposed rule would have a significant impact on
the quality of the human environment under the NEPA. The draft EA is
available for review and public comment in conjunction with this
proposed rule at www.regulations.gov (in the Search box, enter BSEE-
2013-0011).
M. Data Quality Act
In developing this rule, we did not conduct or use a study,
experiment, or survey requiring peer review under the Data Quality Act
(Pub. L. 106-554, app. C Sec. 515, 114 Stat. 2763, 2763A-153-154).
N. Effects on the Nation's Energy Supply (E.O. 13211)
Although this proposed rule is a significant regulatory action
under E.O. 12866, it is not a significant energy action under the
definition of that term in E.O. 13211 because:
1. It is not likely to have a significant adverse effect on the
supply, distribution or use of energy; and
2. It has not been designated as a significant energy action by the
Administrator of OIRA.
Thus, a Statement of Energy Effects is not required.
Due to the inherent practical difficulties of exploration and
production in the area, to date there has been relatively little
exploration activity, and very little production of oil and gas, on the
Arctic OCS. The only existing oil production from the Arctic OCS is
through the Northstar Island facility. Since the proposed rule does not
apply to development or production activities, it would not reduce or
inhibit production of oil and gas and would have no adverse impact on
oil and gas supplies or prices.
O. Clarity of this Regulation
We are required by E.O. 12866, E.O. 12988, and by the Presidential
Memorandum of June 1, 1998, to write all rules in plain language. This
means that each rule we publish must:
1. Be logically organized;
2. Use the active voice to address readers directly;
3. Use clear language rather than jargon;
4. Be divided into short sections and sentences; and
5. Use lists and tables wherever possible.
If you believe we have not met these requirements, send us comments
by one of the methods listed in the ADDRESSES section. To better help
us revise the rule, your comments should be as specific as possible.
For example, you should tell us the numbers of the sections or
paragraphs that you find unclear, which sections or sentences are too
long, or the sections where you believe lists or tables would be
useful.
P. Public Availability of Comments
BOEM and BSEE encourage you to participate in this proposed rule by
submitting written comments as discussed in the ADDRESSES and DATES
sections of this proposed rule. Before
[[Page 9965]]
including your address, phone number, email address or other personal
identifying information in your comment on this proposed rule, you
should be aware that your entire comment--including your personal
identifying information--may be made publicly available at any time.
While you can ask us in your comment to withhold your personal
identifying information from public review, we cannot guarantee that we
will be able to do so.
List of Subjects
30 CFR Part 250
Continental shelf, Environmental impact statements, Environmental
protection, Government contracts, Incorporation by reference,
Investigations, Mineral royalties, Oil and gas development and
production, Oil and gas exploration, Oil and gas reserves, Penalties,
Pipelines, Public lands--mineral resources, Public lands--rights of-
way, Reporting and recordkeeping requirements, Sulphur development and
production, Sulphur exploration, Surety bonds.
30 CFR Part 254
Continental shelf, Intergovernmental relations, Oil and gas
exploration, Oil pollution, Pipelines, Public lands--mineral resources,
Reporting and recordkeeping requirements.
30 CFR Part 550
Administrative practice and procedure, Environmental impact
statements, Environmental protection, Federal lands, Government
contracts, Oil, Oil and gas exploration, Oil and gas development, Outer
continental shelf, Penalties, Pipelines, Public lands--mineral
resources, Public lands--right-of-way, Reporting and recordkeeping
requirements, Sulphur development and production, Energy, Oil and gas
reserves, Natural gas, Natural resources, Continental shelf, Offshore
structures, Petroleum, Bonds, Surety bonds.
Dated: February 18, 2015.
Janice M. Schneider,
Assistant Secretary, Land and Minerals Management.
For the reasons stated in the preamble, BOEM and BSEE amend 30 CFR
parts 250, 254, and 550 as follows:
TITLE 30--Mineral Resources
CHAPTER II--BUREAU OF SAFETY AND ENVIRONMENTAL ENFORCEMENT, DEPARTMENT
OF THE INTERIOR
PART 250--OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL
SHELF
0
1. The authority citation for 30 CFR part 250 is revised to read as
follows:
Authority: 30 U.S.C. 1751, 31 U.S.C. 9701, 33 U.S.C.
1321(j)(1)(C), 43 U.S.C. 1334.
0
2. Amend Sec. 250.105 by:
0
a. Revising the definition of ``District Manager'' and
0
b. Adding new definitions for ``Arctic OCS'', ``Arctic OCS
conditions'', ``Cap and flow system'', ``Capping stack'', ``Containment
dome'' and ``Source control and containment equipment (SCCE)'' in
alphabetical order, to read as follows:
Sec. 250.105 Definitions.
* * * * *
Arctic OCS means the Beaufort Sea and Chukchi Sea Planning Areas,
as described in the Proposed Final OCS Oil and Gas Leasing Program for
2012-2017 (June 2012).
Arctic OCS conditions means, for the purposes of this part, the
conditions operators can reasonably expect during operations on the
Arctic OCS. Such conditions, depending on the time of year, include,
but are not limited to: Extreme cold, freezing spray, snow, extended
periods of low light, strong winds, dense fog, sea ice, strong
currents, and dangerous sea states. Remote location, relative lack of
infrastructure, and the existence of subsistence hunting and fishing
areas are also characteristic of the Arctic region.
* * * * *
Cap and flow system means an integrated suite of equipment and
vessels, including a capping stack and associated flow lines, that,
when installed or positioned, is used to control the flow of fluids
escaping from the well by conveying the fluids to the surface to a
vessel or facility equipped to process the flow of oil, gas, and water.
A cap and flow system is a high pressure system that includes the
capping stack and piping necessary to convey the flowing fluids through
the choke manifold to the surface equipment.
Capping stack means a mechanical device that can be installed on
top of a subsea or surface wellhead or blowout preventer to stop the
uncontrolled flow of fluids into the environment.
* * * * *
Containment dome means a non-pressurized container that can be used
to collect fluids escaping from the well or equipment below the sea
surface or from seeps by suspending the device over the discharge or
seep location. The containment dome includes all of the equipment
necessary to capture and convey fluids to the surface.
* * * * *
District manager means the BSEE officer with authority and
responsibility for operations or other designated program functions for
a district within a BSEE Region. For activities on the Alaska OCS, any
reference in this part to District Manager means the BSEE Regional
Supervisor.
* * * * *
Source control and containment equipment (SCCE) means the capping
stack, cap and flow system, containment dome, and/or other subsea and
surface devices, equipment, and vessels whose collective purpose is to
control a spill source and stop the flow of fluids into the environment
or to contain fluids escaping into the environment. ``Surface devices''
refers to equipment mounted or staged on a barge, vessel, or facility
to separate, treat, store and/or dispose of fluids conveyed to the
surface by the cap and flow system or the containment dome. ``Subsea
devices'' includes, but is not limited to, remotely operated vehicles,
anchors, buoyancy equipment, connectors, cameras, controls and other
subsea equipment necessary to facilitate the deployment, operation and
retrieval of the SCCE. The SCCE does not include a blowout preventer.
* * * * *
0
3. Amend Sec. 250.188 by adding a new paragraph (c) to read as
follows:
Sec. 250.188 What incidents must I report to BSEE and when must I
report them?
* * * * *
(c) On the Arctic OCS, in addition to the requirements of
paragraphs (a) and (b) of this section, you must provide to the BSEE
inspector on location, if one is present, or to the Regional Supervisor
both of the following:
(1) An immediate oral report if any of the following occur:
(i) Any sea ice movement or condition that has the potential to
affect your operation or trigger ice management activities;
(ii) The start and termination of ice management activities; or
(iii) Any ``kicks'' or operational issues that are unexpected and
could result in the loss of well control.
(2) Within 24 hours after completing ice management activities, a
written report of such activities that conforms to the content
requirements in Sec. 250.190.
0
4. Amend Sec. 250.198 by adding paragraph (h)(89) to read as follows:
Sec. 250.198 Documents incorporated by reference.
* * * * *
(h) * * *
[[Page 9966]]
(89) API RP 2N, Third Edition, ``Recommended Practice for Planning,
Designing, and Constructing Structures and Pipelines for Arctic
Conditions;'' incorporated by reference at Sec. 250.470(g);
* * * * *
0
5. Amend Sec. 250.300 by revising paragraphs (b)(1) and (b)(2) to read
as follows:
Sec. 250.300 Pollution prevention.
* * * * *
(b)(1) The District Manager may restrict the rate of drilling fluid
discharges or prescribe alternative discharge methods. The District
Manager may also restrict the use of components which could cause
unreasonable degradation to the marine environment. No petroleum-based
substances, including diesel fuel, may be added to the drilling mud
system without prior approval of the District Manager. For Arctic OCS
exploratory drilling, you must capture all petroleum-based mud to
prevent its discharge into the marine environment. The Regional
Supervisor may also require you to capture, during your Arctic OCS
exploratory drilling operations, all water-based mud from operations
after completion of the hole for the conductor casing to prevent its
discharge into the marine environment, based on various factors
including, but not limited to:
(i) The proximity of your exploratory drilling operation to
subsistence hunting and fishing locations;
(ii) The extent to which discharged mud may cause marine mammals to
alter their migratory patterns in a manner that impedes subsistence
users' access to, or use of, those resources, or increases the risk of
injury to subsistence users; or
(iii) The extent to which discharged mud may adversely affect
marine mammals, fish, or their habitat.
(2) Approval of the method of disposal of drill cuttings, sand, and
other well solids shall be obtained from the District Manager. For
Arctic OCS exploratory drilling, you must capture all cuttings from
operations that utilize petroleum-based mud to prevent their discharge
into the marine environment. The Regional Supervisor may also require
you to capture, during your Arctic OCS exploratory drilling operations,
all cuttings from operations that utilize water-based mud after
completion of the hole for the conductor casing to prevent their
discharge into the marine environment, based on various factors
including, but not limited to:
(i) The proximity of your exploratory drilling operation to
subsistence hunting and fishing locations;
(ii) The extent to which discharged cuttings may cause marine
mammals to alter their migratory patterns in a manner that impedes
subsistence users' access to, or use of, those resources, or increases
the risk of injury to subsistence users; or
(iii) The extent to which discharged cuttings may adversely affect
marine mammals, fish, or their habitat.
* * * * *
0
6. Amend Sec. 250.402 by adding a new paragraph (c) to read as
follows:
Sec. 250.402 When and how must I secure a well?
* * * * *
(c) For Arctic OCS exploratory drilling operations, in addition to
the requirements of paragraphs (a) and (b) of this section:
(1) If you move your drilling rig off a well prior to completion or
permanent abandonment, you must ensure that any equipment left on,
near, or in a well bore that has penetrated below the surface casing is
positioned in a manner to:
(i) Protect the well head; and
(ii) Prevent or minimize the likelihood of compromising the down-
hole integrity of the well or the effectiveness of the well plugs.
(2) In areas of ice scour, you must use a well mudline cellar or an
equivalent means of minimizing the risk of damage to the well head.
0
7. Amend Sec. 250.418 by adding a new paragraph (k) to read as
follows:
Sec. 250.418 What additional information must I submit with my APD?
* * * * *
(k) For Arctic OCS exploratory drilling operations, you must
provide the information required by Sec. 250.470.
0
8. Amend Sec. 250.447 by revising paragraph (b) to read as follows:
Sec. 250.447 When must I pressure test the BOP system?
* * * * *
(b) Before 14 days have elapsed since your last BOP pressure test,
or for Arctic OCS exploratory drilling operations before 7 days have
elapsed since your last BOP pressure test. You must begin to test your
BOP system before midnight on the 14th day (or for Arctic OCS
exploratory drilling operations, the 7th day) following the conclusion
of the previous test. However, the District Manager may require more
frequent testing if conditions or BOP performance warrant; and
* * * * *
0
9. Add new Sec. 250.452 to read as follows:
Sec. 250.452 What are the real-time monitoring requirements for
Arctic OCS exploratory drilling operations?
(a) When conducting exploratory drilling operations on the Arctic
OCS, you must have real-time data gathering and monitoring capability
to record, store, and transmit data regarding all aspects of:
(1) The BOP control system;
(2) The well's fluid handling systems on the rig; and
(3) The well's downhole conditions as monitored by a downhole
sensing system, when such a system is installed.
(b) During well operations, you must immediately transmit the data
identified in paragraph (a) of this section to a designated onshore
location where it must be stored and monitored by qualified personnel
who have the capability for continuous contact with rig personnel and
who have the authority, in consultation with rig personnel, to initiate
any necessary action in response to abnormal data or events. Prior to
well operations, you must notify BSEE where the data will be monitored
during those operations, and you must make the data available to BSEE,
including in real time, upon request. After well operations, you must
store the data at a designated location for recordkeeping purposes as
required in Sec. Sec. 250.466 and 250.467.
0
10. Add new undesignated centered heading ``ADDITIONAL ARCTIC OCS
REQUIREMENTS'' and Sec. Sec. 250.470 through 250.473 in Subpart D to
read as follows:
Additional Arctic OCS Requirements
Sec. 250.470 What additional information must I submit with my APD
for Arctic OCS exploratory drilling operations?
In addition to all other applicable requirements included in this
part, you must provide with your APD all of the following information
pertaining to your proposed Arctic OCS exploratory drilling:
(a) A detailed description of:
(1) The environmental, and meteorologic and oceanic conditions you
expect to encounter at the well site(s);
(2) How your equipment, materials, and drilling unit will be
prepared for service in the conditions in paragraph (a)(1) of this
section, and how your drilling unit will be in compliance with the
requirements of Sec. 250.417.
(b) A detailed description of all operations necessary in Arctic
OCS Conditions to transition the rig from being under way to conducting
drilling
[[Page 9967]]
operations and from ending drilling operations to being under way, as
well as any anticipated repair and maintenance plans for the drilling
unit and equipment. The description should include, but not be limited
to:
(1) Recovering the subsea equipment, including the marine riser and
the lower marine riser package;
(2) Recovering the BOP;
(3) Recovering the auxiliary sub-sea controls and template;
(4) Laying down the drill pipe and securing the drill pipe and
marine riser;
(5) Securing the drilling equipment;
(6) Transferring the fluids for transport or disposal;
(7) Securing ancillary equipment like the draw works and lines;
(8) Refueling or transferring fuel;
(9) Offloading waste;
(10) Recovering the ROVs;
(11) Picking up the oil spill prevention booms and equipment; and
(12) Offloading the drilling crew.
(c) Well-specific drilling objectives, timelines, and updated
contingency plans for temporary abandonment of the well, including but
not limited to the following:
(1) When you will spud the particular well (i.e., begin drilling
operations at the well site) identified in the APD;
(2) How long you will take to drill the well;
(3) Anticipated depths and geologic targets, with timelines;
(4) When you expect to set and cement each string of casing;
(5) When and how you would log the well;
(6) Your plans to test the well;
(7) When and how you intend to abandon the well, including
specifically addressing your plans for how to move the rig off location
and how you will meet the requirements of Sec. 250.402(c);
(8) A description of what equipment and vessels will be involved in
the process of temporarily abandoning the well due to ice; and
(9) An explanation of how these elements will be integrated into
your overall program.
(d) A detailed description of your weather and ice forecasting
capability for all phases of the drilling operation, including:
(1) How you will ensure continuous awareness of potential weather
and ice hazards at, and during transition between, wells;
(2) Your plans for managing ice hazards and responding to weather
events; and
(3) Verification that you have the capabilities described in your
BOEM-approved EP.
(e) A detailed description of how you will comply with the
requirements of Sec. 250.472.
(f) A statement that you own, or have a contract with a provider
for, source control and containment equipment (SCCE) that is capable of
controlling and/or containing a worst case discharge, as described in
your BOEM-approved EP, when proposing to use a MODU to conduct
exploratory drilling operations on the Arctic OCS. The following
information must be included in your SCCE submittal:
(1) A detailed description of your or your contractor's SCCE
capabilities, including operating assumptions and limitations,
reflecting that you have access to, and the ability to deploy in
accordance with Sec. 250.471, all SCCE necessary to regain control of
the well, including the ability to evaluate the performance of the well
design to determine how a full shut-in can be achieved without having
reservoir fluids discharged into the environment;
(2) An inventory of the local and regional SCCE, supplies, and
services that you own or for which you have a contract with a provider.
You must identify each supplier of such equipment and services and
provide their locations and telephone numbers;
(3) Where applicable, proof of contracts or membership agreements
with cooperatives, service providers, or other contractors that will
provide you with the necessary SCCE or related supplies and services if
you do not possess them. The contract or membership agreement must
include provisions for ensuring the availability of the personnel and/
or equipment on a 24-hour per day basis while you are drilling below or
working below the surface casing;
(4) A detailed description of the procedures for inspecting,
testing, and maintaining your SCCE; and
(5) A detailed description of your plan to ensure that all members
of your operating team who are responsible for operating the SCCE have
received the necessary training to deploy and operate such equipment in
Arctic OCS Conditions and demonstrate ongoing proficiency in source
control operations. You must also identify and include the dates of
prior and planned training.
(g) Where it does not conflict with other requirements of this
subpart, and except as provided below, you must comply with the
requirements of API RP 2N, Third Edition ``Planning, Designing, and
Constructing Structures and Pipelines for Arctic Conditions''
(incorporated by reference as specified in Sec. 250.198), and provide
a detailed description of how you will utilize the best practices
included in API RP 2N during your exploratory drilling operations. You
are not required to incorporate the following sections of API RP 2N
into your drilling operations:
(1) Sections 6.6.3 through 6.6.4;
(2) The foundation recommendations in Section 8.4;
(3) Section 9.6;
(4) The recommendations for permanently moored systems in Section
9.7;
(5) The recommendations for pile foundations in Section 9.10;
(6) Section 12;
(7) Section 13.2.1;
(8) Sections 13.8.1.1, 13.8.2.1, 13.8.2.2, 13.8.2.4 through
13.8.2.7;
(9) Sections 13.9.1, 13.9.2, 13.9.4 through 13.9.8;
(10) Sections 14 through 16; and
(11) Section 18.
Sec. 250.471 What are the requirements for Arctic OCS source control
and containment?
You must meet the following requirements for all exploration wells
drilled on the Arctic OCS:
(a) If you use a MODU when drilling below or working below the
surface casing, you must have access to:
(1) A capping stack, positioned to ensure that it will arrive at
the well location within 24 hours after a loss of well control and can
be deployed as directed by the Regional Supervisor pursuant to
paragraph (h) of this section;
(2) A cap and flow system, positioned to ensure that it will arrive
at the well location within 7 days after a loss of well control and can
be deployed as directed by the Regional Supervisor pursuant to
paragraph (h) of this section. The cap and flow system must be designed
to capture at least the amount of hydrocarbons equivalent to the
calculated worst case discharge rate referenced in your BOEM-approved
EP; and
(3) A containment dome, positioned to ensure that it will arrive at
the well location within 7 days after a loss of well control and can be
deployed as directed by the Regional Supervisor pursuant to paragraph
(g) of this section. The containment dome must have the capacity to
pump fluids without relying on buoyancy.
(b) You must conduct a monthly stump test of dry-stored capping
stacks. If you use a pre-positioned capping stack, you must conduct a
stump test prior to each installation on each well.
(c) As required by Sec. 250.465(a), if you propose to change your
well design, you must submit an APM. For Arctic OCS operations, your
APM must include a
[[Page 9968]]
reevaluation of your SCCE capabilities for any new WCD rate, and a
demonstration that your SCCE capabilities will meet the criteria in
Sec. 250.470(f) under the changed well design.
(d) You must conduct tests or exercises of your SCCE, including
deployment of your SCCE, when directed by the Regional Supervisor.
(e) You must maintain records pertaining to testing, inspection,
and maintenance of your SCCE for at least 10 years and make the records
available to any authorized BSEE representative upon request.
(f) You must maintain records pertaining to the use of your SCCE
during testing, training, and deployment activities for at least 3
years and make the records available to any authorized BSEE
representative upon request.
(g) Upon a loss of well control, you must initiate transit of all
SCCE identified in paragraph (a) of this section to the well.
(h) You must deploy and use SCCE when directed by the Regional
Supervisor.
Sec. 250.472 What are the relief rig requirements for the Arctic OCS?
(a) In the event of a loss of well control, the Regional Supervisor
may direct you to drill a relief well using the relief rig described in
your APD. Your relief rig must comply with all other requirements of
this part for drilling operations, and it must be able to drill a
relief well under anticipated Arctic OCS Conditions.
(b) When you are drilling below or working below the surface casing
during Arctic OCS exploratory drilling operations, you must have access
to a relief rig, different from your primary drilling rig, staged in a
location such that it can arrive on site, drill a relief well, kill and
abandon the original well, and abandon the relief well prior to
expected seasonal ice encroachment at the drill site, but no later than
45 days after the loss of well control.
(c) Operators may request approval of alternative compliance
measures to the relief rig requirement in accordance with Sec.
250.141.
Sec. 250.473 What must I do to protect health, safety, property, and
the environment while operating on the Arctic OCS?
In addition to the requirements set forth in Sec. 250.107, when
conducting exploratory drilling operations on the Arctic OCS, you must
protect health, safety, property, and the environment by using the
following:
(a) Equipment and materials that are rated or de-rated for service
under conditions that can be reasonably expected during your
operations; and
(b) Measures to address human factors associated with weather
conditions that can be reasonably expected during your operations
including, but not limited to, provision of proper attire and
equipment, construction of protected work spaces, and management of
shifts.
0
11. Amend Sec. 250.1920 by:
0
a. Adding a new last sentence to paragraphs (b)(5), (c), and (d); and
0
b. Adding new paragraphs (e) and (f) to read as follows:
Sec. 250.1920 What are the auditing requirements for my SEMS program?
* * * * *
(b) * * *
(5) * * * For exploratory drilling operations taking place on the
Arctic OCS, you must conduct an audit, consisting of an onshore portion
and an offshore portion, including all related infrastructure, once per
year for every year in which drilling is conducted.
* * * * *
(c) * * * For exploratory drilling operations taking place on the
Arctic OCS, you must submit an audit report of the audit findings,
observations, deficiencies and conclusions for the onshore portion of
your audit no later than March 1 in any year in which you plan to
drill, and for the offshore portion of your audit, within 30 days of
the close of the audit.
(d) * * * For exploratory drilling operations taking place on the
Arctic OCS, you must provide BSEE with a copy of your CAP for
addressing deficiencies or nonconformities identified in the onshore
portion of the audit no later than March 1 in any year in which you
plan to drill, and for the offshore portion of your audit, within 30
days of the close of the audit.
(e) For exploratory drilling operations taking place on the Arctic
OCS, during the offshore portion of each audit, 100 percent of the
facilities operated must be audited while drilling activities are
underway. The offshore portion of the audit for each facility must be
started and closed within 30 days after the first spudding of the well
or entry into an existing wellbore for any purpose from that facility.
(f) For exploratory drilling operations taking place on the Arctic
OCS, if BSEE determines that the CAP or progress toward implementing
the CAP is not satisfactory, BSEE may order you to shut down all or
part of your operations.
PART 254--OIL-SPILL RESPONSE REQUIREMENTS FOR FACILITIES LOCATED
SEAWARD OF THE COAST LINE
0
12. The authority citation for 30 CFR part 254 continues to read as
follows:
Authority: 33 U.S.C. 1321.
0
13. Amend Sec. 254.6 by:
0
a. Revising the definition of ``Adverse weather conditions,''
0
b. Adding a new definition for ``Arctic OCS'' in alphabetical order,
and
0
c. Adding a new definition for ``Ice intervention practices'' in
alphabetical order.
Sec. 254.6 Definitions.
* * * * *
Adverse weather conditions means, for the purposes of this part,
weather conditions found in the operating area that make it difficult
for response equipment and personnel to clean up or remove spilled oil
or hazardous substances. These conditions include, but are not limited
to: Fog, inhospitable water and air temperatures, wind, sea ice,
extreme cold, freezing spray, snow, currents, sea states, and extended
periods of low light. Adverse weather conditions do not refer to
conditions under which it would be dangerous or impossible to respond
to a spill, such as a hurricane.
Arctic OCS means the Beaufort Sea and Chukchi Sea Planning Areas,
as described in the Proposed Final OCS Oil and Gas Leasing Program for
2012-2017 (June 2012).
* * * * *
Ice intervention practices means the equipment, vessels, and
procedures used to increase oil encounter rates and the effectiveness
of spill response techniques and equipment when sea ice is present.
* * * * *
14. Add Sec. 254.55 to Subpart D to read as follows:
Sec. 254.55 Spill response plans for facilities located in Alaska
State waters seaward of the coast line in the Chukchi and Beaufort
Seas.
Response plans for facilities conducting exploratory drilling
operations from a MODU seaward of the coast line in Alaska State waters
in the Chukchi and Beaufort Seas must follow the requirements contained
within subpart E of this part, in addition to the other requirements of
this subpart. Such response plans must address how the source control
procedures selected to comply with State law will be integrated into
the planning, training, and exercise requirements of Sec. Sec.
254.70(a), 254.90(a), and 254.90(c) in the event that the
[[Page 9969]]
proposed operations do not incorporate the capping stack, cap and flow
system, containment dome, and/or other similar subsea and surface
devices and equipment and vessels referenced in those sections.
0
15. Add new subpart E to read as follows:
Subpart E--Oil-Spill Response Requirements for Facilities Located on
the Arctic OCS
Sec.
254.65 Purpose.
254.66 through 254.69 [Reserved]
254.70 What are the additional requirements for facilities
conducting exploratory drilling from a MODU on the Arctic OCS?
254.71 through 254.79 [Reserved]
254.80 What additional information must I include in the ``Emergency
response action plan'' section for facilities conducting exploratory
drilling from a MODU on the Arctic OCS?
254.81 through 254.89 [Reserved]
254.90 What are the additional requirements for exercises of your
response personnel and equipment for facilities conducting
exploratory drilling from a MODU on the Arctic OCS?
Subpart E--Oil-Spill Response Requirements for Facilities Located
on the Arctic OCS
Sec. 254.65 Purpose.
This subpart describes the additional requirements for preparing
spill response plans and maintaining oil spill preparedness for
facilities conducting exploratory drilling operations from a MODU on
the Arctic OCS.
Sec. Sec. 254.66 through 254.69 [Reserved]
Sec. 254.70 What are the additional requirements for facilities
conducting exploratory drilling from a MODU on the Arctic OCS?
In addition to meeting the applicable requirements of this part,
your response plan must:
(a) Describe how the relevant personnel, equipment, materials, and
support vessels associated with the capping stack, cap and flow system,
containment dome, and other similar subsea and surface devices and
equipment and vessels will be integrated into oil spill response
incident action planning;
(b) Describe how you will address human factors, such as cold
stress and cold related conditions, associated with oil spill response
activities in adverse weather conditions and their impacts on decision-
making and health and safety; and
(c) Undergo plan-holder review prior to handling, storing, or
transporting oil in connection with seasonal exploratory drilling
activities, and all resulting modifications must be submitted to the
Regional Supervisor. If this review does not result in modifications,
you must inform the Regional Supervisor in writing that there are no
changes. The requirements of this subsection are in lieu of the
requirements in Sec. 254.30(a).
Sec. Sec. 254.71 through 254.79 [Reserved]
Sec. 254.80 What additional information must I include in the
``Emergency response action plan'' section for facilities conducting
exploratory drilling from a MODU on the Arctic OCS?
In addition to the requirements in Sec. 254.23, you must include
the following information in the emergency response action plan section
of your response plan:
(a) A description of your ice intervention practices and how they
will improve the effectiveness of the oil spill response options and
strategies that are listed in your OSRP in the presence of sea ice.
When developing the ice intervention practices for your oil spill
response plan, you must consider, at a minimum, the use of specialized
tactics, modified response equipment, ice management assist vessels,
and technologies for the identification, tracking, containment and
removal of oil in ice.
(b) On areas of the Arctic OCS where a planned shore-based response
would not satisfy Sec. 254.1(a):
(1) A list of all resources required to ensure an effective
offshore-based response capable of operating in adverse weather
conditions. This list must include a description of how you will ensure
the shortest possible transit times, including but not limited to
establishing an offshore resource management capability (e.g., sea-
based staging, maintenance, and berthing logistics); and
(2) A list and description of logistics resupply chains, including
waste management, that effectively factor in the remote and limited
infrastructure that exists in the Arctic and ensure you can adequately
sustain all oil spill response activities for the duration of the
response. The components of the logistics supply chain include, but are
not limited to:
(i) Personnel and equipment transport services;
(ii) Airfields and types of aircraft that can be supported;
(iii) Capabilities to mobilize supplies (e.g., response equipment,
fuel, food, fresh water) and personnel to the response sites;
(iv) Onshore staging areas, storage areas that may be used en route
to staging areas, and camp facilities to support response personnel
conducting offshore, nearshore and shoreline response; and
(v) Management of recovered fluid and contaminated debris and
response materials (e.g., oiled sorbents), as well as waste streams
generated at offshore and on-shore support facilities (e.g., sewage,
food, and medical).
(c) A description of the system you will use to maintain real-time
location tracking for all response resources while operating,
transiting, or staging/maintaining such resources during a spill
response.
Sec. Sec. 254.81 through 254.89 [Reserved]
Sec. 254.90 What are the additional requirements for exercises of
your response personnel and equipment for facilities conducting
exploratory drilling from a MODU on the Arctic OCS?
In addition to the requirements in Sec. 254.42, the following
requirements apply to exercises for your response personnel and
equipment for facilities conducting exploratory drilling from a MODU on
the Arctic OCS:
(a) You must incorporate the personnel, materials, and equipment
identified in Sec. 254.70(a), the safe working practices identified in
Sec. 254.70(b), the ice intervention practices described in Sec.
254.80(a), the offshore-based response requirements in Sec. 254.80(b),
and the resource tracking requirements in Sec. 254.80(c) into your
spill-response training and exercise activities.
(b) For each season in which you plan to conduct exploratory
drilling operations from a MODU on the Arctic OCS, you must notify the
Regional Supervisor 60 days prior to handling, storing, or transporting
oil.
(c) After the Regional Supervisor receives notice pursuant to Sec.
254.90(b), the Regional Supervisor may direct you to deploy and operate
your spill response equipment and/or your capping stack, cap and flow
system, and containment dome, and other similar subsea and surface
devices and equipment and vessels, as part of announced or unannounced
exercises or compliance inspections. For the purposes of this section,
spill response equipment does not include the use of blowout
preventers, diverters, heavy weight mud to kill the well, relief wells,
or other similar conventional well control options.
[[Page 9970]]
CHAPTER V--BUREAU OF OCEAN ENERGY MANAGEMENT, DEPARTMENT OF THE
INTERIOR
PART 550--OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER
CONTINENTAL SHELF
0
16. The authority citation for 30 CFR part 550 continues to read as
follows:
Authority: 30 U.S.C. 1751; 31 U.S.C. 9701; 43 U.S.C. 1334.
0
17. Amend Sec. 550.105 by adding new definitions for ``Arctic OCS''
and ``Arctic OCS conditions'' in alphabetical order to read as follows:
Sec. 550.105 Definitions.
* * * * *
Arctic OCS means the Beaufort Sea and Chukchi Sea Planning Areas,
as described in the Proposed Final OCS Oil and Gas Leasing Program for
2012-2017 (June 2012).
Arctic OCS conditions means, for the purposes of this part, the
conditions operators can reasonably expect during operations on the
Arctic OCS. Such conditions, depending on the time of year, include,
but are not limited to: extreme cold, freezing spray, snow, extended
periods of low light, strong winds, dense fog, sea ice, strong
currents, and dangerous sea states. Remote location, relative lack of
infrastructure, and the existence of subsistence hunting and fishing
areas are also characteristic of the Arctic region.
* * * * *
0
18. Amend Sec. 550.200 paragraph (a) by adding the term ``IOP'' in
alphabetical order:
Sec. 550.200 Definitions.
* * * * *
(a) * * *
IOP means Integrated Operations Plan.
* * * * *
0
19. Add a new Sec. 550.204 to read as follows:
Sec. 550.204 When must I submit my IOP for proposed Arctic
exploratory drilling operations and what must the IOP include?
If you propose exploratory drilling activities on the Arctic OCS,
you must submit an Integrated Operations Plan (IOP) to the Regional
Supervisor at least 90 days prior to filing your EP. Your IOP must
describe how your exploratory drilling program will be designed and
conducted in an integrated manner suitable for Arctic OCS Conditions
and include the following information:
(a) Information describing how all vessels and equipment will be
designed, built, and/or modified to account for Arctic OCS Conditions;
(b) A schedule of your exploratory drilling program, including
contractor work on critical components of your program;
(c) A description of your mobilization and demobilization
operations, including tow plans suitable for Arctic OCS Conditions, as
well as your general maintenance schedule for vessels and equipment;
(d) A description of your exploratory drilling program objectives
and timelines for each objective, including general plans for
abandonment of the well(s), such as:
(1) Contingency plans for temporary abandonment in the event of ice
encroachment at the drill site;
(2) Plans for permanent abandonment; and
(3) Plans for temporary seasonal abandonment;
(e) A description of your weather and ice forecasting capabilities
for all phases of the exploration program, including a description of
how you would respond to and manage ice hazards and weather events;
(f) A description of work to be performed by contractors supporting
your exploration drilling program (including mobilization and
demobilization), including:
(1) How such work will be designed or modified to account for
Arctic OCS Conditions; and
(2) Your concepts for contractor management, oversight, and risk
management.
(g) A description of how you will ensure operational safety while
working in Arctic OCS Conditions, including but not limited to:
(1) The safety principles that you intend to apply to yourself and
your contractors;
(2) The accountability structure within your organization for
implementing such principles;
(3) How you will communicate such principles to your employees and
contractors; and
(4) How you will determine successful implementation of such
principles.
(h) Information regarding your preparations and plans for staging
of oil spill response assets;
(i) A description of your efforts to minimize impacts of your
exploratory drilling operations on local community infrastructure,
including but not limited to housing, energy supplies, and services;
and
(j) A description of whether and to what extent your project will
rely on local community workforce and spill cleanup response capacity.
0
20. Revise Sec. 550.206 to read as follows:
Sec. 550.206 How do I submit the IOP, EP, DPP, or DOCD?
(a) Number of copies. When you submit an IOP, EP, DPP, or DOCD to
BOEM, you must provide:
(1) Four copies that contain all required information (proprietary
copies);
(2) Eight copies for public distribution (public information
copies) that omit information that you assert is exempt from disclosure
under the Freedom of Information Act (FOIA) (5 U.S.C. 552) and the
implementing regulations (43 CFR part 2); and
(3) Any additional copies that may be necessary to facilitate
review of the IOP, EP, DPP, or DOCD by certain affected States and
other reviewing entities.
(b) Electronic submission. You may submit part or all of your IOP,
EP, DPP, or DOCD and its accompanying information electronically. If
you prefer to submit your IOP, EP, DPP, or DOCD electronically, ask the
Regional Supervisor for further guidance.
(c) Withdrawal after submission. You may withdraw your proposed
IOP, EP, DPP, or DOCD at any time for any reason. Notify the
appropriate BOEM OCS Region if you do.
0
21. Amend Sec. 550.220 by:
0
a. Revising paragraph (a), and
0
b. Adding a new paragraph (c).
Sec. 550.220 If I propose activities in the Alaska OCS Region, what
planning information must accompany the EP?
* * * * *
(a) Emergency Plans. A description of your emergency plans 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.
* * * * *
(c) If you propose exploration activities on the Arctic OCS, the
following planning information must also accompany your EP:
(1) Suitability for Arctic OCS conditions. A description of how
your exploratory drilling activities will be designed and conducted in
a manner suitable for Arctic OCS conditions and how such activities
will be managed and overseen as an integrated endeavor.
(2) Ice and weather management. A description of your weather and
ice forecasting and management plans for all phases of your exploratory
drilling activities, including:
(i) A description of how you will respond to and manage ice hazards
and weather events;
(ii) Your ice and weather alert procedures;
[[Page 9971]]
(iii) Your procedures and thresholds for activating your ice and
weather management system(s); and
(iv) Confirmation that you will operate ice and weather management
and alert systems continuously throughout the planned operations,
including mobilization and demobilization operations to and from the
Arctic OCS.
(3) Source control and containment equipment capabilities. A
general description of how you will comply with Sec. 250.471 of this
title.
(4) Deployment of a relief well rig. A general description of how
you will comply with Sec. 250.472 of this title, including a
description of the relief well rig, the anticipated staging area of the
relief well rig, an estimate of the time it would take for the relief
well rig to arrive at the site of a loss of well control, how you would
drill a relief well if necessary, and the approximate timeframe to
complete relief well operations.
(5) Resource-sharing. Any agreements you have with third parties
for the sharing of assets or the provision of mutual aid in the event
of an oil spill or other emergency.
(6) Anticipated end of seasonal operations dates. Your projected
end of season dates, and the information used to identify those dates,
for:
(i) The completion of on-site operations, which is contingent upon
your capability in terms of equipment and procedures to manage and
mitigate risks associated with Arctic OCS Conditions; and
(ii) The termination of drilling operations into zones capable of
flowing liquid hydrocarbons to the surface consistent with the relief
rig planning requirements under Sec. 250.472 of this title and with
your estimated timeframe under paragraph (c)(4) of this section for
completion of relief well operations.
[FR Doc. 2015-03609 Filed 2-20-15; 4:15 pm]
BILLING CODE 4310-VH-4310-MR-P