Oil and Gas and Sulfur Operations in the Outer Continental Shelf-Blowout Preventer Systems and Well Control Revisions

 
CONTENT
Federal Register, Volume 84 Issue 94 (Wednesday, May 15, 2019)
[Federal Register Volume 84, Number 94 (Wednesday, May 15, 2019)]
[Rules and Regulations]
[Pages 21908-21985]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2019-09362]
[[Page 21907]]
Vol. 84
Wednesday,
No. 94
May 15, 2019
Part II
Department of the Interior
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Bureau of Safety and Environmental Enforcement
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30 CFR Part 250
Oil and Gas and Sulfur Operations in the Outer Continental Shelf--
Blowout Preventer Systems and Well Control Revisions; Final Rule
Federal Register / Vol. 84 , No. 94 / Wednesday, May 15, 2019 / Rules
and Regulations
[[Page 21908]]
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DEPARTMENT OF THE INTERIOR
Bureau of Safety and Environmental Enforcement
30 CFR Part 250
[Docket ID: BSEE-2018-0002; 190E1700D2 ET1SF0000.EAQ000 EEEE500000]
RIN 1014-AA39
Oil and Gas and Sulfur Operations in the Outer Continental
Shelf--Blowout Preventer Systems and Well Control Revisions
AGENCY: Bureau of Safety and Environmental Enforcement, Interior.
ACTION: Final rule.
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SUMMARY: The Bureau of Safety and Environmental Enforcement (BSEE) is
revising existing regulations for well control and blowout preventer
systems. This final rule revises requirements for well design, well
control, casing, cementing, real-time monitoring (RTM), and subsea
containment. These revisions modify regulations pertaining to offshore
oil and gas drilling, completions, workovers, and decommissioning in
accordance with Executive and Secretary of the Interior's Orders to
ensure safety and environmental protection, while correcting errors and
reducing certain unnecessary regulatory burdens imposed under the
existing regulations. Accordingly, after thoroughly reexamining the
2016 Blowout Preventer Systems and Well Control final rule (WCR),
experiences from the implementation process, and various BSEE policies
(notices to lessees, answers to frequently asked questions, and
conditions of approval), BSEE will amend, revise, or remove certain
current regulatory provisions that create unnecessary burdens on
stakeholders, while still maintaining safety and environmental
protection. The final regulations also address various issues and
errors that BSEE identified during the implementation of the 2016 WCR.
DATES: This final rule becomes effective on July 15, 2019. BSEE will
defer compliance with certain provisions of the final rule, however,
until the times specified in those provisions and as described in
Section II of this preamble.
    The incorporation by reference of certain publications listed in
the rule is approved by the Director of the Federal Register as of July
15, 2019.
FOR FURTHER INFORMATION CONTACT: For technical questions contact Fred
Brink, Gulf of Mexico Region (GOMR) District Operations Support, (504)
736-2400, or by email: [email protected]; for procedural questions
contact Kirk Malstrom, Regulations and Standards Branch, (202) 258-
1518, or by email: [email protected].
SUPPLEMENTARY INFORMATION:
Executive Summary
    In the immediate aftermath of the Deepwater Horizon incident in
2010, BSEE adopted several recommendations from multiple investigation
teams, and promulgated multiple rulemakings including the Drilling
Safety Rule (Oct. 2010), Safety and Environmental Management Systems
(SEMS) I (Oct. 2010), and SEMS II (April 2013), in order to improve the
safety of offshore operations. Subsequently, BSEE published the Blowout
Preventer Systems and Well Control final rule (the WCR) on April 29,
2016. The 2016 WCR consolidated the equipment and operational
requirements for well control into one part of BSEE's regulations;
enhanced blowout preventer (BOP), well design, and well-control
requirements; and incorporated certain industry consensus standards.
Most of the 2016 WCR provisions became effective on July 28, 2016.
Although the 2016 WCR addressed a significant number of issues that
were identified during the analysis of the Deepwater Horizon incident,
BSEE recognized that BOP equipment and systems continue to improve
technologically and well control processes also evolve. In 2017,
Congress also encouraged BSEE to:
evaluate information learned from additional stakeholder input and
ongoing technical conversations to inform implementation of this
rule. To the extent additional information warrants revisions to the
rule that require public notice and comment, the Bureau is
encouraged to follow that process to ensure that offshore operations
promote safety and protect the environment in a technically feasible
manner.\1\
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    \1\ See n. 10, supra.
Additionally, since the WCR became effective in 2016, BSEE has
continued to engage with the offshore oil and gas industry, Standards
Development Organizations (SDOs), and other stakeholders. During the
course of these engagements, BSEE identified areas for regulatory
improvement and stakeholders expressed a variety of concerns regarding
the implementation of the 2016 WCR. For instance, oil and natural gas
operators raised concerns about certain regulatory provisions that they
assert impose undue burdens on their industry, but do not significantly
enhance worker safety or environmental protection (e.g., how real time
monitoring is monitored and utilized onshore; a strictly enforced 0.5
pounds per gallon (ppg) drilling margin; requirements that may be
inconsistent with American Petroleum Institute (API) Standard 53; and
requirements for certain BSEE approvals during cementing operations
that result in unnecessary delay). Other stakeholders suggested that
certain regulatory requirements do not properly account for advances or
limitations in technology and processes. Further, BSEE received
numerous questions regarding the proper interpretation and application
of provisions viewed to be unclear or ambiguous, requiring BSEE to
provide substantial informal guidance regarding the terms of the 2016
WCR. BSEE posted approximately 100 responses to questions regarding the
2016 WCR provisions on the BSEE web page at https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule.
    Accordingly, after thoroughly reexamining the 2016 WCR, experiences
from the implementation process, and BSEE policy, BSEE is amending,
revising, or removing current regulatory provisions that create
unnecessary burdens on stakeholders while still maintaining safety and
environmental protection. On May 11, 2018, BSEE published in the
Federal Register a proposed rule to revise certain provisions of the
2016 WCR (83 FR 22128) (the ``proposed rule'') and to solicit comments
on several additional issues. In response to the proposed rule, BSEE
received over 265 sets of comments containing individually submitted
comments and multiple similar group form letters, totaling over 118,000
submittals. Comments included submittals from individual entities
(e.g., companies, industry organizations, non-governmental
organizations, State governments, and private citizens). All relevant
comments are posted at the Federal eRulemaking portal: http://www.regulations.gov. To access the comments at that website, enter
BSEE-2018-0002 in the Search box. The final regulatory changes reflect
BSEE's consideration of the public comments received on both the 2016
WCR and the proposed rule, and stakeholders' recommendations pertaining
to the requirements applicable to offshore oil and gas drilling,
completions, workovers, and decommissioning. This rule revises
regulatory provisions in 30 CFR part 250, subparts A, B, D, E, F, G,
and Q on topics such as, but not limited to:
    Notifications and submittals to BSEE;
    Drilling margins;
    Lift boats;
    Real-time monitoring;
[[Page 21909]]
    BSEE Approved Verification Organizations (BAVOs);
    Accumulator systems;
    BOP and control station testing;
    Coiled tubing; and
    Mechanical barriers (packers and bridge plugs).
    BSEE utilized the best available data to analyze the economic
impacts of the final changes. That analysis indicates that the
estimated overall economic impact will benefit the industry over the
next 10 years because of the reduction in compliance costs, in addition
to increased regulatory certainty. As this rule maintains safety and
environmental protection, the entities realizing savings from these
changes can deploy them for other, more productive purposes, e.g.,
additional capital investment. Increased productivity and competiveness
of domestic energy projects benefit consumers and the broader U.S.
economy.
    In keeping with recent Executive and Secretary's Orders, BSEE
undertook a review of the 2016 WCR with a view toward the policy
direction of encouraging energy exploration and production on the Outer
Continental Shelf (OCS) and reducing unnecessary regulatory burdens,
while ensuring that any such activity is safe and environmentally
responsible. BSEE carefully reviewed all 342 provisions of the 2016
WCR, and determined that this final rule revises or adds to 71
provisions of the 2016 WCR--or approximately 20% of the 2016 WCR
provisions. The regulations will still contain the core safety and
environmental protective provisions of the 2016 WCR. In the process,
BSEE compared each of the changes to the 424 recommendations arising
from 26 separate reports from 14 different organizations developed in
the wake of and in response to the Deepwater Horizon disaster, and
determined that none of the final changes ignores or contradicts any of
those recommendations, or alters any provision of the 2016 WCR in a way
that would make the result inconsistent with those recommendations.
Further, nothing in this final rule alters any elements of other rules
promulgated since Deepwater Horizon, including the Increased Safety
Measures for Energy Development on the OCS (Drilling Safety Rule) (75
FR 63346, October 14, 2010), SEMS I and II (75 FR 63610, October 15,
2010, 78 FR 20423, April 5, 2013). BSEE's review has been thorough,
careful, and tailored to the task of reducing unnecessary regulatory
burdens, while ensuring that operators conduct OCS activities in a safe
and environmentally responsible manner.
Table of Contents
I. Background
    A. BSEE Statutory and Regulatory Authority and Responsibilities
    B. Purpose and Summary of the Rulemaking
    C. Summary of Documents Incorporated by Reference
    D. Executive and Secretary's Orders
    E. Stakeholder Engagement
II. Discussion of Compliance Dates for the Final Rule
    A. April 29, 2021--Alternative Cutting Device No Longer Allowed
    B. May 1, 2023--Drill Pipe Positioning Within Shearing Blades
III. Discussion of Final Rule Requirements
    A. Summary of Key Regulatory Provisions
    B. Summary of Significant Differences Between the Proposed and
Final Rules
    1. Safe Drilling Margin--Sec. Sec.  250.414 and 250.427(b)
    2. Centering Capabilities While Shearing--Sec. Sec.  250.732 and
250.734(a)(16)
    3. Shearing Combinations--Sec.  250.734(a)(1)(ii)
    4. Subsea Accumulator Capacity--Sec.  250.734(a)(3)(iii)
    5. 21-Day BOP Testing Frequency--Sec.  250.737
IV. Discussion of Public Comments on the Proposed Rule
    A. General Support for the Proposed Rule
    B. General Opposition to the Proposed Rule
    C. 21-Day BOP Testing Frequency
    D. BSEE Approved Verification Organization (BAVO)
    E. Legal Comments
    F. Economic Comments
    G. Environmental Comments
    H. Miscellaneous Comments
V. Section-by-Section Summary and Responses to Comments on the
Proposed Rule
VI. Procedural Matters
List of Acronyms and References
ANL Argonne National Laboratory
ANPR Advance Notice of Proposed Rulemaking
ANSI American National Standards Institute
APA Administrative Procedure Act
APD Application for Permit To Drill
API American Petroleum Institute
APM Application for Permit to Modify
ASME American Society of Mechanical Engineers
BAST Best Available and Safest Technology
BAVO BSEE Approved Verification Organization
BOEM Bureau of Ocean Energy Management
BOP Blowout Preventer
BSEE Bureau of Safety and Environmental Enforcement
BSR Blind Shear Ram
BTS Bureau of Transportation Statistics
CDWOP Conceptual Deepwater Operations Plan
Department Department of the Interior
DWOP Deepwater Operations Plan
EA Environmental Assessment
ECD Equivalent Circulating Density
EIS Environmental Impact Statement
E.O. Executive Order
EOR End of Operations Report
ESA Endangered Species Act
FOIA Freedom of Information Act
FONSI Finding of No Significant Impact
FRIA Final Regulatory Impact Analysis
FSHR Free Standing Hybrid Riser
GDP Gross Domestic Product
HPHT High Pressure High Temperature
IADC International Association of Drilling Contractors
IBR Incorporated By Reference
IC Information Collection
IEC International Electrotechnical Commission
IOGP International Association of Oil And Gas Producers
IRIA Initial Regulatory Impact Analysis
ISO International Organization For Standardization
JIP Joint Industry Project
LMRP Lower Marine Riser Package
MASP Maximum Anticipated Surface Pressure
MIA Mechanical Integrity Assessment
MODU Mobile Offshore Drilling Unit
MPB Multiple Physical Barrier
NAICS North American Industry Classification System
NEPA National Environmental Policy Act
NPRM Notice of Proposed Rulemaking
NTTAA National Technology Transfer and Advancement Act
OCS Outer Continental Shelf
OCSLA Outer Continental Shelf Lands Act
OEM Original Equipment Manufacturer
OFR Office of the Federal Register
OIRA Office of Information and Regulatory Affairs
OMB Office of Management Budget
OORP Office of Offshore Regulatory Programs
Psi pounds per square inch
Ppg pounds per gallon
PRA Paperwork Reduction Act
PWD Pressure While Drilling
QRA Quantitative Risk Analysis
RCD Regional Containment Demonstration
RFA Regulatory Flexibility Analysis
RIA Regulatory Impact Analysis
ROT Remotely Operated Tools
ROV Remotely Operated Vehicle
RTM Real-Time Monitoring
SBA Small Business Administration
SCCE Source Control and Containment Equipment
SDO Standards Development Organization
Secretary Secretary of the Interior
SEMS Safety and Environmental Management Systems
SPPE Safety and Pollution Prevention Equipment
SRAM System Risk Assessment Management
TBT Technical Barriers to Trade
WAR Well Activity Report
WCP Well Containment Plan
WCR Well Control Rule
WTO World Trade Organization
I. Background
A. BSEE Statutory and Regulatory Authority and Responsibilities
    BSEE derives its authority primarily from the Outer Continental
Shelf Lands
[[Page 21910]]
Act (OCSLA), 43 U.S.C. 1331-1356a. Congress enacted OCSLA in 1953,
authorizing the Secretary of the Interior (Secretary) to lease the OCS
for mineral development, and to regulate oil and gas exploration,
development, and production operations on the OCS. The Secretary
delegated authority to perform certain of these functions to BSEE.
    To carry out its responsibilities, BSEE regulates offshore oil and
gas operations to enhance the safety of exploration for and development
of oil and gas on the OCS, to ensure that those operations protect the
environment, and to implement advancements in technology. BSEE also
conducts onsite inspections to ensure compliance with regulations,
lease terms, and approved plans and permits. Detailed information
concerning BSEE's regulations and guidance to the offshore oil and gas
industry may be found on BSEE's website at: https://www.bsee.gov/guidance-and-regulations.
    BSEE's regulatory program covers a wide range of facilities and
activities, including drilling, completion, workover, production,
pipeline, and decommissioning operations. Drilling, completion,
workover, and decommissioning operations are types of well operations
that offshore operators \2\ perform throughout the OCS. These well
operations are the primary focus of this rulemaking.
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    \2\ BSEE's regulations at 30 CFR part 250 generally apply to ``a
lessee, the owner or holder of operating rights, a designated
operator or agent of the lessee(s). . . ,'' covered by the
definition of ``you'' in Sec.  250.105. For convenience, this
preamble will refer to all of the regulated entities as
``operators,'' unless otherwise indicated.
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B. Purpose and Summary of the Rulemaking
    This final rule amends and updates certain provisions of the
Blowout Preventer Systems and Well Control regulations and updates the
regulations to better implement BSEE policy. This final rule will
strengthen the Administration's policy of facilitating energy security
leading to increased domestic oil and gas production, and reduce
unnecessary burdens on stakeholders while still maintaining safety and
environmental protection. Since 2010, in order to improve worker safety
and environmental protection, BSEE has promulgated a number of rules
(e.g., Safety and Environmental Management Systems I and II (75 FR
63610, October 15, 2010; 78 FR 20423, April 5, 2013), the final safety
measures rule (77 FR 50856, August 22, 2012), the production safety
systems final rule (83 FR 49216, September 28, 2018), and the 2016 WCR
(81 FR 25888; April 29, 2016). The 2016 WCR consolidated into one part
the equipment and operational requirements pertaining to BOP and well
control for offshore oil and gas drilling, completions, workovers, and
decommissioning that were previously codified in various parts of
BSEE's regulations. More specifically, the 2016 WCR incorporated
industry standards; adopted reforms to well design, well control,
casing, cementing, real-time well monitoring, and subsea containment
requirements; and implemented many of the recommendations arising from
various investigations of the Deepwater Horizon incident. Most of the
provisions of the 2016 WCR became effective on July 28, 2016.
    Since the time the 2016 WCR regulations took effect, oil and
natural gas operators have raised various concerns, and BSEE has
identified issues during the implementation of the rule. The concerns
and issues involve certain regulatory provisions that impose undue
burdens on oil and natural gas operators, but do not significantly
enhance worker safety or environmental protection. BSEE understands the
operators' concerns that have been raised, but BSEE also fully
recognizes that the BOP and other well-control requirements are
critical to ensure safety and environmental protection. Consistent with
recent Executive and Secretary's Orders (discussed further in Section
I.D below) and congressional direction, BSEE undertook a review of the
2016 WCR. It did so with a view toward the policy direction of
encouraging energy exploration and production on the OCS and reducing
unnecessary regulatory burdens, while ensuring that any such activity
is conducted in a safe and environmentally responsible manner. BSEE
carefully analyzed all 342 provisions of the 2016 WCR, and proposed to
revise or add to 71 provisions--or approximately 20%--of the 2016 WCR
provisions. In the process, BSEE compared each of the changes to the
424 recommendations arising from 26 separate reports from 14 different
organizations \3\ developed in the wake of and response to the
Deepwater Horizon disaster. This final rule is consistent with the
proposed revisions and none of the final changes ignore or contradict
any of those recommendations, or alters any provision of the 2016 WCR
in a way that would make the result inconsistent with those
recommendations. Further, nothing in this final rule alters any
elements of other rules promulgated since Deepwater Horizon, including
the Drilling Safety Rule (Oct. 2010), SEMS I (Oct. 2010), and SEMS II
(April 2013). BSEE's review was thorough, careful, and tailored to the
task of reducing unnecessary regulatory burdens while ensuring that OCS
activity is conducted in a safe and environmentally responsible manner.
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    \3\ DOI, DOI OCS Safety Oversight Board, DOI OIG, DOI/Department
of Homeland Security (DHS) Joint Investigation Team, National
Commission on the BP Deepwater Horizon Oil Spill and Offshore
Drilling, Chief Counsel for the National Commission, National
Academy of Engineering, Joint Industry Subsea Well Control and
Containment Task Force, Environmental Law Institute, Ocean Energy
Safety Advisory Committee, Chemical Safety Board, Joint Industry Oil
Spill Preparedness and Response Task Force, Transportation Research
Board, U.S. Government Accountability Office (GAO).
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    This rule revises current regulations that impact offshore oil and
gas drilling, completions, workovers, and decommissioning activities.
The final regulations also address various issues that BSEE identified
during the implementation of the 2016 WCR, as well as numerous
questions that have required substantial informal guidance from BSEE
regarding the interpretation and application of the 2016 WCR.\4\ For
example, this final rule:
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    \4\ BSEE posted approximately 100 responses to questions
regarding the 2016 WCR provisions on the BSEE web page https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule.
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     Clarifies the rig movement reporting requirements.
     Clarifies and revises the requirements for certain
submittals to BSEE to eliminate redundant and unnecessary reporting.
     Clarifies the drilling margin requirements in Sec. Sec.
250.414 and 250.427.
     Revises Sec.  250.723 by removing references to lift boats
from the section.
     Removes certain prescriptive requirements for RTM.
     Replaces the use of a BAVO with the use of an independent
third party for certain certifications and verifications of BOP systems
and components, and removes the requirement to have a BAVO submit a
Mechanical Integrity Assessment report for the BOP stack and system.
     Revises the accumulator system requirements and
accumulator bottle requirements to better align with API Standard 53.
     Revises the control station and pod testing schedules to
ensure component functionality without inadvertently requiring
duplicative testing.
     Includes coiled tubing and snubbing requirements in
Subpart G.
     Revises the text to ensure consistency and conformity
across the applicable sections of the regulations.
     Revises the regulation to include a 21-day BOP testing
frequency.
[[Page 21911]]
C. Summary of Documents Incorporated by Reference
    This rule updates a document currently incorporated by reference to
a newer edition, includes an addendum to an already incorporated
standard, and adds two new standards for incorporation. A brief summary
of the final changes, based on the descriptions in each standard or
specification, is provided in the text that follows.
API Standard 53 and Addendum--Blowout Prevention Equipment Systems for
Drilling Wells
    API Standard 53 (Fourth Edition published November 2012) and
addendum (published July 2016) provide requirements for the
installation and testing of blowout prevention equipment systems whose
primary functions are to confine well fluids to the wellbore, provide
means to add fluid to the wellbore, and allow controlled volumes to be
removed from the wellbore. BOP equipment systems are comprised of a
combination of components that are covered by this document, Including:
Installations for surface and subsea BOPs; choke and kill lines; choke
manifolds; control systems; and auxiliary equipment. The document also
addresses equipment arrangements. The Addendum contains clarifications
to API Standard 53, 4th Edition.
    This standard also provides industry best practices related to the
use of dual shear rams, maintenance and testing requirements, and
failure reporting. The standard does not address diverters, shut-in
devices, and rotating head systems (rotating control devices), whose
primary purpose is to safely divert or direct flow, rather than to
confine fluids to the wellbore. It also does not include procedures and
techniques for well control and extreme temperature operations.
API Bulletin 92L--Drilling Ahead Safely With Lost Circulation in the
Gulf of Mexico
    API Bulletin 92L, First Edition, was published in August 2015. API
Bulletin 92L addresses drilling margins and drilling ahead with lost
circulation in wells drilled in the OCS environments. The drilling
margin is the difference between the maximum pore pressure and minimum
fracture pressure of a formation. Lost circulation is the flow of
drilling fluid into the formation instead of returning up the annulus.
If uncontrolled, lost circulation can lead to consequences potentially
as severe as a blowout. This bulletin identifies items that should be
considered to safely address lost circulation challenges when
equivalent circulation density (ECD) exceeds the fracture gradient of a
formation. It also provides guidance regarding appropriate responses
when lost circulation is experienced with either surface or subsea BOP
stack operations (excluding diverter operations). Lastly, the bulletin
recommends four decision tree flow charts for common lost circulation
scenarios in the OCS: (1) Drilling Exploration Wells with Lost
Circulation; (2) Drilling Ahead Below Salt with Lost Circulation; (3)
Drilling Depleted Zones with Lost Circulation; and (4) Managed Pressure
Drilling with Lost Circulation. Although similar, each flow chart is
unique and specific to the circumstances surrounding the lost
circulation event. The flow charts serve as an aid for operators to use
when deciding how best to safely drill ahead when lost circulation
occurs.
API Standard 65--Part 2, Isolating Potential Flow Zones During Well
Construction
    This standard, which API issued in December 2010 (reaffirmed
November 2016), outlines the process for isolating potential flow zones
during well construction. The new Standard 65--part 2 enhances the
description and classification of well-control barriers, and defines
testing requirements for cement to be considered a barrier.
API Recommended Practice 17H--Remotely Operated Tools and Interfaces on
Subsea Production Systems
    The final rule updates the incorporated version of this document
from the First Edition (July 2004, reaffirmed January 2009) to the
Second Edition (June 2013) and Errata (January 2014). This recommended
practice provides general recommendations and overall guidance for the
design and operation of remotely operated tools (ROT) and remotely
operated vehicle (ROV) tooling used on offshore subsea systems. ROT and
ROV performance is critical to ensuring safe and reliable deepwater
operations and this document provides general performance guidelines
for this and associated equipment. One of the main differences between
the first edition and second edition of this recommended practice is
that the second edition includes provisions on high flow Type D hot
stabs.
International Organization for Standardization (ISO)/IEC (International
Electrotechnical Commission) 17021-1--Conformity assessment--
Requirements for Bodies Providing Audit and Certification of Management
Systems--Part 1: Requirements.
    The final rule incorporates into the regulations a reference to
ISO/IEC 1702-1, First Edition, June 15, 2015, for purposes of the
quality management system certification requirements of Sec.
250.730(d). This standard contains principles and requirements to
ensure the competence, consistency, and impartiality of bodies
providing audit and certification of all types of management systems.
It provides general requirements for such bodies performing audit and
certification in the fields of quality, the environment, and other
types of management systems. Incorporation of this standard will
provide clarity and consistency surrounding the critical qualifications
of entities responsible for certifying quality management systems for
the manufacture of BOP stacks.
How To View the Documents Incorporated by Reference
    When a copyrighted publication is incorporated by reference into
BSEE regulations, BSEE is obligated to observe and protect that
copyright. BSEE is working with the standards organizations to provide
free online viewing for standards incorporated by reference. Many such
organizations already make relevant standards publicly available free
of charge. BSEE provides members of the public with website addresses
where these standards may be accessed for viewing--sometimes for free
and sometimes for a fee. Standards development organizations decide
whether to charge a fee. One such organization, API, provides free
online public access to view read-only copies of its key industry
standards, including a broad range of technical standards. All API
standards that are safety-related and that are incorporated into
Federal regulations, or that are considered for incorporation, are
available to the public for free viewing online in the Incorporation by
Reference Reading Room on API's website at: http://publications.api.org.\5\ In addition to the
[[Page 21912]]
free online availability of these standards for viewing on API's
website, hardcopies and printable versions are available for purchase
from API. The API website address to purchase standards is: https://www.api.org/products-and-services/standards/purchase.
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    \5\ To view these standards online, go to the API publications
website at: http://publications.api.org. You must then log-in or
create a new account, accept API's ``Terms and Conditions,'' click
on the ``Browse Documents'' button, and then select the applicable
category (e.g., ``Exploration and Production'' or ``IBR Documents
Under Consideration'') for the standard(s) you wish to review.
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    The International Organization for Standardization (ISO) creates
documents that provide requirements, specifications, guidelines, or
characteristics that can be used consistently to ensure that materials,
products, processes, and services are fit for their purposes. All ISO
International Standards are available at the ISO Store for purchase at:
https://www.iso.org/store.html.
    For the convenience of members of the viewing public who may not
wish to purchase copies or view these incorporated documents online,
they may be inspected at BSEE's office in Houston, at 1919 Smith
Street, Suite 14042, Houston, Texas 77002. To make an appointment to
inspect incorporated material at the Houston BSEE office, call 1-844-
259-4779. BSEE may also make the standards available at its other
offices located in: Washington, DC; Sterling, Virginia; New Orleans,
Louisiana; Camarillo, California; and Anchorage, Alaska. Individuals
wishing to view standards at a BSEE office may make arrangements by
sending an email to: [email protected].
D. Executive and Secretary's Orders
    On March 28, 2017, the President issued Executive Order (E.O.)
13783--Promoting Energy Independence and Economic Growth (82 FR 16093).
The E.O. directed Federal agencies to review all existing regulations
and other agency actions with a goal toward ``avoiding regulatory
burdens that unnecessarily encumber energy production, constrain
economic growth, and prevent job creation.'' It instructs agencies to
``review existing regulations that potentially burden the development
or use of domestically produced energy resources and appropriately
suspend, revise, or rescind those that unduly burden the development of
domestic energy resources beyond the degree necessary to protect the
public interest or otherwise comply with the law.''
    On April 28, 2017, the President issued E.O. 13795--Implementing an
America-First Offshore Energy Strategy (82 FR 20815), which directed
the Secretary to review the 2016 WCR for consistency with the policy
``to encourage energy exploration and production, including on the
Outer Continental Shelf, in order to maintain the Nation's position as
a global energy leader and foster energy security and resilience for
the benefit of the American people, while ensuring that any such
activity is safe and environmentally responsible'' and to ``publish for
notice and comment a proposed rule revising that rule, if appropriate
and as consistent with law.'' It further directed the Secretary of the
Interior to ``take all appropriate action to lawfully revise any
related rules and guidance for consistency with the policy set forth in
section 2 of this order. Additionally, the Secretary of the Interior
shall review BSEE's regulatory regime for offshore operators to
determine the extent to which additional regulation is necessary.''
    To further implement E.O. 13795, the Secretary issued Secretary's
Order No. 3350 on May 1, 2017, directing BSEE to review the 2016 WCR
for consistency with E.O. 13795 and prepare a report ``providing
recommendations on whether to suspend, revise, or rescind the rule'' in
response to concerns raised by stakeholders that the 2016 WCR
``unnecessarily include[s] prescriptive measures that are not needed to
ensure safe and responsible development of our OCS resources.''
    Based on E.O.s 13783 and 13795, congressional guidance, and
Secretary's Order No. 3350, and in light of the requests received for
clarification and revision of various provisions, BSEE reviewed the
regulations promulgated through the 2016 WCR and is making revisions to
those regulations that will reduce unnecessary burdens on industry
without affecting key 2016 WCR provisions that have a significant
impact on improving safety and equipment reliability.
    On September 28, 2018, the Department of the Interior (Department)
issued Secretary's Order No. 3369 (S.O. 3369), ``Promoting Open
Science.'' S.O. 3369 directs bureaus within the Department to ensure
that their use of science in decision-making is open and transparent to
facilitate public awareness, and to ensure that, when decisions are
based on scientific data or literature, bureaus utilize the ``best
available science.'' As previously discussed, BSEE used a number of
sources of information to inform decisions related to these revisions,
including comments received through a ``Request for comments'' on the
DOI's regulatory reform initiatives, published in the Federal Register
on June 22, 2017 (82 FR 28429), and experience gained during the
implementation of the 2016 WCR and the policies developed in response
to those experiences. In addition, BSEE solicited input from interested
parties to identify potential revisions to the regulations, including
through the public forum held on September 20, 2017, in Houston, Texas.
Further, BSEE gained valuable insights from comments received in
response to the proposed rule. BSEE regulatory staff used information
from these sources and worked directly with BSEE regional subject
matter experts to assess the current requirements for well control and
blowout preventers in order to determine which provisions could
potentially be revised, while leaving critical safety provisions intact
to maintain safety and environmental protection. BSEE also reviewed
publically available lists of alternate procedures and departures that
BSEE granted through permits, and reviewed past incident data,
specifically concerning information on equipment failure after a
successful seal of the well.
E. Stakeholder Engagement
Implementation of the 2016 WCR--BSEE Qs and As
    The Department promulgated the original ``Blowout Preventer Systems
and Well Control'' final rule (WCR) (81 FR 25888, April 29, 2016).
Subsequently, during the implementation of the regulations, BSEE
received numerous questions from stakeholders seeking clarification and
guidance concerning the 2016 WCR's provisions. The questions covered a
vast array of issues and spanned multiple subparts of the regulations.
    BSEE reviewed each question it received and decided whether the
question presented an issue that was appropriate for Bureau guidance.
To the extent that a question required guidance or clarification, BSEE
provided a response to clarify any potentially confusing language. In
addition to deciding on the appropriateness of a question for guidance,
BSEE determined whether the question was of sufficient public interest
to merit broader publication of a response. After finalizing regulatory
guidance in response to a stakeholder's question, BSEE typically
publishes both the question and BSEE's answer on its web page. The
information, which reflects BSEE's guidance on the current regulations,
may be found at: https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule. BSEE posted approximately 100 responses
to questions regarding the 2016 WCR provisions on the web page.
    BSEE reexamined the questions and answers pertaining to the 2016
WCR.
[[Page 21913]]
After carefully considering all relevant information in the questions
and answers, BSEE determined that it is appropriate to revise certain
of the regulations promulgated through the 2016 WCR to support the
goals of the regulatory reform initiative, while still maintaining
safety and environmental protection. Additionally, the revisions will
help clarify any ambiguity in the regulatory language, eliminate
redundancies in the provisions, and align specific requirements more
closely with relevant technical standards.
    BSEE public forum on well control and blowout preventer rule: To
ensure a complete and thorough review of the 2016 WCR, prior to this
rulemaking, BSEE solicited input from interested parties to identify
potential revisions to the regulations promulgated through the 2016 WCR
that would reduce regulatory burdens while maintaining safety and
environmental protection on the OCS. BSEE held a public forum on
September 20, 2017, in Houston, Texas. More than 110 participants
attended and provided comments and suggestions. Participants included
representatives from:
     Federal agencies;
     Media;
     Oil and gas companies;
     Classification societies;
     Trade associations;
     Environmental groups; and
     Equipment manufacturers.
    Additionally, there were eight presentations made at the forum.
These presentations are available at: https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule/public%20forum.
II. Discussion of Compliance Dates for the Final Rule
    BSEE considered the public comments on the proposed rule, as well
as relevant information gained during, among other activities, BSEE's
interactions with stakeholders, involvement in development of industry
standards, and evaluation of current technology. Based on its analysis,
BSEE is setting an effective date of 60 days following publication of
the final rule, by which time operators will be required to comply with
most of the final rule's provisions. BSEE determined, however, that it
is appropriate to identify alternative compliance dates, subsequent to
the effective date of the final rule, for certain provisions identified
below. Detailed explanations for the requirements associated with these
compliance dates are provided in Sections IV and V of this preamble.
A. April 29, 2021--Alternative Cutting Device No Longer Allowed
    Current regulations require, at Sec.  250.733(a)(1), that operators
use an alternative cutting device capable of shearing any electric-,
wire-, or slick-line before closing the BOP if, prior to April 29,
2021, an operator's blind shear rams (BSR) are unable to cut such lines
under maximum anticipated surface pressure (MASP) and seal the
wellbore. After April 29, 2021, BSEE will no longer allow the use of an
alternative cutting device, and the BSR in the surface stack will be
required to shear any electric-, wire-, or slick-line under MASP and
seal the wellbore. BSEE is aware that some current BSR technology is
available to shear electric-, wire-, or slick-line. BSEE established
this extended timeframe to allow operators to acquire and install
equipment to meet the requirements and to discontinue the use of the
alternative cutting device. Current regulations at Sec.  250.733(b)(1)
require that new surface BOPs installed on floating production
facilities after April 29, 2019, comply with the BOP requirements of
Sec.  250.734(a)(1). This final rule extends that compliance date to
April 29, 2021, in order to eliminate any confusion between applicable
compliance dates for Sec. Sec.  250.733(b)(1) and 250.734(a)(1). The
dual shear ram requirements for both surface and subsea BOPs will now
have the same compliance date of April 29, 2021.
B. May 1, 2023--Drill Pipe Positioning Within Shearing Blades
    Current regulations at Sec.  250.734(a)(16)(i) require operators to
have the capability to position the drill pipe completely within the
area of the shearing blades during shearing operations no later than
May 1, 2023. This final rule retains that compliance date from the 2016
WCR.
III. Discussion of Final Rule Requirements
A. Summary of Key Regulatory Provisions
    After review of all the public comments received in response to the
proposed rule, BSEE determined that it will include the following
proposed revisions in this final rule. This final rule includes most of
the provisions in the proposed rule without change, although the final
rule revises several of the proposed provisions in response to
comments, as explained in sections IV and V of this preamble.
    Documents incorporated by reference \6\--The final rule:
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    \6\ To view online read-only API documents visit: http://publications.api.org/AccessToDocuments.aspx.
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     Requires compliance with the industry standards contained
in API Standard 53.
     Requires compliance with API RP 17H to standardize ROV hot
stab activities. This will allow certain functions of the BOP to be
activated remotely and within specified timeframes.
     Requires compliance with the cementing guidelines of API
Standard 65--Part 2 to help achieve a successful cement job.
     Requires compliance with ISO/IEC 17021-1, which provides
requirements of an entity that certifies quality management systems for
BOP stack manufacturing.
     Requires compliance with API Bulletin 92L, which provides
guidance regarding how to safely address lost circulation challenges.
    Safe drilling practices--The final rule:
     Requires operators to maintain safe drilling margins,
provides details on when operators may request BSEE approval of the
safe drilling margins, and specifies actions the operator must take if
a safe drilling margin cannot be maintained.
     Includes requirements related to downhole equipment that
operators use to help reduce the likelihood of a major well-control
event and ensure the overall integrity of the well.
     Requires real-time monitoring when conducting well
operations with a subsea BOP or with a surface BOP on a floating
facility, or when operating in a high pressure high temperature (HPHT)
environment. Also requires operators to develop and implement a real-
time monitoring plan. This will allow operators to anticipate and
identify issues in a timely manner and to utilize resources to assist
in addressing critical issues.
    Failure reporting and analysis--The final rule:
     Requires that operators report any significant problems
with BOP or well-control equipment to BSEE or BSEE's designated third
party, so BSEE can help analyze failure trends and determine whether
information should be provided, in a timely manner, to OCS operators
and, if appropriate, to international offshore regulators and
operators.
     Requires that operators conduct an investigation and
failure analysis within a designated timeframe to help ensure that the
causes of failures are identified and addressed.
[[Page 21914]]
    Equipment requirements--The final rule:
     Requires access to and utilization of well intervention
equipment for certain subsea completed wells with a tree installed.
This will allow the necessary equipment to be maintained and available
to perform intervention operations when necessary.
     Requires the BOP accumulator capacity to provide fast
closure of the BOP components for autoshear/deadman in accordance with
API Standard 53.
    Operational requirements--The final rule:
     Requires retesting protocols for when the BOP or lower
marine riser package (LMRP) are unlatched and then relatched. These
requirements provide clarity for the testing required when an operator
returns to a well location and relatches the BOP or LMRP to the well.
These tests help confirm that the BOP or LMRP is properly functional
prior to resuming operations after being removed.
     Requires high and low pressure testing procedures for
certain BOP components. The testing requirements codify BSEE policy and
provide clarity and consistency for permitting.
     Requires the development of an alternate testing schedule
for control stations and pods for subsea BOPs. The intended result of
an alternating testing schedule is to ensure that operators can use
each control station, and each pod for subsea, to properly function all
required BOP components, while reducing unnecessary duplicative testing
and risk of component wear.
B. Summary of Significant Differences Between the Proposed and Final
Rules
    After consideration of all relevant and significant comments, BSEE
made a number of revisions from the proposed rule to the final rule. We
are highlighting several of these changes here because they are
significant and because numerous comments addressed these topics.
Discussions of the relevant and significant comments and BSEE's
responses are found in sections IV and V of this preamble. The
significant revisions made in response to comments include:
1. Safe Drilling Margin--Sec. Sec.  250.414 and 250.427(b)
    When drilling a well, operators use the hydrostatic pressure from a
mud column to keep sufficient pressure on the formation to prevent gas
or oil from flowing into the wellbore (i.e., a ``kick''). If the
hydrostatic pressure from the mud column is too high, however, the
formation may fracture and result in a significant number of
operational issues, one of which is ``lost returns.'' Lost returns, or
lost circulation, occur when drilling fluids escape from the well into
the formation. A drilling margin is the difference between the pore
pressure of the formation, with the mud weight taken into
consideration, and the fracture pressure of the formation. The 2016 WCR
established a default minimum drilling margin of 0.5 ppg, but also
provided avenues for operators to obtain approval of lower margins
through the permitting process (81 FR 25894). Since the effective date
of the 2016 WCR, BSEE has approved many Applications for Permit to
Drill (APDs) with a drilling margin less than 0.5 ppg.\7\ BSEE did not
propose changes to the 0.5 ppg safe drilling margin requirements;
however, BSEE solicited comments on possible revisions to, or options
regarding, the 0.5 ppg drilling margin issue.
---------------------------------------------------------------------------
    \7\ Between August 1, 2016 and March 22, 2018, ``BSEE's records
show that there have been 305 wells drilled. Of those wells, BSEE
approved operators' use of drilling margins that are less than 0.5
ppg for 32 wells.'' 83 FR 22128, 22133 (May 11, 2018).
---------------------------------------------------------------------------
    Multiple commenters recommended replacing the current requirement
with a performance-based standard under which an approved safe drilling
margin would be established on a case-by-case basis, based on data and
analysis specific to a particular well. They suggested that this is a
safer and better alternative that would provide a risk-based approach
that ensures safety and provides investment certainty to the industry.
Multiple commenters also submitted comments on Sec.  250.427 and
recommended that, in instances where an operator encounters a lost
circulation zone, the operator should have options for safely
addressing the situation. In particular, many commenters asserted that
suspending operations in certain circumstances may negatively impact
safety and that drilling ahead to get through a lost circulation zone
may be the safest option to restore the integrity of the well. For
example, a commenter asserted that suspending drilling while in the
weak zone to set casing (or otherwise remedy the situation) may simply
transfer risk to a deeper hole section, where conditions may be even
more challenging. Commenters suggested that it is appropriate for
operators to specify in the Deepwater Operations Plan (DWOP) or APD how
they will remedy an anticipated loss of circulation on bottom. They
suggested using API Bulletin 92L as the standard for responding to such
situations. A significant number of commenters also strongly opposed
any changes to the 0.5 ppg drilling margin requirements in the current
regulations.
    In this final rule, BSEE is not revising the 0.5 ppg default
drilling margin requirement or the requirements for justifying any
alternative equivalent downhole mud weight. However, based on comments
received, BSEE is revising Sec.  250.414(c)(2) to allow operators the
option to submit the required justification for BSEE approval at an
earlier date rather than waiting to submit with the APD. The proposed
rule indicated that BSEE was considering ``whether it should adhere to
its practice of identifying a specific drilling margin with an avenue
for allowing operators to submit adequate documentation justifying the
use of a different drilling margin . . . .'' (83 FR 22133). The
relevant comments informed BSEE's decision to revise Sec.
250.414(c)(2) to permit submission of the alternative drilling margin
justification prior to submitting an APD. Also, based on comments
received, BSEE is revising Sec.  250.427(b) to allow an operator to
respond to lost circulation events in accordance with API Bulletin 92L
and to require notification to the BSEE District Manager documenting
the operator's use of API Bulletin 92L.\8\ In conjunction with the use
of API Bulletin 92L, BSEE is requiring that an operator submit a
revised permit documenting any remedial actions. BSEE is also
clarifying that the District Manager must review and approve proposed
remedial actions in an APD. BSEE recognizes that API Bulletin 92L may
not be a consensus document. According to API policy,\9\ documents that
are classified as ``bulletins'' may be developed without following a
consensus process, which is the preferred process for documents
incorporated by reference in government regulations according to the
guidance in OMB Circular A-119. However, OMB Circular A-119 does not
preclude the use of standards that are developed without following a
voluntary consensus process. API Bulletin 92L addresses specific
technical issues, such as lost circulation while drilling, to help
operators diagnose well stability issues and remedy the situation. BSEE
determined that this document is consistent with BSEE policy in the
approaches used to
[[Page 21915]]
address these issues, appropriate for meeting the agency's regulatory
needs, and preferable to an agency-developed standard. Therefore, API
Bulletin 92L is appropriate for incorporation into the regulations,
even though it is a non-consensus developed bulletin. BSEE has
evaluated API Bulletin 92L and determined that compliance with it would
not reduce safety. The content of the bulletin includes flow charts
that can be used as an aid for operators to use in deciding how best to
safely drill ahead when lost circulation occurs and the required
criteria and procedures are met.
---------------------------------------------------------------------------
    \8\ API Bulletin 92L provides operators with flow charts to help
evaluate what is happening in the well during lost circulation
events and to respond accordingly. (e.g., Depending on the situation
operators may have to stop drilling and run casing, or contact the
regulator and drill ahead no more than 300 ft.)
    \9\ The Organization and Procedures for the CSOEM: Policy
Document 2017 (S1) and the Procedures for Standards Development 2016
(Procedures for Standards Development).
---------------------------------------------------------------------------
2. Centering Capabilities While Shearing--Sec. Sec.  250.732 and
250.734(a)(16)
    Current regulations at Sec. Sec.  250.732 and 250.734 require the
use of a shear ram positioning mechanism to ensure that pipe is
centered within the area of the shearing blade. Since the publication
of the 2016 WCR, many of the shear ram designs have improved the
shearing capabilities to help ensure shearing is conducted on the
appropriate shearing area of the shear blades. This is commonly done by
shaping the shear ram cutting blades in a ``V'' or ``W'' pattern to
help center the pipe as it shears, as well as to increase the blade
face surface area to ensure there are no areas that cannot shear the
pipe in the well. Accordingly, BSEE proposed to remove the centering
mechanism requirements in both Sec. Sec.  250.732 and 250.734. However,
in the proposed rule preamble, BSEE solicited comments about the
effectiveness of requiring shear rams to center pipe or wire while
shearing, or requiring shear rams to have the capability to shear any
pipe or wire in the hole without a separate centering mechanism. BSEE
also discussed the option of retaining the centering mechanism
requirements, but expressly provided that the shear rams with these
capabilities satisfy the requirements.
    Based on comments, BSEE recognizes that the technology exists to
help ensure the pipe is positioned within the shear surface to optimize
shearing capabilities. BSEE agrees that even though this technology
exists, the rule as proposed would not have specifically required the
use of such technology. In this final rule, BSEE is now retaining the
existing requirement to maintain the capability to position the pipe
within the shearing blade, however BSEE will not require this to be
achieved using a separate mechanism and will allow this capability to
be accomplished with the shear ram itself. As encouraged by Congress
\10\ to ensure that offshore operations promote safety and protect the
environment in a technically feasible manner, BSEE does not want to
limit the use of improved technological advancements in shear blade
designs.
---------------------------------------------------------------------------
    \10\ Explanatory Statement to Accompany Div G. of Consolidated
Appropriations Act, 2017 (Interior, Environment, and Related
Agencies), Public Law 115-31 (May 5, 2017). (``Blowout Preventer
Systems and Well Control Rule.--The Committees encourage the Bureau
to evaluate information learned from additional stakeholder input
and ongoing technical conversations to inform implementation of this
rule. To the extent additional information warrants revisions to the
rule that require public notice and comment, the Bureau is
encouraged to follow that process to ensure that offshore operations
promote safety and protect the environment in a technically feasible
manner.''). 163 Cong. Rec. H 3327, 3880 (May 3, 2017).
---------------------------------------------------------------------------
3. Shearing Combinations--Sec.  250.734(a)(1)(ii)
    In the 2016 WCR, BSEE established that both shear rams must have
the capability to shear the specified equipment. During the development
of the 2016 WCR, BSEE did not receive comments specific to the ``both
shear rams'' provision.
    BSEE proposed to revise Sec.  250.734(a)(1)(ii) by clarifying that
a ``combination of the'' shear rams must be capable of shearing all the
items specified in the paragraph. BSEE is aware that certain casing
shears still have difficulty shearing electric-, wire-, or slick-line,
while certain BSRs have difficulties shearing larger casing sizes. As
stated in the proposed rule, the proposed revision would have provided
the operators flexibility for how they utilize the BOP system and
components for operations, while still ensuring all critical shearing
capabilities.
    Multiple commenters generally agreed with the proposed language;
however, other commenters opposed any changes to existing requirements.
Commenters expressed concerns about the proposed removal of the
requirement to have two fully redundant shear rams and suggested that
such a change would not account for the possibility of one shear ram
malfunctioning. The benefit of having two, fully capable shear rams is
a fully redundant back up. Under the proposed revisions, if one shear
ram were to fail and the remaining shear ram could not independently
shear the necessary equipment, well control might not have been
achieved.
    Based on comments received, BSEE is keeping the language in
existing Sec.  250.734(a)(1)(ii) that requires ``both shear rams to be
capable of shearing'' the specified equipment in the hole. BSEE
principally bases this decision on comments BSEE received concerning
the importance of shearing redundancy and a recognition that the
proposed language's reliance on a ``combination'' of shear rams
potentially interjected some ambiguity regarding the number of rams
subject to this shearing requirement.
    BSEE is not revising the dual shear ram requirements or the
associated compliance date of April 29, 2021, found in existing Sec.
250.734(a)(1).
4. Subsea Accumulator Capacity--Sec.  250.734(a)(3)(iii)
    The purpose of the accumulator system and applicable accumulator
capacity requirements is to ensure that there is sufficient volume and
pressure in the accumulator bottles to properly operate BOP components
in a specified timeframe regardless of the location of the accumulator
bottles.
    In the proposed rule, BSEE proposed to remove the reference to the
subsea location of the accumulator capacity. BSEE understands that the
accumulator system works together with the surface and subsea
accumulator capacity to achieve full functionality and BSEE determined
that it was unnecessary to specifically identify only subsea
requirements when API Standard 53 covers the entire system.
    BSEE received multiple comments supporting the proposed revisions;
however, BSEE also received comments asserting that BSEE had not
explained how removing the reference to the subsea location of
accumulator capacity would ensure that the accumulator system can
adequately function if there is a loss of the power fluid connection to
the surface. Based on these comments, BSEE has decided to keep the
clarification that certain accumulator capacity must be located subsea
in order to avoid confusion about how the autoshear and deadman systems
utilize accumulator capacity. The autoshear and deadman systems do not
use accumulator capacity from the surface accumulators. The conditions
to function these emergency systems involve the loss of electrical/
hydraulic communication or connection between the BOP stack and the
rig. Therefore, it is necessary to require that the autoshear and
deadman emergency systems' accumulator capacity must be able to
function properly without connection or communication with the surface
and therefore the accumulator capacity must be located subsea.
    In this final rule, BSEE is clarifying that the accumulator bottles
for the autoshear/deadman systems need to be located subsea. The
autoshear/deadman systems are not controlled by surface personnel and
are essentially considered failsafe. Consistent with the
[[Page 21916]]
existing regulations, the accumulator bottles that operate these
systems need to be located subsea to ensure there is enough fluid and
pressure to operate the associated functions. This is a clarification
to ensure there is no confusion about where the required fluid and
pressure must reside to operate the autoshear/deadman emergency
functions.
5. 21-Day BOP Testing Frequency--Sec.  250.737
    In the proposed rule, BSEE requested comments on whether the BOP
testing interval should be 7 days, 14 days, or 21 days for all
operations (i.e., drilling, completions, workovers, and
decommissioning). BSEE also requested comments on the specific cost and
operational implications of each testing interval to further its
consideration of the issue. Current regulations (multiple citations
throughout Sec.  250.737) require pressure and function testing of
specific BOP components for drilling, completions, workovers, and
decommissioning operations every 14 days. Although BSEE did not present
revisions to the testing frequency regulatory text in the proposed
rule, BSEE raised the option of 21-day BOP testing in the preamble.
    The industry and BSEE currently rely on function and hydrostatic
tests to verify the performance of BOP equipment in the field. These
tests have traditionally been the primary method of verifying the
capability of in-service equipment. In recent years, the industry has
raised concerns related to the benefits of pressure and function
testing of subsea BOPs when compared to the costs and potential
operational issues associated with such testing, including wear and
tear.
    BSEE received multiple comments supporting a 21-day BOP testing
frequency. These comments provided some data to justify a 21-day BOP
testing frequency. However, BSEE also received many comments opposing
any changes to the BOP testing frequency and a commenter even stated
that the BOP testing frequency should be increased to every 7 days.
    BSEE analyzed the justifications provided in the 2016 WCR for the
decision to adopt a 14-day rather than a 21-day testing frequency. The
relevant analysis offered little by way of data-driven conclusions, so
BSEE has, through this rulemaking, undertaken a thorough analysis of
the information available. In the final rule, based on comments
received, BSEE is revising Sec.  250.737 to allow the use of a 21-day
BOP testing frequency if an operator meets certain criteria and if BSEE
approves an operator's 21-day BOP testing frequency request. BSEE is
requiring operators to demonstrate, in the 21-day BOP testing frequency
request, that they have developed a BOP health monitoring plan that
includes certain system capabilities. BSEE is requiring the BOP health
monitoring plan to include condition monitoring tools that are able to
provide continuous surveillance of sensor readings from the BOP control
system, real-time condition analysis and displays, functional pressure
signal analysis, and trending capabilities of the sensor data. The
condition monitoring tools also must include failure propagation
analysis and a failure tracking and resolution system to identify
recurring problems. BSEE is also requiring operators to submit
quarterly reports of the data collected to the BSEE Regional
Supervisor, District Field Operations. BSEE will review this data to
help ensure compliance with the requirements of the regulations and
help support its continual analysis of the 21-day BOP testing
frequency.
    This approach offers a path for operators to avoid the identified
cost and operational concerns associated with more frequent testing,
while at the same time requiring that adequate and proven tools for
ensuring safety and environmental protection are in place before
testing frequency is changed to a 21-day interval.
IV. Discussion of Public Comments on the Proposed Rule
    In response to the proposed rule, BSEE received over 265 sets of
comments containing individually submitted comments and multiple
similar group form letters, totaling over 118,000 submittals. Comments
included submittals from individual entities (e.g., companies, industry
organizations, non-governmental organizations, State governments, and
private citizens). Some entities submitted comments multiple times and
a majority of the individual commenters submitted nearly identical
comments (similar to a form letter). Over 117,000 of the comments
submitted follow a type of form letter and contain similar comments.
All relevant comments are posted at the Federal eRulemaking portal:
http://www.regulations.gov. To access the comments at that website,
enter BSEE-2018-0002 in the Search box. BSEE reviewed all comments
submitted, and this section and section V of this preamble contain
brief summaries of the relevant comments as well as of BSEE's
responses.
A. General Support for the Proposed Rule
    BSEE received hundreds of comments expressing general support for
the proposed rule. The public comments expressing or suggesting general
support for the proposed rule as a whole or for some of its major
provisions comprise a few hundred of the total number of comments
received. BSEE received supporting comments from, but not limited to,
oil and gas companies, contractors, industry trade groups, equipment
manufacturers, class societies, private citizens, and legal firms. Some
of the commenters expressing general support for the proposed rule also
provided specific detailed comments, addressed further infra.
    The comments submitted by industry trade groups, operators, and
service companies generally supported the proposed alleviation of
administrative burdens and reduction of prescriptive regulations. As
rationale for their support of the proposed rule, those commenters
often identified concerns about how the current regulations increase
operational risks and impose unnecessary cost burdens but provide no
commensurate safety improvements or environmental protection. However,
while the commenters voiced support broadly for the proposed changes,
some of them also cited additional regulatory provisions that they
asserted impose unnecessary regulatory burdens that the proposed
revisions would not go far enough to relieve, as discussed in this
section and section V of this preamble.
B. General Opposition to the Proposed Rule
    A majority of entities and individuals that commented on the
proposed revisions expressed general opposition to the proposed rule
and many of its major proposals. A majority of those comments were
submitted by non-governmental organizations, environmental groups,
multiple State Attorneys General, lawmakers from the U.S. House of
Representatives and U.S. Senate, public, and academia.
    A large majority of the approximately 118,000 comments that BSEE
received voiced significant concerns about the proposed changes. The
rationale for the commenters' opposition to the proposed revisions to
the existing regulations generally fell into two main categories.
First, many commenters asserted that BSEE does not have sufficient
evidence to support many of the proposed revisions to the existing
regulations. However, many of the commenters did not provide additional
information/data
[[Page 21917]]
to support assertions. Comments in this first group highlighted the
fact that BSEE adopted the WCR in 2016 and thus asserted that it has
not had enough time to gather the data necessary to support any
changes.
    Second, some commenters cited the findings from the investigations
and reports arising out of Deepwater Horizon to support their general
contention that oversight of the oil and gas industry in the form of
regulations is vitally important and necessary. Among these comments,
opposition to the proposed rule was apparently premised on the belief
that any ``rollback'' of the existing regulations will adversely impact
safety and environmental protection.
    For a discussion of the substantive comments in opposition to
specific provisions and BSEE's responses, refer to later parts of this
section and Section V of this preamble.
C. 21-Day BOP Testing Frequency
    In the proposed rule, BSEE did not propose any specific regulatory
text changes to the existing requirement for the minimum 14-day testing
frequency for BOP systems. However, BSEE solicited comments in the
proposed rule on whether the BOP testing frequency should be 7 days, 14
days, or 21 days for all types of operations. BSEE also requested
comments on the adequacy of the current function and pressure test
requirements for BOP systems in predicting the performance of this
equipment in subsequent drilling operations. Furthermore, BSEE
requested comments about what circumstances or environments might
justify an increase or decrease to the required testing frequency.
    In addition, BSEE is aware of potential technologies that may
improve the operability and reliability of BOP systems and thus may
affect the need for and appropriate frequency of BOP testing.
Accordingly, BSEE also solicited comments on whether there are
additional technologies, processes, or procedures that can be used to
supplement existing requirements and provide additional assurances
related to the performance of this equipment. BSEE asked commenters to
provide justifications and data to support their comments.
Summary of Comments--21-Day BOP Testing Frequency
    BSEE received comments both supporting a 21-day BOP testing
frequency and opposing such a change. Numerous commenters proposed
aligning the regulatory requirement for BOP testing frequency with the
21-day testing frequency found in API Standard 53; some of those
commenters cited the fact that Texas regulations for onshore operations
have successfully used 21-day testing for many years. These commenters
cited studies indicating that a 21-day testing frequency: Provides for
a safe and reliable BOP system; aligns with global practices and
technological capabilities; and prevents extensive pressure testing
that can cause premature system wear. Some commenters also asserted
that function tests provide more reliable indications of BOP
performance. Commenters also suggested a pilot program that would
implement 21-day testing to gather data to assess the difference in BOP
performance between 14 and 21-day testing frequency. Another commenter
provided some data comparing the results of 14-day and 21-day BOP
testing worldwide. Another commenter suggested that a 21-day testing
interval is appropriate if there are tools, systems, and data
collection to ensure that the 21-day testing keeps operational risk and
process safety performance equivalent to the 14-day testing interval.
    Commenters who did not support the change to the 21-day testing
frequency noted that BSEE considered a 21-day BOP testing interval in
the context of the 2016 WCR, but rejected that testing interval because
the agency did not receive data to support it. The commenters further
asserted that BSEE is again proposing a 21-day BOP testing interval,
despite not having any new data to support the change. Another
commenter proposed a 7-day interval for BOP testing, along with a
recommendation that BSEE undertake a technical risk analysis of BOP
failure rates for 7-, 14-, and 21-day BOP test intervals. One commenter
suggested that BSEE postpone a revision to the BOP testing frequency
and solicit input from an advisory committee regarding what a
reasonable and prudent standard should be. A commenter requested that
BSEE show the impact of the proposed change on all system risks and
asserted that BSEE should not rely on industry comments as a basis for
the change.
     Response: After considering all comments regarding this
potential change, BSEE agrees with many of the commenters'
recommendations to allow a 21-day test frequency, under limited
circumstances when an operator meets appropriate qualifications.
Therefore, BSEE is revising Sec.  250.737 in the final rule to maintain
the 14-day test frequency as the default requirement, but to allow
operators to request special approval to use a 21-day BOP testing
frequency in lieu of a 14-day BOP testing frequency if the operator
meets certain criteria and receives BSEE approval. To address the
concerns raised by commenters regarding the availability of data that
demonstrates the impact on reliability due to testing frequency, the
final rule requires any operator seeking to change testing frequency to
develop a BOP health monitoring plan that includes condition monitoring
tools that provide continuous surveillance of sensor readings from the
BOP control system, real-time condition analysis and displays,
functional pressure signal analysis, and trending capabilities of the
sensor data. The condition monitoring tools also must include failure
propagation analysis and a failure tracking and resolution system to
identify recurring problems. BSEE is also requiring operators to submit
quarterly reports of the data collected to the BSEE Regional
Supervisor, District Field Operations. The BOP health monitoring plan
will provide BSEE with relevant data on how the BOP equipment operates
throughout the equipment lifecycle and additional assurance of the
successful functioning and oversight of the BOP equipment. BSEE will
review this data to help ensure compliance with the requirements of the
regulations and help support its continual analysis of the 21-day
testing frequency.
    These efforts are consistent with BSEE's implementation of E.O.s
13783 and 13795, congressional guidance, and Secretary's Order No. 3350
(described in Section I.D above).
    BSEE analyzed the justifications provided in the 2016 WCR for the
decision to adopt a 14-day rather than a 21-day testing frequency,
which offered little by way of data-driven conclusions. Following
closure of the comment period, BSEE undertook a thorough review of
available data, existing regulations, and all comments related to the
evaluation of 7-, 14-, and 21-day BOP testing interval requirements. As
part of its analysis, BSEE considered the BOP equipment failure
reporting data captured in the U.S. Department of Transportation Bureau
of Transportation Statistics (BTS) 2017 SafeOCS report titled Blowout
Prevention Safety System--2017 Annual Report.\11\ The report analyzed
1129 events and found that there were 1044 notifications for subsea
BOPs and 85 notifications for surface BOPs. Of the total events, 946
reported events were found while the BOPs were not in operation. That
report observes on page 28 that ``[w]ear and tear was the most
frequently reported root cause of
[[Page 21918]]
failures (53.6 percent).'' This data helps BSEE establish a baseline of
operating events for the 14-day BOP testing frequency. That report also
indicates that various forms of monitoring were responsible for
detecting at least as many reported ``in-operation'' BOP equipment
failures as the equipment failures detected through additional testing
during 2017. These data suggest that monitoring plays an important role
in the detection of BOP equipment failures, in conjunction with regular
testing. Health monitoring systems allow operators to detect and
remediate potential failures before they occur, and to understand
potential failures and their impact on overall BOP system reliability,
potentially contributing to downward failure trends. Accordingly, BSEE
determined that operators who desire to reduce the frequency of their
regular testing should be required to adopt more robust BOP health
monitoring capabilities to ensure that oversight of BOP operability is
not compromised. Adopting a 21-day testing frequency would align BSEE
requirements with the BOP testing provisions of API Standard 53 that
are widely utilized and accepted internationally. A 21-day testing
frequency would also align with widely adopted BOP testing standards
followed by the international offshore oil and gas industry. BSEE
contacted many international regulators \12\ responsible for overseeing
offshore operations and requested information on whether those
regulators allow the use of a 21-day BOP testing frequency. BSEE was
informed that, among others, Brazil, Denmark, the United Kingdom,\13\
and the Netherlands allow a 21-day BOP testing frequency. BSEE
recognizes the successful international use of the 21-day testing
frequency and relied, in part, on that experience to support its
decision that a 21-day testing frequency may be appropriate for OCS
operations under certain conditions.
---------------------------------------------------------------------------
    \11\ https://www.safeocs.gov/2017_WCR_Annual_Report_v4.pdf.
    \12\ Canada-Nova Scotia Offshore Petroleum Board (CNSOPB),
Canada-Newfoundland and Labrador Offshore Petroleum Board, Danish
Offshore Oil and Gas, United Kingdom, Brazil ANP (National Agency of
Petroleum, Natural Gas and Biofuels), Norway PSA (Petroleum Safety
Authority), and Australia National Offshore Petroleum Safety and
Environmental Management Authority.
    \13\ http://www.hse.gov.uk/offshore/ed-well-control.pdf.
---------------------------------------------------------------------------
    BSEE also requires additional specified function testing of certain
BOP components. For example, existing Sec.  250.737(d)(9) requires BOP
function testing of annular and pipe/variable bore rams every 7 days.
This function testing would continue to confirm important aspects of
BOP functionality at more frequent intervals if pressure testing is
conducted at a 21-day frequency.
    In addition, one commenter submitted an analysis of field pressure
testing data across two rigs with similar BOP equipment--one subject to
14-day testing under requirements applicable in the Gulf of Mexico and
the other on a 21-day testing cycle overseas. The commenter's analysis
indicates that no reduction in BOP reliability was found in connection
with the international 21-day testing standards. BSEE reviewed the
commenter's data and agrees that the commenter's analysis demonstrates
successful use of 21-day BOP testing.
Summary of Comments--21-Day BOP Testing Frequency in the Economic and
Environmental Analyses
    Multiple commenters questioned the validity of BSEE's cost and
environmental analyses and asserted that BSEE did not provide any
concrete data or analysis to support a change to the BOP testing
frequency in the regulations.
     Response: BSEE disagrees with the commenters' assertion
that the draft economic and environmental analyses released with the
proposed rule were invalid. BSEE reviewed all relevant comments related
to these analyses and updated or revised them, as appropriate, for the
final rule (see discussions of the 21-day testing provisions in the
environmental assessment and Regulatory Impact Analysis).
D. BSEE Approved Verification Organization (BAVO)
    The 2016 WCR established criteria and associated requirements
related to the use of BAVOs. Pursuant to the regulations promulgated
through the 2016 WCR, a BAVO is an entity that submits qualifications
to BSEE and receives BSEE approval in order to perform certain
independent engineering reviews and provides reasonable assurances that
certain equipment would perform as designed under the operating
conditions relevant to the particular well where the equipment will be
used. The 2016 WCR regulations at Sec. Sec.  250.731, 250.732, 250.734,
250.738, and 250.739 covered BAVO requirements. The 2016 WCR
established that the BAVO requirements would not take effect until one
year after BSEE published a list of BAVOs. BSEE has not yet published a
BAVO list; accordingly, the BAVO requirements are not currently
effective. However, the 2016 WCR also required that operators use
independent third-parties to perform certain of the certifications,
verifications, and reporting functions pending implementation of the
BAVO requirements.
    In the proposed rule, BSEE proposed to remove all references to
BAVOs and to replace them with references to an independent third party
in Sec. Sec.  250.731, 250.732, 250.734, 250.738, and 250.739. BSEE
received many comments supporting these proposed changes. This section
includes a summary of the general BAVO-related comments and BSEE
responses. For additional discussions of comments associated with BAVO-
specific provisions and BSEE responses, refer to section V of this
final rule preamble.
    Summary of comments: Multiple commenters expressed concerns that
changing BAVO requirements in the new rule would negatively affect
safety and accountability. Multiple comments requested keeping the
requirement for BSEE to certify BAVOs, as described in the 2016 WCR.
Those commenters desired assurance that the third-party will be well-
qualified for the extremely important work that is required, which
includes verifying and documenting the proper functioning of the BOP. A
commenter requested that BSEE explain how it will ensure that third-
party reviewers are truly independent, qualified, and consistent in
their execution of inspections and establish a process to evaluate the
independent third parties. Another commenter recommended that BSEE not
surrender the authority to approve the third-party organizations. A
different commenter asserted that BSEE cannot avoid the
responsibilities it has to ensure drilling safety by allowing
inspections by organizations that may not have the expertise or
capacity to determine whether blowout preventers are being correctly
operated and maintained. Another commenter asserted that this change
would reduce oversight, suggesting that if BSEE does not have a role in
approving the inspectors, the operators would be able to choose who
inspects their BOPs, and that such inspectors would not even be
required to be present during inspection. One commenter asserted that
reports prepared by a third-party that is not present during the actual
inspection would be of minimal value and be too late to affect real
change/improvement.
     Response: BSEE does agree that the independent third-
parties need to be qualified to perform the required work. The
independent third-party must have the qualifications listed under Sec.
250.732(b), which requires the independent third-party to be a
technical classification society, or a licensed professional
engineering firm, or a registered professional engineer
[[Page 21919]]
capable of providing the required certifications and verifications. As
BSEE described in the preambles to the 2016 WCR and the proposed rule,
BSEE expected most of the companies or individuals that would be
approved as BAVOs to be drawn from the group currently being used as
independent third-parties. BSEE determined that, under these
circumstances, submittal to become a BAVO would be unnecessary and
would not provide significant meaningful improvements to safety or
environmental protection. BSEE has increased its interaction with the
independent third-parties to better understand how they operate and
carry out certifications and verifications. For example, BSEE engineers
and inspectors are regularly on a rig or at a testing facility
concurrently with independent third-parties during BOP testing. BSEE
utilizes these opportunities to observe the independent third-parties
and discuss the required verifications for the associated operations
with them. If BSEE becomes aware of any concerns with the required
independent third-party certifications or verifications, there are
still options for BSEE to address the issues through the operator
(e.g., verifications through the permitting process).
    BSEE disagrees with the assertions that BSEE is surrendering
authority to approve third parties, that BSEE is avoiding
responsibilities for ensuring safety, or that the changes reduce
oversight. The regulatory revision that eliminates the BAVO process
will continue to meet the objectives BSEE stated in 2015: ``The
objective is to have this equipment monitored during its entire
lifecycle by an independent third-party to verify compliance with BSEE
requirements, OEM recommendations, and recognized engineering
practices. The BSEE believes that the importance and complexity of BOP
systems and the fact that they might be operated at various worldwide
locations throughout their service life warrants a thorough and regular
assessment of the systems and verification that design, installation,
maintenance, inspection, and repair activities are documented and
traceable.'' (Proposed WCR, 80 FR 21504).
    Although the regulations allow operators to select the independent
third party who performs the inspection, there are multiple paths by
which BSEE can directly verify the adequacy of independent third party
performance. For example, BSEE will continue to review the
verifications and certifications submitted by independent third parties
and confirm that they provide a sufficient level of detail to ensure
compliance with the regulations. Since 2015, BSEE has consistently
articulated the importance of independent third-party verification and
documentation. This regulatory amendment does not eliminate or reduce
the role of such verification and documentation. While the regulations
do not require the independent third party to be present at the major
inspections, they require the independent third party to review the
documentation of the inspections to help ensure that the appropriate
entities accurately and appropriately complete the inspection and
maintenance. The independent third party document review also allows
the comparison of the design data to the current status of the
equipment. The intent of the major inspection is to verify that the
well control system components are fit for service and within design
tolerances to be utilized for specific well conditions, which can be
verified through a data review and does not require a physical
presence.
    Summary of comments: Commenters suggested that BSEE should take
steps to ensure that any third-party is acting in good faith before it
verifies rig safety measures and that BSEE should provide additional
explanation and justification to support the proposed change.
     Response: BSEE agrees with the commenters that the
independent third-parties must act in good faith and be capable and
competent when conducting the required verifications and
certifications. The qualification requirements set forth in final Sec.
250.732(b) are designed, in part, to ensure such professional
standards. If BSEE becomes aware of any concerns with certifications or
verifications that are performed by an independent third-party as
required by the regulations, BSEE retains options to address these
potential issues through its regulation of the operator (e.g.,
verifications through the permitting process).
    Summary of comments: A commenter asserted that the proposed
definition of independent third-party is too broad and would allow
organizations or individuals to perform verification activities without
having the proper expertise. The commenter recommends retaining and
applying the current BAVO requirements found in previous Sec.
250.732(a)(3)(i) through (vi) to potential independent third-parties.
     Response: BSEE disagrees with the commenter's suggestion
to include the identified BAVO requirements in this final rule. Final
Sec.  250.732 paragraph (b) references the independent third party
qualifications. The existing regulations do not require a BAVO to be a
technical classification society, a licensed professional engineering
firm, or a registered professional engineer capable of performing the
required actions; however, for an individual or company to become an
independent third-party that performs the required certifications and
verification under this final rule, it must continue to meet the
qualifications currently set forth in Sec.  250.732(a)(2) and being
retained in the final rule at Sec.  250.732(b). These standards ensure
a level of professional competence and independence comparable to that
required of BAVOs in the existing regulations.
E. Legal Comments
General Comments on Legal Aspects of the Rulemaking Process
    Summary of comments: BSEE received a number of comments regarding
the rulemaking process. Some commenters raised specific concerns about
the process. For example, a commenter asserted that BSEE engaged in an
inadequate information-gathering process. Several others claimed the
public comment period was too short, and did not involve enough
participation from stakeholders. Other commenters expressed support for
the rulemaking process, asserting that this rule would address
perceived deficits in the previous rule.
     Response: BSEE disagrees with the assertion that the
bureau provided an unreasonably short public comment and that BSEE
engaged in an inadequate information gathering process. As previously
discussed, BSEE held a public forum on September 20, 2017, in Houston,
Texas, prior to initiating the rulemaking process, to solicit input on
the development of the proposed rule. In addition, BSEE accepted
comments through a ``Request for comments'' on the Department of the
Interior's regulatory reform initiatives, published in the Federal
Register on June 22, 2017 (82 FR 28429), with no deadline for comments.
BSEE received 19 comments relevant to this rulemaking from interested
parties as a result of this request for comments. BSEE published the
proposed rule with a 60-day comment period that was scheduled to close
on July 10, 2018, and extended that comment period by 27 days to August
6, 2018. BSEE determined that this 87 day comment period on the
proposed rule was reasonably sufficient because it afforded interested
parties a meaningful opportunity to participate in the rulemaking
process.
[[Page 21920]]
Compliance With the Administrative Procedure Act (APA)
    Summary of comments: A commenter asserted that if BSEE chooses to
publish a final rule, then it must first provide analysis and data upon
which the proposed rule is based, in compliance with the fair notice
requirements of the Administrative Procedure Act (APA), asserting that
the APA requires BSEE to provide specific revisions with data and
analysis supporting those proposals and to request further public
comments on those specific proposed revisions, rather than simply ask
for comments on a broad range of topics. The commenter asserted that
there are several places in the proposed rule where BSEE solicits
comments for amending certain existing provisions but provides no
specific plans for how it intends to amend those provisions and
asserted that without a defined course of action, the public cannot
intelligently critique the proposed rule. The commenter asserted that
BSEE did not include the analysis or data on which other proposed
revisions are based, thus precluding meaningful public criticism.
     Response: BSEE disagrees. The APA's notice and comment
provision (5 U.S.C. 553(b)) requires that an agency test its regulation
through exposure to diverse public comment and give affected parties an
opportunity to develop evidence in the record to support their
positions regarding the rulemaking, thereby enhancing the quality of
agency decisionmaking.\14\ As evidenced by BSEE's receipt of diverse,
extensive public comments, the proposed rule fairly apprised interested
parties about the rule's detailed subjects and the range of
alternatives the bureau was considering. BSEE's evaluation of the
comments it received permitted the bureau to test these final
regulatory provisions. Through this rulemaking process, BSEE provided
ample and adequate notice of the potential for each regulatory change
implemented through this final rule and ensured that the rulemaking
record included adequate justification for each such change.
---------------------------------------------------------------------------
    \14\ Prometheus Radio Project v. F.C.C., 652 F.3d 431, 449 (3d
Cir. 2011), certiorari denied 567 U.S. 951 (2012).
---------------------------------------------------------------------------
    With regard to revisions to the BOP system testing requirements,
BSEE solicited comments in the proposed rule ``on whether the BOP
testing interval should be 7 days, 14 days, or 21 days for all types of
operations including drilling, completions, workovers, and
decommissioning,'' as well as comments ``on the specific cost and
operational implications of each testing interval.'' \15\ Contrary to
the commenter's assertion, BSEE specifically discussed industry's and
BSEE's current reliance on function and hydrostatic tests and
industry's concerns ``related to the benefits of pressure and
functional testing of subsea BOPs when compared to the costs and
potential operational issues.'' \16\ BSEE requested comments on these
specific tests and intervals, including ``[u]nder what circumstances or
environments . . . the testing frequency [should] be increased or
decreased,'' and what ``technologies, processes, or procedures can be
used to supplement existing requirements and provide additional
assurances related to the performance of this equipment.'' BSEE did not
propose the regulatory text adopted in the final rule regarding BOP
testing frequency. However, BSEE discussed all of the final rule
elements in the proposed rule, and a reasonable commenter could have
anticipated the adopted changes and the text of the final rule BOP
testing frequency provisions was a logical outgrowth of the proposed
rule. BSEE specifically requested comments on whether the BOP testing
interval should be 21 days for all types of operations, including
associated costs and operational considerations, and highlighted
questions surrounding the benefits of current testing requirements
compared to known concerns. 83 FR 22143. BSEE specifically requested
comments on circumstances in which testing frequency might be decreased
and alternative approaches to ensuring the operability and reliability
of BOP systems. Id. BSEE derived the final regulatory changes from
comments received pursuant to the solicitations in the proposed rule.
The final rule's BOP testing interval constitutes a logical outgrowth
from the proposed rule because interested parties should have
anticipated that this change was possible and, in fact, filed relevant
comments.\17\
---------------------------------------------------------------------------
    \15\ 83 FR 22143 (May 11, 2018).
    \16\ Ibid.
    \17\ ``A rule is deemed a logical outgrowth if interested
parties `should have anticipated' that the change was possible, and
thus reasonably should have filed their comments on the subject
during the notice-and-comment period.'' NE Maryland Waste Disposal
Auth. v. E.P.A., 358 F.3d 936, 952 (D.C. Cir. 2004) (internal cites
omitted). See also, CSX Transp., Inc. v. Surface Transp. Bd., 584
F.3d 1076, 1081 (D.C. Cir. 2009) (``[A] final rule represents a
logical outgrowth where the NPRM expressly asked for comments on a
particular issue or otherwise made clear that the agency was
contemplating a particular change.'').
---------------------------------------------------------------------------
Enforcement of Compliance With Documents Incorporated by Reference
    Summary of comments: A number of commenters asserted that, by
relying on incorporation by reference of industry standards, the
proposed rule would allow the oil and gas industry to regulate itself
without government oversight.
     Response: BSEE disagrees. As discussed elsewhere in this
final rule, BSEE incorporates technical standards by reference in
accordance with the requirements of the National Technology Transfer
and Advancement Act (NTTAA) \18\ and implementing Office of Management
and Budget (OMB) guidance, the Office of the Federal Register (OFR)
regulations (1 CFR part 51), and BSEE's own procedures for
incorporation (Sec.  250.115, What are the procedures for, and effects
of, incorporation of documents by reference in this part?). These
processes include thorough evaluation of the pertinent standards for
appropriateness and adequacy as regulatory requirements. The effect of
incorporation by reference of an industry standard into the regulations
is that the incorporated document becomes a regulatory requirement, see
Sec.  250.115(c), and, thus, becomes subject to BSEE oversight and
enforcement in the same manner as other regulatory requirements. BSEE
incorporates standards developed by SDOs with a preference for those
standards that are developed using a consensus process. Furthermore,
BSEE may incorporate portions of SDO standards, limit their
applicability to specified sections of BSEE's regulations, and impose
other limitations such as providing that where a provision of an
incorporated standard conflicts with BSEE regulatory provisions, those
regulatory provisions prevail. If an SDO later revises a standard that
BSEE has previously incorporated in a final rule, BSEE would need to
evaluate the revised standard before incorporating it through
rulemaking in the regulations; in other words, industry itself cannot
change the regulatory requirements by revising a standard after that
standard is incorporated in BSEE's regulations. Nor is industry
authorized to oversee or enforce compliance with standards once
incorporated into regulation. Once incorporated, BSEE enforces these
standards as any other regulatory requirement.
---------------------------------------------------------------------------
    \18\ National Technology Transfer and Advancement Act, 15 U.S.C.
370 et seq.
---------------------------------------------------------------------------
Correcting Issues From the 2016 Rulemaking Process
    Summary of comments: A commenter asserted that this proposed rule
corrected a failure in the 2016 WCR to provide a Statement of Energy
Effects, as required by E.O. 13211. According to
[[Page 21921]]
the commenter, E.O. 13211 required BSEE to publish for public comment a
detailed statement relating to (1) ``any adverse effects on energy
supply'' and (2) ``reasonable alternatives to the action.'' A commenter
claimed that the proposed rule makes adjustments to the 2016 rule to
provide ``economically feasible'' regulations as required by OCSLA.\19\
A commenter asserted that a detailed evaluation of ``reasonable
alternatives'' to the 2016 WCR ``would necessarily have included use of
consensus standards.'' According to this same commenter, BSEE's recent
cost impact assessment of the 2016 WCR found needless waste under
certain provisions of the rule, leading to ``idled rigs, unnecessary
new equipment, unnecessary reporting, non-productive time, and lost
production opportunities, all of which have no offsetting benefit to
safety or environmental protection.'' This commenter contended that the
proposed rule included adjustments to the 2016 WCR that provide
economically feasible avenues for reaching the safety and environmental
goals required by OCSLA. One commenter asserted that E.O. 13211 is
unconstitutional, so any reliance on it is unlawful.
---------------------------------------------------------------------------
    \19\ The commenter cited 43 U.S.C. 1347(b) as the basis for its
assertion. BSEE-2018-0002-0050 Attch. 1 (p. 3).
---------------------------------------------------------------------------
     Response: BSEE's articulation of its 2016 position with
respect to the applicability of E.O. 13211 to the 2016 WCR constitutes
the best evidence of the bureau's position.\20\ The OCSLA provision
cited by the commenter addresses economic feasibility with respect to
the use of certain technologies during OCS operations, not with respect
to the economic feasibility of regulatory updates.\21\ This rulemaking
does not make a determination regarding the economic feasibility of any
technology under 43 U.S.C. 1347(b). As explained in more detail in
section I of this final rule preamble, E.O.s 12866 and 13563 direct
BSEE 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). As a
general matter, BSEE informs its decision-making with respect to
rulemaking through fulfillment of the requirements of the APA and
associated regulations and guidance.
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    \20\ 81 FR 25888, 26013 (April 29, 2016).
    \21\ 43 U.S.C. 1347(b) states, in part: ``[The Secretary] shall
require, on all new drilling and production operations and, wherever
practicable, on existing operations, the use of the best available
and safest technologies which the Secretary determines to be
economically feasible . . . .''
---------------------------------------------------------------------------
Comments on Other Legal Issues
    Summary of comments: A commenter asserts that the agency cannot
adopt new revisions in the final rule based on solicited comments when
the agency did not propose those revisions in the proposed rule nor
provide an opportunity for public comment on those revisions.
     Response: BSEE disagrees. BSEE decision-making regarding
regulatory revisions is governed by the requirements of the APA and
associated regulations and guidance. BSEE has complied with the notice
and comment requirements of applicable law with respect to all
provisions of the final rule. Any provisions not specifically proposed
in the proposed rule reflect existing requirements and/or are logical
outgrowths from the proposed rule.
    Summary of comments: A commenter asserted that BSEE must perform a
Quantitative Risk Analysis (QRA) before BSEE can realistically conclude
that the changes ensure safe operations. In addition, the commenter
asserted that BSEE must evaluate the significant environmental impacts
of the rulemaking by preparing an Environmental Impact Statement (EIS).
The commenter based this assertion on the requirement under the
National Environmental Policy Act (NEPA) to take a ``hard look'' at the
cumulative impacts the rulemaking would have on water resources,
wildlife, coastal habitats, marine species, air quality, and
sociocultural and economic systems, including direct and indirect
impacts. The commenter also asserted that the rulemaking requires BSEE
to undertake Endangered Species Act (ESA) consultations because
removing certain regulatory provisions regarding environmental and
worker protections may affect listed species and critical habitat.
     Response: BSEE disagrees with the claim that a QRA is the
only way for BSEE to conclude that these changes ensure safe
operations. As more fully discussed in the final Environmental
Assessment (EA), NEPA requires that BSEE take a ``hard look'' at the
potential impacts of a rulemaking, however it does not specifically
require a QRA. BSEE took its ``hard look'' through the final EA, and
reached a Finding of No Significant Impact (FONSI), demonstrating that
an EIS is not required. Further, before any actual operations can be
conducted on the OCS, there are a number of additional stages (e.g.,
leasing program, lease sales, planning, permitting) at which additional
analyses of potential impacts are and will be performed. In addition,
guidance in OMB Circular A4 regarding the preparation of a regulatory
impact analysis (RIA) for significant rulemakings states that agencies
``should seek to use more rigorous approaches with higher consequence
rules.'' BSEE evaluated the recommendations from the stakeholders and
commenters, considering a number of factors including risk, benefits,
and cost. As previously discussed, consistent with congressional
encouragement, BSEE solicited input from stakeholders early in this
rulemaking process to identify those provisions of the existing
regulations that BSEE could amend, revise, or remove to reduce
unnecessary burdens on stakeholders while still maintaining safety and
environmental protection. BSEE generally focused on those provisions in
the existing regulations that did not significantly enhance worker
safety or environmental protection.
    With respect to ESA consultation, BSEE considered the ongoing
Section 7 ESA consultations with the U.S. Fish and Wildlife Service,
and whether this rule would affect any listed species or habitat. The
National Marine Fisheries Service expressly excluded this rule making
from the ongoing programmatic consultation. The final rule would not
give rise to any additional or modified activities that would affect
listed species or designated critical habitat. BSEE has determined that
the final rule will have ``no effect'' on listed species or designated
critical habitat. BSEE has determined that ESA consultation is
therefore not required for this rule.
Comments on Best Available and Safest Technology (BAST) Requirement in
OCSLA
    Summary of comments: A commenter emphasized that OCSLA requires
BSEE to ensure that operators use ``the best available and safest''
technology (BAST) possible, unless BSEE determines that the narrow
impracticability exception applies. The commenter asserted that BSEE
failed to ensure or otherwise determine that the proposed rule meets
these requirements. This commenter asserted that before BSEE may
rescind and revise technological requirements that were determined to
meet the requirements of BAST, BSEE is obligated to demonstrate
compliance with BAST by ensuring that those revisions are as good as
the original requirements. The commenter maintained that BSEE may not
adopt the proposed revisions without a determination that the benefits
of the
[[Page 21922]]
original provisions are clearly insufficient to justify the incremental
costs of implementing these technologies. This commenter asserted that
BSEE must provide information demonstrating that the rulemaking will
meet the BAST requirements of OCSLA.
    A commenter urged BSEE to expeditiously finalize its consideration
of the potential revisions to Sec.  250.107.
     Response: The Conference Report regarding OCSLA's BAST
provision \22\ explains that that this provision requires the Secretary
to make a ``determination as to what are the best available and safest
technologies economically feasible . . . .'' \23\ Neither the 2016 WCR
nor this rule made or makes any such determination with respect to any
specific technology. Therefore, in this rule, the Secretary has not
undertaken any BAST evaluation of economic feasibility of any specific
technology, nor did the Secretary do so in the context of the 2016 WCR
(see, e.g., 81 FR 25901; 25911; and 25929). Thus, the BAST statutory
requirement does not apply here because this rulemaking makes no BAST
determinations, nor does it alter any existing BAST determinations. The
BAST statutory requirement is independent from OCSLA's provisions
establishing the Secretary's authority to promulgate regulations to
govern OCS operations.\24\
---------------------------------------------------------------------------
    \22\ 43 U.S.C. 1347(b).
    \23\ Conf. Rpt. 95-1091 (Aug. 10, 1978) (p. 109).
    \24\ 43 U.S.C. 1334(a) states, in part: ``The Secretary shall .
. . prescribe . . . regulations as may be necessary to carry out
[OCSLA]. The Secretary may at any time prescribe and amend such . .
. regulations as may be necessary and proper in order to provide for
the prevention of waste and conservation of the natural resources of
the [OCS], and the protection of correlative rights therein . . .
.''
---------------------------------------------------------------------------
Comments on Grounds for Decisions
    Summary of comments: A commenter asserted that BSEE failed to meet
the APA's legal standards and argued that BSEE must provide ``the
grounds of its decision and the essential facts upon which the
administrative decision was based,'' and ``good reasons'' for the
proposed changes in policy, explaining the reasons why BSEE disregarded
the ``facts and circumstances that underlay or were engendered by'' the
prior rule. The commenter asserted that BSEE needs to provide a more
detailed justification, providing ``reasoned explanation.'' The
commenter also asserted that it is arbitrary and capricious for BSEE to
assume that the proposal to repeal regulations, that two years ago BSEE
found would provide significant societal benefits, will not have an
effect on societal costs and benefits.
     Response: BSEE disagrees. The APA's provisions regarding
notice and comment (5 U.S.C. 553(b) and (c)) require that an agency
test its regulation through exposure to diverse public comment and give
affected parties an opportunity to develop evidence in the record to
support their positions regarding the rulemaking, thereby enhancing the
quality of agency decisionmaking.\25\ BSEE provided thorough and
reasoned explanations for its proposed regulatory actions and submitted
them to public comment. BSEE's evaluation of the comments it received
permitted the bureau to test these final regulatory provisions. Through
this rulemaking process, BSEE provided ample and adequate notice of
each regulatory change implemented through this final rule and ensured
that the rulemaking record included adequate justification for each
such change. Further, BSEE undertook its review of the provisions of
existing regulations as promulgated through the 2016 WCR pursuant to
the direction of multiple Executive Orders and Secretary's Orders, as
well as congressional direction. Thus, BSEE faithfully implements OCSLA
and fully complied with procedural legal requirements, including those
applicable to this rulemaking.
---------------------------------------------------------------------------
    \25\ Prometheus Radio Project v. F.C.C., 652 F.3d 431, 449 (3d
Cir. 2011), certiorari denied 567 U.S. 951 (2012).
---------------------------------------------------------------------------
Comments on Weakening of Requirements
    Summary of comments: One commenter strongly opposed the proposed
rule, asserting that the proposal to weaken the existing well control
regulations, just two years after they were promulgated, and before
some provisions of the regulations are effective, would increase the
likelihood of another Deepwater Horizon disaster. The commenter
observed that the previous rulemaking was specifically designed to
prevent another scenario similar to the Deepwater Horizon event. The
commenter stressed that this action would ``epitomize an arbitrary and
capricious reversal of position.''
     Response: The APA requires that BSEE give a ``general
statement of [the regulations'] basis and purpose.'' (5 U.S.C. 553(c)).
As previously described, BSEE broadly based this rulemaking on
congressional guidance, interaction with stakeholders, BSEE's
experience implementing the 2016 WCR, BSEE's recognition of
technological advancements, and directions contained in Executive and
Secretary's Orders issued subsequent to the 2016 WCR. Pursuant to those
Orders, BSEE evaluated existing regulatory provisions to identify
unnecessary regulatory burdens, but always within the bounds of
maintaining safety and environmental protection. BSEE believes that its
process accomplished these goals without ``weaken[ing]'' existing
regulation or failing to maintain safety and environmental protection.
BSEE's articulation of these sound reasons for its regulatory decisions
demonstrates that it is not acting arbitrarily or capriciously.\26\
BSEE disagrees with the commenter's assertion that this rule would
increase the likelihood of an event similar to DWH. As discussed in
section I.D of this preamble, this rulemaking reduces regulatory burden
while maintaining safety and environmental protection.
---------------------------------------------------------------------------
    \26\ See, Natl. Indus. Sand Ass'n v. Marshall, 601 F.2d 689, 717
(3d Cir. 1979).
---------------------------------------------------------------------------
F. Economic Comments
Comments on Cost and Benefits
    Summary of comments: Some commenters made assertions regarding the
cost/benefit aspects of the proposed rule as presented in the initial
regulatory impact analysis (IRIA). These comments were varied in scope
and in position. Some commenters supported the overall conclusion of
the IRIA, that BSEE is alleviating unnecessary regulatory burdens on
industry with no foregone benefit to the public. Many commenters
challenged this conclusion, both for the rule as a whole and with
respect to some of the individual provisions. Commenters often
supported their claims with descriptions in the 2016 WCR or by
highlighting statements from the multiple investigative and engineering
studies following the Deepwater Horizon incident in 2010.
    Most comments did not challenge the IRIA's methodology or the
compliance cost or savings estimates. Commenters that noted these did
so generally, usually in the context of added risks or foregone
benefits to the public. In other words, commenters mostly accepted the
compliance savings estimates in the IRIA, but asserted that it was
incomplete and that BSEE essentially ignored the ``benefit'' part of a
cost-benefit analysis. On this basis, one commenter challenged BSEE's
``neutral'' designation for safety and environment impacts, claiming it
treats foregone benefits as having zero value. The commenter further
asserted, ``BSEE must analyze and monetize the forgone societal
benefits from [the proposed rule] that it analyzed and monetized in
[[Page 21923]]
2016, including the risk reduction benefits.'' In the absence of such
an analysis, a separate commenter asserts that, ``BSEE provides no
evidence that the existing rule is actually a burden or that removing
safeguards will ensure adequate protections remain in place.'' Further
comments suggest the savings estimates presented in the IRIA are
insignificant in comparison to the billions in gross domestic product
(GDP) generated by the coastal communities placed at greater risk if
this rule is finalized--a risk, commenters note, BSEE did not evaluate.
Variations of these claims are found in multiple comments.
     Response: The 2016 WCR did not make specific claims
regarding the reduced risk created by the provisions in that
rulemaking. A breakeven analysis of the rule's total compliance costs
claimed only that BSEE believed the risk reduction was greater than one
percent. This final rule does not modify or change the overwhelming
majority of the provisions codified in the previous rulemaking.
Further, BSEE identified the changes being made specifically because
they maintain safety and environmental protection, and the societal
benefits associated therewith. The revisions made through this
rulemaking exemplify that there are multiple approaches to maintaining
safety and environmental protection, and the associated societal
benefits. As discussed in the ``Section-by-Section Summary''
discussions in this preamble, this final rule leaves in place several
of the provisions proposed for revision in the proposed rule. The final
rule focuses only on those provisions that are expected to reduce
unnecessary burdens on operators, while still maintaining safety and
environmental protection. Accordingly, BSEE has adequately incorporated
those benefits into its formulation of this final rule.
Comments on Compliance Costs or Savings Estimates
    Summary of comments: BSEE received few comments on compliance cost
or savings estimations in the IRIA. One commenter resubmitted a cost
analysis prepared for the 2016 WCR to support the position that BSEE
should revise additional provisions not included in the proposed rule.
Similarly, a separate commenter highlighted an unspecified cost burden
related to the retention period of real-time monitoring data as defined
by a provision not proposed for revision in the proposed rule.
     Response: BSEE's rulemaking process revises only the
provisions identified in the proposed rule and changes that would be
considered a ``logical outgrowth'' of the proposed rule. These comments
suggested that BSEE should revise provisions that it did not propose
for modification in the Notice of Proposed Rulemaking (NPRM) and that
it did not analyze in the IRIA. BSEE considers the suggestions made in
these comments to be outside the scope of this rulemaking.
Comments on the Elimination of BAVO Requirements
    Summary of comments: Regarding elimination of the BAVO framework, a
commenter asserted that, based on the supporting RIA for the 2016 WCR,
``BSEE estimated that the BAVO system would result in a mere $10,000 in
annual costs to operators and verification organizations. BSEE has
provided no evidence that such a small annual cost outweighs the
critical benefits of the BAVO system.''
     Response: As discussed previously, BSEE concluded that the
use of independent third parties will provide the same level of safety
as the BAVO framework. Implementation of the BAVO framework would also
impose meaningful costs and burdens on BSEE. BSEE considers any
compliance cost that does not contribute to safety or environmental
protection burdensome and therefore believes it is appropriate that the
regulatory impact analysis reflect a compliance savings and no foregone
public benefit.
Comments on Lack of a Risk Analysis or Risk Assessment and Financial
Analysis
    Summary of comments: Several comments asserted that the proposed
rule lacks sufficient risk analysis and asserted that additional
analyses are required, while other commenters stated they were
satisfied with the proposed risk assessment.
    One commenter asserted that BSEE claimed the proposed rule would
not cause a major increase in costs or prices for: Consumers;
individual industries; Federal, State, Tribal, or local governments; or
regions of the nation. The commenter then asserted that these
conclusions do not consider the risk of another spill like Deepwater
Horizon or consider the impacts of that event related to the shutdown
of fishing and tourism businesses for months or longer. The same
commenter noted that according to BSEE, the proposed changes would
reduce regulatory costs over a 10-year period at a rate less than $1
billion total, which the commenter asserted is a relatively small
amount when compared to the damage of one oil spill.
    Another commenter made a similar assertion regarding BSEE's
position that the rule would not cause major increases in cost or
prices, and asserted that this position does not address important risk
factors. The commenter asserted that the proposed rule failed to
account for foregone benefits along with the avoided costs. The
commenter asserted that because the proposed revisions ``would have a
positive annual effect on the economy of $100 million or more,'' this
rulemaking is subject to the cost-benefit analysis requirements under
E.O.s 12866 and 13563, as well as OMB Circular A-4. The commenter
asserted that BSEE claimed it has conducted the required analysis, but
argued that while BSEE's analysis quantifies industry's anticipated
reduction in compliance costs, it does not address the foregone
benefits of protections against the types of spills that have cost
billions of dollars to remediate. The commenter further asserted that
BSEE simply stated that, ``[t]he proposed amendments would not
negatively impact worker safety or the environment.'' The commenter
observed that the economic analysis conducted for the 2016 WCR
``quantified and monetized the potential benefits of the rule,
including time savings, reductions in oil spills, and reductions in
fatalities.''
    One commenter asserted that the rulemaking is consistent with the
Executive and Secretary's Orders, in that the rulemaking would remove
undue burdens on operators. The commenter supported BSEE's assertion
that the proposed rule would increase the competitiveness of America's
offshore energy industry.
    Another commenter asserted that the proposed rule would hold risk
to an acceptable level and that the risk-based standards and procedures
as currently used by operators are sufficient to maintain well control.
The commenter asserted that operators can maintain well control and
manage events safely when: Wells are designed for the range of
anticipated risk; equipment and safeguards have the required redundancy
and are properly maintained and tested; personnel are trained; tests
and drills are conducted; and established procedures are followed. The
commenter emphasized the importance of highly skilled and trained
personnel on location who are able to provide timely and effective well
control and safety decision making. The commenter also recommended that
BSEE consider these general operating practices when finalizing this
and other regulations.
[[Page 21924]]
     Response: BSEE disagrees with the commenters' assertion
that BSEE did not consider risk in the development of the proposed and
final rule. BSEE evaluated operational considerations, equipment design
and specifications, and relevant public input and comments to identify
appropriate revisions. As previously discussed in this preamble, BSEE
carefully considered potential changes to these regulations, under
direction to identify possible revisions that would reduce unnecessary
regulatory burdens on stakeholders, while still maintaining safety and
environmental protection. As discussed qualitatively in the RIA, BSEE
determined that the selected revisions are likely to maintain the same
worker safety and environmental protection as the 2016 final rule,
therefore BSEE did not evaluate the costs related to a potential
increase in spills or safety issues. BSEE recognizes that pursuant to
OMB guidance (OMB circular A-4),\27\ agencies are encouraged to ``seek
to use more rigorous [economic analysis] approaches with higher
consequence rules,'' i.e., those rulemakings that are expected to have
annual benefits and/or costs in the range from $100 million to $1
billion. BSEE recognizes that there is a potential relationship between
a decrease in regulatory requirements and an increase in risks.
However, during the rulemaking process, BSEE considered the potential
impacts of contemplated revisions to safety and environmental risks to
identify those revisions that would reduce burdens on operators while
maintaining safety and environmental protection. While BSEE did not
develop a specific risk analysis for this rulemaking, BSEE considered
potential risks as part of the process of developing this rule and RIA.
BSEE has a number of completed and ongoing efforts related to
evaluating risk in OCS operations. BSEE considered information from
these efforts when evaluating the requirements of the current well
control regulations to identify requirements that could be revised
while still maintaining safety and protection of the environment. Among
the ongoing efforts considered by BSEE that address well control-
related risk issues, are:
---------------------------------------------------------------------------
    \27\ https://www.whitehouse.gov/sites/whitehouse.gov/files/omb/circulars/A4/a-4.pdf.
---------------------------------------------------------------------------
    (1) The SafeOCS failure reporting program, and the ``Blowout
Preventions System Events and Equipment Component Failures'' 2016
Annual Report and ``Blowout Preventions System Safety'' 2017 Annual
Report on failures, by BTS. These reports include summaries and
analysis of the data received through the SafeOCS program on BOP
equipment component failures on the OCS and other key information, such
as failure causes, operational impacts, and opportunities to improve
data quality. More information on the SafeOCS reporting system and
copies of the 2016 and 2017 BTS reports are available at: https://www.safeocs.gov/wcr_home.htm.
    (2) Argonne National Laboratory (ANL) 2017 report and updated 2018
report on Risk-Based Evaluation of Offshore Oil and Gas Operations
Using a Multiple Physical Barrier Approach. This project was designed
to assist BSEE in developing a multiple physical barrier (MPB) model of
risk analysis. The project resulted in a risk-analysis technique,
developed by ANL, that focuses on the use of physical barriers to
prevent hydrocarbon release. BSEE has used a multiple barrier approach
as part of its approach to regulations for many years. This project
supports that approach through the development of a formalized
methodology for evaluating process safety, to ensure that success paths
(e.g., systems, components, and human actions needed to ensure the
success (of a barrier)) are in place and are capable of performing
their functions in all expected conditions and circumstances. The
initial (2016) ANL project resulted in a joint industry project (JIP),
a case study on plug and abandonment barriers. More information on this
project and the two ANL reports is available at: https://www.bsee.gov/research-record/risk-based-evaluation-of-offshore-oil-and-gas-operations-using-a-multiple-physical.
    Regarding the comments on BSEE's determination that the proposed
rule would not cause a major increase in costs or prices, the revisions
to the regulatory requirements in this final rule are expected to
reduce unnecessary burdens, while still maintaining safety and
environmental protection. The 2016 WCR did not make specific claims
regarding the risk reduction created by the provisions in that
rulemaking. A breakeven analysis of the rule's compliance costs claimed
only that BSEE had concluded that the risk reduction was greater than
one percent (81 FR 25987). This final rule does not modify or change
the overwhelming majority of the provisions codified in the 2016 WCR.
BSEE determined that the selected revisions are likely to maintain
safety and environmental protection.
    This final rule does not codify some provisions of the proposed
rule. One example is the proposed revision to existing Sec.
250.734(a)(1)(ii), which requires ``both shear rams to be capable of
shearing'' the specified equipment run in the hole. BSEE proposed to
change this provision to require only that a ``combination of the shear
rams must be capable of shearing'' the specified equipment run in the
hole. As previously stated, BSEE based the decision not to make that
change in this final rule on consideration of the public comments on
the proposed rule, the importance of shearing redundancy, and the
potential ambiguity the change would create regarding the number of
rams subject to this shearing requirement. For more information on
specific proposed provisions that are not being codified in this final
rule, refer to section V of this preamble.
    Concerning the comment that recommended that BSEE consider these
general operating practices when finalizing these and other
regulations; BSEE agrees and does this routinely as part of developing
regulations and policies. The incorporation by reference of industry
developed standards in the regulations is one approach BSEE uses to
address general operating practices used by the industry. Since these
documents are developed by industry, they reflect common industry
practices. BSEE also considered input from industry to identify those
provisions from the existing regulations that were unduly burdensome,
although this was not the only input that BSEE considered in
determining how to revise these regulations.
Comments on Potential Safety Impacts of Proposed RTM Rrevisions
    Summary of comments: One commenter asserted that BSEE must
ascertain whether removing certain provisions, such as RTM
requirements, would increase the risk of human error, or remove a check
on human error, regarding the need for an operator's offshore and
onshore teams to come to consensus on how to proceed. The commenter
also asserted that BSEE must provide quantitative risk analyses to
support the proposed rule provisions, stating that such an analysis is
critical to understanding whether BSEE's proposal to rescind such
built-in safety checks would impermissibly undermine safety. The
commenter also cited System Risk Assessment and Management (SRAM) as an
approach that works effectively in other countries.
     Response: The final rule revises part of the existing RTM
requirements, but does not entirely remove them. Section 250.724
paragraph (a) of the final rule continues to require RTM when operators
conduct ``well operations with a subsea BOP or with a
[[Page 21925]]
surface BOP on a floating facility, or when operating in a high
pressure high temperature (HPHT) environment.'' The operator must
``gather and monitor real-time well data using an independent,
automatic, and continuous monitoring system capable of recording,
storing, and transmitting data.'' This includes data regarding the BOP
control system, the well's active fluid circulating system, and the
downhole conditions with bottom hole assembly tools.
    The final rule continues to require operators to transmit such data
as they are gathered in accordance with a real-time monitoring plan.
The final rule requires that operators have the capability to monitor
the data using qualified personnel. In addition, BSEE requires the
operator to develop and maintain a real-time monitoring plan that meets
certain specified criteria.
    The final rule removes the language in existing Sec.  250.724(b)
discussing contact between onshore and offshore personnel and stating
that, after completing operations, the operator must preserve and store
these data for recordkeeping purposes as required in Sec. Sec.  250.740
and 250.741, and must provide BSEE with access to the designated real-
time monitoring data onshore upon request. The final rule also removes
the requirement from Sec.  250.724 that the operators include
certifications that they have a real-time monitoring plan in their APD.
These provisions are prescriptive, but unnecessary. The regulations
still require the operator's RTM plan to describe how the data will be
transmitted and monitored by qualified personnel, procedures for, and
methods of, communication between rig personnel and monitoring
personnel, and actions to be taken in the event of loss of
communications. Further, the existing regulations (Sec. Sec.  250.740
and 250.741) already specify recordkeeping requirements for all of
Subpart G. BSEE also has the authority to request these records from
the operators. Removal of these redundant or unnecessary requirements
for storage of RTM data from Sec.  250.724 do not remove the obligation
for the operator to develop and implement an RTM plan, which includes a
description of how the data will be stored; therefore, the change in
risk is minimal and a quantitative risk analysis, as suggested by the
commenter is not needed.
    Regarding the commenter's mention of the SRAM, BSEE recognizes that
there are numerous ways to approach risk assessments and may consider
other approaches for future policies or regulations.
Comments on Financial Assurance
    Summary of comments: A commenter asserted that operators should
provide evidence of financial ability to plug wells and cover lost
income, including the loss of income to those who rely on [acy] clean
ocean for their livelihoods.
     Response: BSEE assumes that this comment is related to
financial assurance (bonding) issues. BSEE does not regulate financial
assurance for the offshore oil and gas industry; the Bureau of Ocean
Energy Management's (BOEM's) regulations at 30 CFR parts 553, Oil Spill
Financial Responsibility for Offshore Facilities and 556, Leasing of
Sulfur or Oil and Gas and Bonding Requirements in the Outer Continental
Shelf address that responsibility.
G. Environmental Comments
Comments on the OCS Leasing Program
    Summary of comments: A number of commenters addressed elements of
the BOEM draft proposed 2019-2024 National OCS Leasing Program (Leasing
Program). These commenters focused on the potential impacts of the
proposed regulations in conjunction with the potential for oil and gas
exploration and development in areas that could be opened for leasing
under BOEM's proposed Leasing Program. One commenter asserted that
BOEM's proposed expansion of leasing would entail the issuance of
leases at a pace that exceeds the pace of recent leasing activities.
The commenter further asserted that this would lead to an increase in
the risk of spills, blowouts, and other consequences, and that the
leases would be issued in areas where there is currently no oil and gas
production and little or no production of oil and natural gas has taken
place. The commenter asserted that the proposed rule would weaken the
precautions in place to prevent these consequences just as offshore
drilling would begin in areas that are not prepared to respond to
spills.
    Some comments asserted that the proposal in the Leasing Program to
expand OCS leasing into additional geographic areas would magnify any
reduction in safety and environmental protection resulting from the
proposed revisions in this rulemaking. Some commenters asserted that
BSEE must consider the impacts that the proposed rule would have under
the expanded Leasing Program proposed by BOEM.
     Response: BSEE is aware of BOEM's Leasing Program. The
proposed Leasing Program is a separate action by BOEM, which is a
separate bureau from BSEE within the Department. The Leasing Program
specifies the size, timing, and location of potential leasing activity
that the Secretary determines will best meet national energy needs for
the five-year period under consideration. The Leasing Program is
subject to its own separate public comment processes and is beyond the
scope of this rulemaking. While certain regulations apply exclusively
to certain regions, the bulk of BSEE's regulations apply to the entire
OCS regardless of location. As analyzed throughout, BSEE disagrees with
the commenters' assertion that this rulemaking weakens the precautions
to prevent spills and incidents. Accordingly, the impacts of this rule
are not pertinent to commenters' concerns, and any concerns related to
the expansion of operations into new areas should be directed toward
BOEM's proposed Leasing Program, as that is not a subject of this
rulemaking. Regardless of the BOEM leasing pace, BSEE permits
operations on an individual well-by-well basis taking into account
site-specific environmental and operational conditions to help ensure
safety and environmental protection.
    BSEE disagrees that the regulations are being weakened and it
selected the revisions implemented through this rule based in part on
the fact that they are likely to maintain the same level of safety and
environmental protection for OCS activities as established by the 2016
final regulations. This rulemaking does not revise or reduce the oil
spill response plan requirements.
General Comments on Environmental Impacts
    Summary of comments: Multiple commenters were concerned that the
proposed rule would increase environmental impacts of drilling and
other well operations, thus negatively affecting the environment. One
commenter asserted that the penalties imposed for failures are
insufficient to motivate operators to comply with the regulations. The
commenter asserted that the 2016 WCR was overly conservative in its
estimations of its environmental benefits. The commenter also asserted
that BSEE admitted that it understated the environmental benefits when
BSEE assumed that the rule would reduce oil spill risk by only one
percent per year. The commenter asserted that this mistake is further
compounded by the fact that BSEE relies on this erroneous one percent
reduction of risk assessment in its costs reduction analysis for the
proposed revisions to the regulations promulgated through the 2016 WCR.
The commenter also asserted that a significant monetary imbalance
exists between current civil penalties and operating costs; asserting
[[Page 21926]]
that the penalties are too small to deter risk-taking and provide a
financial incentive to disregard regulatory compliance. The commenter,
however, acknowledged that BSEE cannot address this problem through
regulations, and that Congress needs to mandate penalties that will
discourage this behavior.
    A different commenter expressed concern regarding how the proposed
rule would negatively affect the environment. The commenter expressed
opposition to any provisions of the proposed rule that would weaken
requirements for decommissioning, such as possibly excluding
decommissioning from RTM requirements. The commenter referenced a 2010
article by the Associated Press asserting that there are more than
27,000 sealed and abandoned oil and gas wells in the Gulf of Mexico,
with more than 3,200 wells classified as active that have no cement
plugging. The commenters asserted that these 3,200 wells pose a
significant risk to the health of the Gulf and coastal communities
because the factors that could lead to leaks are not being monitored.
The commenter noted that in recent years, millions of dollars from
Deepwater Horizon recovery and restoration funds were provided to state
programs to safely plug abandoned wells. The commenter asserted that
BSEE should strengthen requirements for decommissioning activities to
prevent the risk of future leaks.
     Response: BSEE disagrees with the commenters' assertions
that the selected regulatory revisions would negatively affect the
environment. BSEE has determined that this rulemaking does not alter
the baseline (2016 level) risk profile of the 2016 WCR, for the reasons
specified in the rule and RIA. There are no benefits (forgone or
otherwise) to quantify because the baseline risk profile is unchanged.
Therefore, those forgone benefits are ultimately quantified at zero. In
the EA, BSEE evaluated the revisions in this rulemaking to focus the
impact analyses on those revisions that could potentially change
operators' responsibilities for how they conduct their operations. The
impact analysis focuses on the likely impacts associated with a
possible loss of well control, discharges of hydrocarbons to the
environment, and air pollution emissions associated with testing
activities. BSEE evaluated the impacts of the final rule provisions and
determined that none of the provisions will significantly impact the
quality of the human environment under NEPA (refer to the final EA and
FONSI).
    BSEE generally agrees with the commenters' assertions about the
importance of civil penalties. However, those considerations are beyond
the scope of this rulemaking. BSEE also agrees that the sufficiency of
the maximum civil penalties allowable under OCSLA is a question that
would need to be addressed by Congress. BSEE also generally agrees with
the commenters' assertions about the importance of decommissioning.
However, this aspect of decommissioning operations is also beyond the
scope of this rulemaking.
Comments on the Need for an EIS
    Summary of comments: Multiple commenters recommended that BSEE
should prepare an EIS. These commenters asserted that the environmental
impacts discussed in the draft EA are significant in scope and
intensity and that the impacts of a catastrophic discharge would be
severe. The commenters also asserted that the proposed rule would
increase the risk of significant impacts; therefore, BSEE should
prepare an EIS for this rulemaking. Another commenter asserted that the
standard for triggering an EIS is low and that an EIS should be
prepared when substantial questions are raised about whether a project
may have a significant impact on the environment. A commenter also
asserted that agencies must identify their methodologies, indicate when
information is incomplete or unavailable, acknowledge scientific
disagreement and data gaps, and evaluate indeterminate adverse impacts
based on approaches or methods ``generally accepted in the scientific
community.'' Some commenters asserted that BSEE's utilization of an
environmental assessment is unsupportable because of the potential
effects from a possible catastrophic oil spill, like the Deepwater
Horizon incident, and BOEM's plans to dramatically expand the scope of
offshore drilling through the National OCS Program under development.
     Response: BSEE disagrees that the potential impacts of the
rule are significant. BSEE used the best available scientific
information to conduct a comprehensive review of the potential
environmental impacts of the provisions of the proposed rule. More
specifically, BSEE reviewed and incorporated the impact analyses from
multiple existing environmental documents into the draft EA and
determined that there were no significant environmental impacts
associated with any of the NEPA alternatives considered, and, most
importantly, with the provisions in this final rule. Furthermore, BSEE
disagrees that the proposed rule would increase the risk of significant
impacts. As previously mentioned, BSEE considered potential risks while
developing the final rule. In particular, we concluded that the risk of
a catastrophic oil spill is not increased by the regulatory revisions
of this rule. These considerations included the public's input on the
proposed rule and information from a number of BSEE efforts related to
evaluating risk in OCS operations--such as BSEE's SafeOCS failure
reporting program and the ANL report on Risk-Based Evaluation of
Offshore Oil and Gas Operations Using a Multiple Physical Barrier
Approach. These various sources of information led BSEE to identify
changes to the regulations implemented through the 2016 WCR that would
reduce regulatory burden while maintaining safety and environmental
protection on the OCS. For example, the final rule does not include
certain changes initially mentioned in the proposed rule that would
have eliminated the requirement for both shear rams in a BOP to be
capable of shearing specific equipment run in the hole and eliminated
requirements related to pipe positioning for shear rams. Inasmuch as
the impacts of the rule are either neutral or positive, the potential
for expansion of the geographic area subject to leasing does not
increase the risks to a level approaching significance. General
statements of dissatisfaction with the draft EA's analyses or general
statements regarding NEPA legal standards, do not assist BSEE in
providing any supplemental analysis that could assist the public in
understanding the potential environmental impacts of the final rule.
Comments on the Adequacy of Impacts Analysis
    Summary of comments: A number of comments asserted that BSEE's
analyses of impacts on environmental resources are inadequate. One
comment asserted that BSEE's one-sided evaluation of economic impacts
violates NEPA and that the analysis fails to address the ``crippling
economic consequences of failing to prevent an oil spill that could
have been prevented under the 2016 well control rule.'' Another comment
asserted that the draft EA fails to disclose and analyze impacts to
water resources, wildlife on nearby habitats, air quality,
sociocultural systems, commercial and recreational fisheries, tourism,
and recreation, as well as cumulative impacts. The commenter also
disapproved of BSEE's determination that consultation for threatened
and endangered species is
[[Page 21927]]
not necessary at this time. The commenter asserted that BSEE's
conclusions are not supported by any qualitative or quantitative
analysis and therefore fail to satisfy the hard look requirement of
NEPA.
     Response: BSEE stands by the conclusions provided in the
EA, while noting that BSEE used the best available scientific
information to conduct a comprehensive review of the potential
environmental impacts. This information includes multiple existing
environmental analysis documents, listed in the next paragraph, as well
as information received through public comment on the proposed rule and
a number of BSEE efforts (e.g., ANL studies) related to evaluating risk
in OCS operations. As previously mentioned, the changes to the
regulations promulgated through the 2016 WCR are limited only to those
that would reduce regulatory burden while maintaining safety and
environmental protection on the OCS. Those comments that express
general dissatisfaction with the analyses do not provide any
supplemental analysis that could assist the public in understanding the
potential environmental impacts of the rule.
    The project area evaluated in the EA is fully described in Chapter
3 of the EA, Affected Environment. The EA incorporates by reference
baseline information regarding resources that are relevant to the
operations conducted under the revised regulations from the Final
Programmatic Environmental Impact Statement; Outer Continental Shelf
Oil and Gas Leasing Program: 2017-2022; Final Environmental Impact
Statement; Gulf of Mexico OCS Oil and Gas Lease Sales: 2017-2022; Gulf
of Mexico Lease Sales 249, 250, 251, 252, 253, 254, 256, 257, 259, and
261; Final Programmatic Environmental Assessment of the Use of Well
Stimulation Treatments on the Pacific Outer Continental Shelf: May
2016; and the Final Environmental Assessment; Oil and Gas and Sulfur
Operations on the Outer Continental Shelf--Blowout Preventer Systems
and Well Control: April 2016. BSEE rigorously evaluated and discussed
in Chapter 4 of the EA, Environmental Consequences, the analyses of
impacts on water resources, wildlife on nearby habitats, air quality,
sociocultural systems, commercial and recreational fisheries, tourism,
and recreation, as well as cumulative impacts, while noting that many
of the quantitative and qualitative analyses are supported in the
documents incorporated by reference.
    In the EA, BSEE identified the scope of reasonably foreseeable
activities that may be attributed to this rulemaking in order to
estimate its environmental effects. BSEE acknowledges that there is
some level of risk associated with offshore oil and gas activities;
however the scope of this EA is limited to this rulemaking, which
adopted changes to the current regulations that reduce regulatory
burdens while maintaining safety and environmental protection.
    The cumulative impacts analysis considered the baseline data
included in Chapter 3, Affected Environment, which describes current
conditions and past and ongoing impacts on the resources that could
potentially be affected by the activities included under each
alternative, as well as reasonably foreseeable future activities that
should be taken into account. The EA appropriately describes and
analyzes all of the current and reasonably foreseeable future impacts
from other activities described in the Cumulative Effects section 4.5
of the EA based on the estimated negligible to small impacts attributed
to promulgating the final regulations in this rulemaking under
Alternative 4, and the small contribution to total cumulative impacts.
    BSEE considered the ongoing Section 7 ESA consultations with the
U.S. Fish and Wildlife Service and National Marine Fisheries Service,
and whether this rule would affect any listed species or habitat. The
final rule would not give rise to any additional or modified activities
that would affect listed species or designated critical habitat. BSEE
has determined that the final rule will have ``no effect'' on listed
species or designated critical habitat. BSEE has determined that ESA
consultation is therefore not required for this rule.
H. Miscellaneous Comments
Comments on General Safety Issues
    A number of comments discussed overall safety issues purportedly
implicated by the rulemaking, not related to a specific proposed
revision. Some commenters stated that they perceived that the proposed
rule would improve the overall safety of operations, while others
raised concerns that the proposed rule would decrease overall safety.
    Summary of comments: Multiple commenters expressed support for the
proposed rule's reliance on best management practices, innovation to
increase safety and reliability, optimization of risk reduction,
support for the nation's efforts to increase energy independence, and
incorporation of API Standard 53. One commenter asserted that adoption
of API Standard 53 would improve safety by aligning the regulations
with actual industry practices; by incorporating the standard it would
apply to operators, suppliers, and contractors; and that the standard
would provide for timely introduction and management of new technology.
    A commenter asserted that the economic production of crude oil and
natural gas in the Gulf of Mexico is vital to the U.S. economy and
American consumers. The commenter emphasized the importance of ensuring
that any regulations BSEE adopts optimize risk reduction without making
development and production uneconomic or unsafe.
    A commenter asserted that new technologies can provide industry
with operational information. The commenter asserted that the industry
and BSEE recognize that technologies already exist, or are in
development, that can provide operators with data regarding the
equipment's performance. The commenter asserted that use of these and
other emerging technologies, along with API Standard 53 failure
reporting, may lead to advances that further improve safety and
reliability.
     Response: BSEE agrees with the comments generally
supporting the selected revisions. BSEE has reviewed all comments
submitted and is revising the proposed rule as appropriate. BSEE
responds directly to comments on specific provisions and discusses the
final rule provisions in section V of this preamble.
    Summary of comments: Several commenters asserted that the proposed
rule failed to adequately demonstrate how it will protect safety.
Another commenter asserted that the proposed rule allows operators to
govern their own safety. The commenter asserted that the proposed
revisions would allow a substantial degree of self-governance to the
operators and that this is an industry that has demonstrated an
inability to obtain oil in a safe, responsible way. The commenter
referred to a recent series of surprise inspections of drilling rigs
that revealed a number of major safety violations and asserted that
several of the companies pushing hardest against the regulations were
cited for violations more often than the industry average. A different
commenter asserted that the proposed rule lacked adequate evidence that
it would protect safety. This commenter asserted that BSEE must
evaluate safety with respect to the different geographical environments
where the oil and gas operations will occur. The commenter noted that
different ocean environments present different constraints, challenges,
and operational risks; and asserted that BSEE must
[[Page 21928]]
evaluate whether the proposed revisions would ensure safety in all
environments. The commenter further asserted that BSEE did not provide
evidence that the existing regulations are actually a burden or that
removing safeguards will ensure adequate protections remain in place.
The commenter also asserted that the proposed rule did not provide
sufficient analysis on how it would safeguard workers and protect the
environment, but focused on assertions about reducing regulatory
burdens for industry and burdensome paperwork for regulators. The
commenter asserted that the proposed rule lacked any studies,
investigations, reports, or public solicitations for information.
    A commenter contended that the reduced oversight contemplated by
the proposed rule would make losses of well control and oil spills more
likely to occur. The commenter claimed that weakening safety
regulations designed to prevent blowouts would further contribute to
the already routine oil spills that will occur in the Atlantic if the
Administration finalizes its plan to allow oil and gas development in
that area. The commenter asserted that, if offshore drilling increases,
the level of safety and prudence must also increase.
     Response: BSEE reviewed all comments submitted and is
revising the proposed rule as appropriate. BSEE does not agree with the
commenters' assumption that this rulemaking will allow the operators to
govern their own safety. The use of various regulatory approaches in
this rulemaking--including the incorporation of standards; performance-
based requirements; independent third parties instead of BAVOs--
increases the responsibilities on operators, but does not reduce BSEE's
oversight responsibilities. BSEE continues to review and approve permit
applications for specific activities and to inspect all OCS facilities
for compliance with applicable law, regulation, plans, permits, and
lease terms. Operator applications must contain appropriate information
to demonstrate compliance with BSEE regulations, including any
documents incorporated by reference. The incorporation by reference of
industry standards does not mean the industry is self-regulating. BSEE
participates in the development of many of the standards incorporated
by reference. In addition, BSEE reviews and analyzes any standards
incorporated in the regulations to ensure the documents provide for
safety and environmental protection and are consistent with BSEE's
authorities and policies. BSEE may supplement standards with specific
regulatory provisions, if there are any places where the standards are
lacking. Most importantly, once incorporated by reference, such
standards are enforceable as any other regulatory requirement, and BSEE
is responsible for oversight of compliance and enforcement--it is not
left to industry. Further, if industry modifies an incorporated
standard, those modifications do not impact the regulatory requirements
unless and until BSEE incorporates those modifications through a
separate rulemaking.
    The commenter referred to a recent series of surprise inspections
of drilling rigs that revealed a number of major safety violations and
asserted that several of the companies pushing hardest against the
regulations were cited for violations more often than the industry
average. BSEE regularly conducts unscheduled or ``surprise''
inspections of facilities on the OCS. BSEE is not certain whether this
comment is referring to the regular unplanned inspections or a specific
increased inspection effort. Regardless, BSEE normally inspects mobile
offshore drilling units (MODUs) at least once every 30 days when they
are in operation on the OCS. BSEE does not agree with the assertion
that the companies most vigorously opposing the regulations were cited
for violations more often than the industry average. BSEE did not
consider the number of violations issued to specific operators when
developing this rulemaking.
    Regarding the concern that BSEE must evaluate safety with respect
to the different geographic environments where the oil and gas
operations will occur, BSEE agrees that differences in geographic
environment can impact the nature of operations. This is reflected in
the fact that certain of BSEE's regulatory requirements are
specifically tailored to particular geographic environments, such as
the Arctic or frontier areas. Prior to receiving approval from BSEE to
begin drilling operations on the OCS, an operator must submit an
exploration or development plan to BOEM for approval. The exploration
or development plan addresses operational considerations relevant to
the specific location and operating environment (for more information
on the content of exploration and development plans, go to: https://www.boem.gov/Submitting-Complete-Exploration-and-Development-Plans/).
As part of the review of the APD, BSEE confirms whether the APD is
consistent with the approved exploration or development plan, as well
as consistent with the additional requirements applicable to such
submissions, under the circumstances presented.
    Concerning the commenter's assertion that the development of the
proposed rule did not include studies, investigations, reports, or
public solicitations for information, BSEE disagrees. As previously
discussed, BSEE considered questions that arose during the
implementation of the 2016 WCR and the policies developed in response
to those questions. In addition, BSEE solicited input from interested
parties to identify potential revisions to the regulations; including
the public forum held on September 20, 2017, in Houston, Texas.
Further, BSEE received and considered a substantial amount of
information from commenters through the APA notice and comment process.
BSEE's approach to this regulatory reform was to consider input from a
variety of sources to make proposals that would carefully remove
unnecessary burdens while leaving critical safety provisions intact.
    Summary of comments: One commenter asserted that implementation of
the proposed rule and adoption of a related procedure for checking well
pressures as a standard industry practice would potentially have
prevented a number of fatalities. This commenter recommended that BSEE
incorporate a specific safety procedure in the regulations, so it would
become a standard industry practice.
     Response: BSEE received and assessed the comment and is
not incorporating the commenter's suggested procedure into the
regulations at this time. BSEE disagrees that it would be appropriate
to require the commenters' identified specific procedures on all wells
and rigs, and doing so would be beyond the scope of this rulemaking.
BSEE may evaluate the procedures for possible inclusion in future
rulemakings, if appropriate.
Comments on Energy Independence
    Summary of comments: Some commenters expressed concern that BSEE is
promoting increased drilling and energy independence at the expense of
its obligations to protect the environment. One commenter asserted that
BSEE's function is to promote safety and protect the environment. The
commenter referenced BSEE's explanation in the proposed rule that the
intention of this rulemaking is to fortify the Administration's
position toward facilitating energy security leading to increased
domestic oil and gas production and to reduce unnecessary burdens on
stakeholders.
[[Page 21929]]
However, the commenter asserted that it is not BSEE's duty to increase
production of oil or gas. The commenter noted BSEE's mission statement
that says its mission is to ``promote safety, protect the environment,
and conserve resources offshore through vigorous regulatory oversight
and enforcement.'' The commenter asserted that it is inappropriate for
BSEE to sacrifice its public trust obligations in favor of enhancing
industry profits.
     Response: BSEE disagrees with the commenters' assertions
that this rulemaking is promoting increased drilling and energy
independence at the expense of BSEE's obligations to protect safety and
the environment. BSEE recognizes its obligations to protect safety and
the environment under OCSLA; however, as stated in Sec.  250.101(b),
and pursuant to 43 U.S.C. 1332(3). BSEE is also obligated to follow
sound conservation practices to make OCS resources available for
development to meet the Nation's energy needs. Applying sound
conservation practices includes ensuring that the requirements in the
regulations do not unduly burden responsible development and production
of oil and natural gas resources, while maintaining safety and
environmental protection. BSEE's responsibilities go beyond safety and
environmental protection and extend to numerous aspects of the proper
management of OCS oil and gas operations. In addition, as previously
discussed, this rulemaking executes the mandates from the President and
the Secretary, as set forth in E.O. 13783--Promoting Energy
Independence and Economic Growth; E.O. 13795--Implementing an America-
First Offshore Energy Strategy; and Secretary's Order No. 3350. BSEE
disagrees that this rule fails to maintain safety and environmental
protection and stands by its determination that every change made in
this rule meets that standard.
Comments on Conflicts of Interest
    Summary of comments: Some commenters took issue with the fact that
BSEE incorporated input from interested parties in the proposed rule.
The commenters claimed that the proposed rule would allow operators to
provide their own oversight, while not acknowledging API's role as a
lobbyist for the oil and gas industry. These commenters asserted that
this creates a conflict of interest for these parties and for BSEE and
that this would make losses of well control and catastrophic oil spills
more likely. One of these commenters asserted that adopting standards
developed by API creates a conflict of interest, because API is a major
oil and gas industry trade association and lobbying firm. The other
commenter views the performance-based standards in the proposed rule as
poorly defined, claiming they should be clearly established before the
final rule's publication. The commenter asserts that a number of
provisions in the proposed rule regarding performance-based standards
are extremely vague. This commenter opined that BSEE should have
published an Advance Notice of Proposed Rulemaking (ANPR) to gather the
information necessary to prepare a better defined proposed rule, if
BSEE did not know which proposed standards to include.
    Response: BSEE disagrees with the suggestion that BSEE should have
published an ANPR before publishing the proposed rule. As previously
discussed, when BSEE initiated its review of these regulations, BSEE
held a public forum in Houston, Texas, which was attended by more than
110 interested parties. The participants of the public forum provided
comments and suggestions before BSEE began the process of developing
the proposed rule. BSEE likewise obtained useful input into the
development of this rulemaking through the Department's ``request for
comment'' on its overall regulatory reform initiatives. The proposed
rule also served as an opportunity for BSEE to secure public comment
and input.
    As discussed previously, this rulemaking does not allow operators
to operate without oversight. BSEE continues to serve in an oversight
and enforcement capacity, even where regulatory requirements are tied
to industry standards. BSEE also disagrees with the commenters'
assertion that there is a conflict of interest inherent in using
industry standards. Federal law in fact requires that an agency ``use
standards developed or adopted by voluntary consensus standards bodies
rather than government-unique standards, except where inconsistent with
applicable law or otherwise impractical.'' NTTAA; OMB Circular A-119 at
p. 13. BSEE follows the requirements of the NTTAA and the relevant
guidance in OMB Circular A-119 when incorporating standards into its
regulations. Membership in an API standard development committee is not
limited to industry representatives \28\ and may include non-industry
members, such as government personnel, consumer advocates, and
academics.
---------------------------------------------------------------------------
    \28\ http://mycommittees.api.org/standards/Reference/API%20Procedures%20for%20Standards%20Development-2016.pdf.
---------------------------------------------------------------------------
    BSEE disagrees with the assertion that the performance-based
standards incorporated by reference in this rulemaking are poorly
defined and vague and need to be more ``clearly established'' before
they can be adopted in a final rule. Performance-based standards
establish expectations for safe operations that allow for more
flexibility to determine the appropriate approach to meeting the
expectations based on specific operating conditions. This approach is
not a design flaw that must be corrected, but rather an important
feature of such standards. BSEE's regulations include a mix of
prescriptive and performance-based regulatory standards, and both
approaches offer a variety of strengths and benefits.
Comments on Production Safety Systems
    Summary of comments: A commenter discussed the removal of the
requirement for third-party certification for safety and pollution
prevention equipment (SPPE). This commenter asserted that both safety
and environmental risks would increase by removing the requirement for
third-party inspection and certification, especially for extreme
conditions. The commenter expressed concern regarding BSEE's proposal
to remove the requirement for review and certification of SPPE by an
independent third party contained in Sec.  250.802(c)(1), including the
requirement of inspection and certification to demonstrate that the
SPPE will function under the most extreme conditions to which it may be
exposed. The commenter opposed this change, asserting that: These
inspections were specifically tailored to address one of the causes of
the Deepwater Horizon catastrophe; third-party inspections respond to
extreme conditions becoming more prevalent and intense with climate
change; and SPPE implicates a level of risk that meets BSEE's standard
for requiring third-party inspection.
     Response: This comment is related to another rulemaking--
1014-AA37 Production Safety Systems (AA37). The final rule for that
rulemaking was published in the Federal Register on September 28, 2018
(83 FR 49216). BSEE received this comment in connection with that
rulemaking, as well, and responded to it in the AA37 production safety
systems final rule.
[[Page 21930]]
V. Section-by-Section Summary and Responses to Comments on the Proposed
Rule
    This summary discusses every section of 30 CFR part 250 proposed
for revision in the proposed rule and this final rule. This summary
does not address sections of the existing regulations that are not
implicated by the proposed or final rule. Although BSEE did not receive
substantive comments on numerous sections covered by the proposed rule,
the final rule includes and summarizes those sections. BSEE received
substantive comments on many other sections covered by the proposed
rule, some of which are included in this final rule without revision
and some of which are revised in the final rule. Those sections, as
well as the relevant comments on those sections and BSEE's responses,
are summarized here.
Subpart A--General
What are the procedures for, and effects of, incorporation of documents
by reference in this part? (Sec.  250.115)
    This section in the current regulations is reserved.
Summary of Proposed Revisions
    BSEE did not propose any specific changes to this section in the
proposed rule. However, in the proposed rule discussion of Sec.
250.198, BSEE discussed the potential for technical (non-substantive)
revisions to Sec.  250.198 for the purposes of reorganizing and
revising that section to make it clearer, more user-friendly, and more
consistent with the OFR's recommendations for incorporations by
reference in Federal regulations. BSEE consulted with the OFR regarding
its suggestions for specific organizational and language changes to
Sec.  250.198 and addressed such technical revisions in this final
rule. One element of the organizational changes involved moving certain
portions of existing Sec.  250.198 out of that regulation, so that it
is focused more exclusively on the incorporated materials themselves.
BSEE chose to implement this action by relocating the relevant
provisions to reserved Sec.  250.115. BSEE determined that those
technical revisions will not have a substantive impact on the
incorporations by reference of industry standards discussed in this
rule or elsewhere.
Summary of Final Rule Revisions
    This final rule adds new Sec.  250.115 in accordance with the
recommendations and requirements of the OFR pertaining to regulations
that incorporate documents by reference. The language of Sec.  250.115
is based on the introductory language in the existing Sec.  250.198,
with certain minor, non-substantive wording changes for clarity. The
revised Sec.  250.198, which will serve as a centralized Incorporated
by Reference (IBR) section, deletes the introductory language in
accordance with OFR's recommendations for these types of IBR
provisions. Specifically, the OFR recommends that a centralized IBR
section, such as Sec.  250.198, should not include language regarding
legal requirements or justifications, scope of the regulations,
instructions, or policy. The OFR recommends that the centralized IBR
section list documents incorporated by reference and provide
information about where the standards are referenced in the regulations
and how to obtain a copy of the actual standards. Accordingly, this
rulemaking removes the introductory language in existing Sec.  250.198
and relocates the language to the new Sec.  250.115 with minor
revisions.
Documents Incorporated by Reference (Sec.  250.198)
    This section of the existing regulations includes citations and
other information regarding all documents (e.g., industry standards)
incorporated by reference in 30 CFR part 250, including where to find
references to the incorporated documents in specific sections of the
regulations. The requirements for complying with a specific
incorporated document can be found where the document is referenced in
the regulations, as specified in existing Sec.  250.198. The existing
section also discusses BSEE's process for incorporating documents by
reference, the regulatory effects of incorporation, and procedures that
operators may follow to seek BSEE's approval to comply with
alternatives to an incorporated document.
Summary of Proposed Revisions
    BSEE proposed to:
    Revise existing paragraph (h)(63), which incorporates API Standard
53, to add a new cross reference to Sec.  250.734, as revised in the
final rule. BSEE also solicited comments on whether to incorporate the
2016 addendum to this standard;
    Revise existing paragraph (h)(78), which incorporates API Standard
65--Part 2, Isolating Potential Flow Zones During Well Construction;
Second Edition, December 2010, to add a new cross reference to Sec.
250.420(a);
    Revise existing paragraph (h)(94) to update the incorporation of
API RP 17H to the Second Edition; and
    Add a new paragraph (j)(2) for the incorporation by reference of
ISO/IEC 17021-1 in order to update the erroneous standard previously
incorporated by the 2016 WCR.
    As previously mentioned, the proposed rule also discussed potential
technical (non-substantive) revisions to Sec.  250.198 that BSEE was
considering to address recommendations from the OFR.
Summary of Final Rule Revisions
    As explained in the previous discussion of new Sec.  250.115, BSEE
is reorganizing this section consistent with the OFR's recommendations.
These revisions include technical, non-substantive changes to the
organization of the section to remove discussions of matters other than
the incorporated materials themselves and to make the section more user
friendly, as well as minor wording and formatting changes for clarity
and consistency.
    Also, based on comments on the proposed rule, BSEE is revising
final paragraph (e)(94) to include the addendum to the already
incorporated API Standard 53 Fourth Edition, November 2012.
    For the reasons discussed in the section-by-section summary for
Sec.  250.427 of this final rule, BSEE is also adding a new paragraph
(e)(6), incorporating by reference API Bulletin 92L.
    The final rule includes, without change, all other documents
proposed for incorporation by reference, including:
    API Standard 65--Part 2, Isolating Potential Flow Zones During Well
Construction; Second Edition, December 2010;
    API Recommended Practice 17H, Remotely Operated Tool and Interfaces
on Subsea Production Systems, Second Edition, June 2013, Errata January
2014; and
    ISO/IEC 17021-1--Conformity assessment--Requirements for bodies
providing audit and certification of management systems--Part 1:
Requirements, First Edition, June 2015.
Summary of Comments
Comments Related to Proposed Sec.  250.198--Incorporation of API
Standard 53 Addendum
    Summary of comments: Some commenters suggested that BSEE
incorporate API Standard 53, 4th Edition, Addendum, which was released
in July 2016. These commenters asserted that many of the operations in
the Gulf of Mexico already comply with the July 2016 Addendum
[[Page 21931]]
of API Standard 53 4th Edition. They asserted that the Addendum
clarifies the existing text of API Standard 53, including clarifying
unintended conflicts with API Specification 16C, Specification for
Choke and Kill Equipment and that these clarifications would increase
operational safety and reliability. They also asserted that the
Addendum was compiled, reviewed, and approved by industry
representatives, including operators, equipment owners, original
equipment manufacturers (OEMs), independent third parties, and service
companies. These commenters stated that API is developing a 5th Edition
of API Standard 53, but that it was not available at the time of the
rulemaking.
     Response: BSEE agrees with the commenter's suggestion
about incorporating the API Standard 53 addendum into the regulations.
BSEE reviewed the Addendum and determined that it would not
significantly alter or negatively impact safety. It does, however,
address and resolve the same problematic issues for which BSEE
currently grants departures, and the IBR of the Addendum will eliminate
the need for granting such departures going forward (e.g., section
7.2.3.2.9 Side outlet location and section 7.3.13.2.5 fire rating of
MUX lines). Therefore, BSEE determined that the Addendum is appropriate
for incorporation into the regulations.
    With regard to the comments about API developing API standard 53
5th Edition, BSEE will evaluate that document when it is finalized for
possible incorporation into the regulations in a future rulemaking.
    Summary of comments: A commenter suggested that arbitrary
requirements beyond the provisions in API Standard 53 ``reduce safety
by adding unnecessary complexity to the blowout prevention equipment
systems.''
     Response: The commenter does not specify which
requirements in the regulations the commenter considers to be arbitrary
or how such requirements add ``unnecessary complexity to the blowout
prevention equipment systems.'' In any event, BSEE disagrees with the
commenter's assertion that any requirements in this final rule or
existing regulations related to BOP systems are arbitrary or
unnecessary. For all the reasons discussed in the 2016 WCR, other prior
rulemakings, and in the proposed rule and this final rule, BSEE has
determined that any such additional requirements are reasonable and
appropriate to ensure that BOP systems are designed and utilized
appropriately.
Comments Related to Proposed Sec.  250.198--Effectiveness of Using
Industry Standards
    Summary of comments: A commenter objected to BSEE incorporating by
reference any industry standards developed by the oil and gas industry,
asserting that standards are ``more fluid and not enforceable by law.''
The commenter asserted that this makes it more difficult for BSEE to be
effective, noting that similar problems existed prior to the Deepwater
Horizon oil spill. The commenter cited the BP Oil Spill Commission
report, asserting that it criticized this culture and stated that the
Department of the Interior has in turn relied on API in developing its
own regulatory safety standards and that API's shortfalls have
undermined the entire Federal regulatory system. This commenter was
concerned about findings from the BP Oil Spill Commission report that
the API standards represent the ``lowest common denominator,'' and do
not reflect ``best industry practices.''
     Response: BSEE disagrees with the commenters' assertions
that the documents incorporated by reference are not enforceable and
that BSEE relies on API to develop regulations. First, BSEE notes that
the cited Report's concerns with incorporation of industry standards
were based on agency practices and other circumstances pre-dating the
2010 Deepwater Horizon incident. Since that event, many BSEE and
industry practices and circumstances have changed significantly.
Concerning the comments on BSEE's use of API standards and the
assertion that API standards increasingly do not represent best
industry practices, BSEE does not agree that incorporation and use of
the standards referenced in this final rule is either inappropriate or
detrimental to safety and environmental protection. For example, BSEE
evaluated the differences between the first and second editions of API
RP 17H and determined that the second edition of API RP 17H eliminates
the conflict between the first edition and API Standard 53, helps
ensure that the appropriate methods are utilized to comply with the API
Standard 53 ROV closure timeframes of 45 seconds, and includes
provisions on high flow Type D 17H hot stabs. All of the standards
referenced in this rulemaking serve as a valuable complement to BSEE's
regulations in helping to achieve the bureau's safety and environmental
objectives under OCSLA. When incorporated into the regulations, these
standards provide a binding baseline that BSEE may supplement with
specific requirements where appropriate.
    Moreover, as previously discussed, the NTTAA mandates that Federal
agencies use technical standards developed by voluntary consensus
standards organizations, instead of government-developed standards,
where practicable and consistent with applicable law. There are only a
few SDOs, including API, that address issues related to offshore oil
and gas operations. Also, API provides standards on technical topics
that are not addressed by other SDOs. Additionally, consistent with the
NTTAA's preference for agency use of voluntary consensus standards (see
15 U.S.C. 272(e)(1)(A)(v)), API develops its standards through a
general consensus process, which provides for input from those who are
potentially materially impacted by the standard, however, membership on
API standards committees is not limited to industry participants. In
addition, based on recommendations in other post-Deepwater Horizon
reports (see, e.g., Final Report on the Investigation of the Macondo
Well Blowout, Deepwater Horizon Study Group (March 1, 2011) at pp. 94-
98), BSEE has expanded its standards program and increased its
involvement in the standards development process, including development
of many API standards, and is continuously improving and formalizing
BSEE's internal process for reviewing standards relevant to the
regulatory program. These developments help BSEE identify issues that
may not be adequately addressed in incorporated standards and to
supplement those standards, as necessary, in its regulations.
    BSEE also disagrees with the commenter's assertion that industry
developed standards should not be incorporated in its regulations
because BSEE does not have the authority to enforce compliance with
incorporated documents. BSEE incorporates industry standards by
reference in accordance with the requirements of the NTTAA and
implementing OMB guidance, OFR regulations (1 CFR part 51), and BSEE's
own procedures for incorporation (Sec.  250.115, What are the
procedures for, and effects of, incorporation of documents by reference
in this part?). The effect of incorporation by reference of an industry
standard into the regulations is that the incorporated document becomes
a regulatory requirement, see existing Sec.  250.198(a)(3) (moved to
new final Sec.  250.115(c)), and thus becomes subject to BSEE oversight
and enforcement in the same manner as other regulatory requirements.
BSEE has
[[Page 21932]]
repeatedly described this principle in a number of previous
rulemakings.
    BSEE is not certain what the commenter means by industry standards
being ``more fluid.'' However, the commenter may be concerned about
industry issuance of revisions to or new editions of incorporated
standards. The OFR regulations, at 1 CFR part 51, govern how BSEE and
other Federal agencies incorporate documents by reference. Agencies may
incorporate a document by reference by publishing in the Federal
Register the document title, edition, date, author, publisher,
identification number, and other specified information. Incorporation
by reference of a document is limited to the edition of the document so
incorporated. See existing Sec.  250.198(a)(1) (moved to new final
Sec.  250.115(a)). In short, the operator must comply with the edition
of the standard that BSEE incorporates in its regulations. If an SDO
later revises a standard that BSEE has previously incorporated in a
final rule, BSEE would need to evaluate the revised standard before
choosing whether to incorporate it through rulemaking into the
regulations; in other words, industry itself cannot change the
regulatory requirements by revising a standard after BSEE incorporates
the standard in its regulations.
Comments Related to Proposed Sec.  250.198--Use of the Latest Published
Edition and Incorporation of Additional Documents
    Summary of comments: Several commenters recommended that BSEE
incorporate the latest published edition of each standard into the
regulations. Commenters asserted that BSEE has directly participated in
the development of these standards and that recognition of these
standards in the regulations would be consistent with the expectations
of the NTTAA, which requires BSEE to consult and use technical
standards that are developed or adopted by voluntary consensus
standards bodies in lieu of BSEE creating its own unique standards.
     Response: BSEE generally agrees that it should consider
whether to incorporate the latest editions of standards for which prior
editions are already incorporated in the regulations. BSEE reviews its
regulations in accordance with E.O. 13563--Improving Regulation and
Regulatory Review and E.O. 13610--Identifying and Reducing Regulatory
Burdens, ``to ensure, among other things, that regulations
incorporating standards by reference are updated on a timely basis . .
. .'' (OMB Circular A-119 at p. 4). In fact, BSEE is currently
reviewing many of the standards incorporated in the existing
regulations and will provide additional information regarding its
review when appropriate. If BSEE decides that some updating of
incorporated standards (e.g., by referencing new editions of existing
standards, or replacing previously incorporated standards with
different standards, or simply deleting outdated standards) in the
regulations is warranted, it will explain its position through future
rulemakings, as appropriate. Of course, BSEE may also decide, for
appropriate reasons, to keep a previously incorporated edition of a
standard in the regulations even if there is an updated edition. BSEE
is not in a position at this time, either substantively or
procedurally, to implement the updates suggested by the commenter as
part of this final rule.
    Summary of comments: Some commenters recommended that BSEE should
incorporate into its regulations additional documents and updated
editions associated with BOP systems (e.g., ANSI/API Spec. 16A--
Specification for Drill-through Equipment, API Standard 16AR--Standard
for Repair and Remanufacture of Drill-through Equipment, and API Spec
20E--Alloy and Carbon Steel Bolting for Use in the Petroleum and
Natural Gas Industries).
     Response: BSEE acknowledges the importance of those
standards to offshore operations. However, they were not proposed for
incorporation in the proposed rule and BSEE is not currently in a
position--procedurally or substantively--to incorporate them into this
final rule. BSEE will evaluate these documents for possible future
incorporation in the regulations. BSEE continually evaluates new
standards and new editions of existing standards for possible
incorporation into the regulations. If, after completing evaluations of
these standards, BSEE determines they are appropriate to incorporate,
we may proceed with a separate rulemaking process to incorporate the
documents.
    Summary of comments: A commenter recommended that BSEE define
international standards as any globally recognized, good-practice
standards.
     Response: BSEE does not agree that any such definition is
necessary in these regulations. BSEE follows the guidance established
by OMB Circular A-119. With respect to international standards, OMB
Circular A-119 explains that the United States is obligated under the
Technical Barriers to Trade (TBT) Agreement to use relevant
international standards, except where such standards would be an
ineffective or inappropriate means to fulfill the legitimate objective
pursued. In particular, according to OMB Circular A-119, the TBT
Agreement, Article 2.4, provides that where technical regulations are
required and relevant international standards exist or their completion
is imminent, World Trade Organization (WTO) Members shall use them, or
the relevant parts of them, as a basis for their technical regulation.
In addition, 19 U.S.C. 2532 directs Federal agencies, in developing
standards, to base their standards on international standards, if
appropriate. OMB Circ. A-119 (p. 22).
Subpart B--Plans and Information
What must the DWOP contain? (Sec.  250.292)
    This section of the existing regulations specifies information
(e.g., description of the typical wellbore, structural design for each
surface system) that must be included in a DWOP. Paragraph (p) of this
section details the information that must be contained within a DWOP
relating to free standing hybrid risers (FSHR) and the associated buoy
and tether system.
Summary of Proposed Revisions
    BSEE proposed to revise the FSHR requirements of this section to
eliminate duplicative submittals and certifications of FSHR systems.
Summary of Final Rule Revisions
    BSEE received no substantive comments on these provisions of the
proposed rule and includes the proposed language in the final rule
without change.
Subpart D--Oil and Gas Drilling Operations
What must my description of well drilling design criteria address?
(Sec.  250.413)
    This section of the existing regulations specifies the type of
information that must be provided in the well drilling description
portion of an APD.
Summary of Proposed Revisions
    BSEE proposed to add to paragraph (g) a parenthetical clarification
of ``surface and downhole'' after ``proposed drilling fluid weights,''
to ensure the operator includes the weight of the drilling fluid in
both places. BSEE proposed this clarification to help ensure the
drilling fluid weight is fully evaluated and appropriate for the
estimated bottom hole pressures.
[[Page 21933]]
Summary of Final Rule Revisions
    BSEE received a few comments in general support of the proposed
revisions to this section, and is including the proposed language in
the final rule without change.
What must my drilling prognosis include? (Sec.  250.414)
    This section of the existing regulations describes the information
that must be included in the drilling prognosis portion of an APD.
Summary of Proposed Revisions
    BSEE proposed to revise paragraph (c)(3) of this section to add the
words ``and analogous'' before ``well behavior observations'' and ``,
if available'' at the end of the paragraph. BSEE proposed this minor
wording change to ensure that operators use available data from wells
with similar conditions to those of the well being drilled when
determining the pore pressure and fracture gradient to ensure accuracy
and safety when establishing the drilling margin. In the proposed rule,
BSEE solicited comments on many of the safe drilling margin provisions,
including potential alternatives to the current default 0.5 ppg
drilling margin and the possibility of replacing it with a more
performance-based standard.
Summary of Final Rule Revisions
    The 0.5 ppg drilling margin requirements in this section remain
unchanged. As in the existing regulations, the final rule requires the
use of a default 0.5 ppg drilling margin while continuing to allow for
a deviation from the default under certain circumstances. The request
to deviate does not have to be submitted as an alternate procedure or
departure request. However, as the proposed rule indicated, BSEE
considered whether to allow a different method or ``avenue'' for
operators to submit a justification for a different drilling margin (83
FR 22133). Based on comments received, BSEE is revising Sec.
250.414(c)(2) to allow operators the option to submit the required
justification for BSEE approval at an earlier date prior to the APD.
Any such approval will be contingent upon confirmation in the APD that
the plans and information underlying the BSEE approved justifications
have not changed. An operator may submit such requests prior to an APD,
or continue to provide that information within the APD. Regardless of
the timing of the request to use an alternative drilling margin, each
request will require the supporting justifications as provided in
existing regulations. BSEE is currently approving some APDs with
drilling margins other than 0.5 ppg based on specific well conditions.
Summary of Comments
Comments Related to Proposed Sec.  250.414--Opposition to Any Proposed
Revisions to the 0.5 ppg Safe Drilling Margin
    Summary of comments: Multiple commenters expressed significant
concerns about potential revisions to the 0.5 ppg safe drilling margin
requirements and emphasized the importance of a safe drilling margin.
Many commenters also asserted that the 0.5 ppg margin was added to the
existing regulations based on the technical work and recommendations
from the National Academy of Engineering and the National Research
Council arising out of Deepwater Horizon investigations and that any
proposed changes to or removal of the safe drilling margin requirements
lack technical evidence or justification. Commenters asserted that BSEE
must have clear, defined, and enforceable criteria to determine whether
the proposed drilling margin will be safe and cannot simply accept an
operator's conclusory statements that its proposal is safe.
     Response: BSEE agrees with the commenters' concerns about
making revisions to the 0.5 ppg drilling margin requirements at this
time. BSEE is keeping the 0.5 ppg drilling margin as a presumptive
minimum requirement as a default standard in the regulations. As more
drilling margin data and research becomes available, BSEE may
reevaluate the drilling margin for possible revisions in future
rulemakings.
Comments Related to Proposed Sec.  250.414--Use of a Performance-Based
Drilling Margin
    Summary of comments: Multiple commenters expressed support for
revising or removing the 0.5 ppg safe drilling margin default standard
requirement. Some commenters recommended replacing the current
requirements with a performance-based standard established on a case-
by-case basis, based on data and analysis specific to a particular
well. Those commenters asserted that this would be a safer and better
alternative for establishing safe drilling margins. They asserted that
such an alternative would provide a risk-based approach that ensures
safety and provides investment certainty to the industry. Some
commenters also suggested that industry would welcome the opportunity
to propose an engineered, performance-based standard for the
establishment of appropriate safe drilling margins through the well
permitting process. Some commenters asserted that technology has
improved to justify a performance-based drilling margin, specifically
citing hydraulic modeling techniques, managed pressure drilling, and
use of real-time downhole pressure while drilling (PWD).
     Response: BSEE does not accept the commenters'
recommendations to replace the 0.5 ppg drilling margin with a
performance-based option. BSEE notes, however, that existing
regulations provide opportunities for similar case-by-case analyses
based on specific well conditions. The regulations establish default
minimum requirements; however, they also allow for deviation from the
default 0.5 ppg drilling margin with sufficient justification, based on
demonstrated well conditions and operational plans. It is the
operator's responsibility to provide sufficient data and justification
to use a lower drilling margin. BSEE is retaining the 0.5 ppg drilling
margin as a presumptive minimum requirement as a default standard in
the regulations. As more drilling margin data and research becomes
available, BSEE may reevaluate the drilling margin for possible
revisions in future rulemakings.
    BSEE agrees that technology is improving and could help justify a
performance-based drilling margin at some point. However, BSEE would
need to obtain and evaluate more research and data before it can
develop and adopt a performance-based drilling margin. In the meantime,
an operator may use the improved technologies cited by the commenters
to substantiate an alternative drilling margin specified in an APD,
provided it complies with the requirement in existing Sec.
250.414(c)(2) regarding adequate documentation to justify the
alternative margin.
Comments Related to Proposed Sec.  250.414--Drilling Margin Below 0.5
ppg
    Summary of comments: Some commenters asserted that evaluation and
analysis of industry data on wells drilled demonstrates that operators
have safely planned and drilled sections of wells below the current
default 0.5 ppg drilling margin and that the current 0.5 ppg margin is
arbitrary and does not ensure safety.
     Response: BSEE agrees with the commenters that operators
have successfully drilled some wells below the default 0.5 ppg drilling
margin under the current regulations. As noted in the proposed rule,
between promulgation of that default margin in
[[Page 21934]]
the 2016 WCR and publication of the proposed rule, BSEE approved the
drilling of 32 wells with drilling margins below the 0.5 ppg default.
Operators may continue to utilize drilling margins below 0.5 ppg
provided that they apply for such a margin in their APDs and comply
with the requirements in Sec.  250.414(c)(2) by providing adequate
documentation to justify the alternative drilling margin. However, BSEE
disagrees with the commenters' assertion that the 0.5 ppg margin is
arbitrary and does not ensure safety. A 0.5 ppg is an appropriate safe
drilling margin for normal drilling scenarios, and, prior to the
promulgation of the 2016 WCR, BSEE approved (and thus made a
requirement) this margin in numerous APDs. BSEE understands that there
are some well-specific circumstances that may justify an acceptable
lower drilling margin to drill a well safely and BSEE has approved
appropriate alternative downhole mud weights as part of a safe drilling
margin in many APDs. However, BSEE is choosing not to alter the 0.5 ppg
default drilling margin in this final rule.
    Summary of comments: A commenter recommended adding the Conceptual
Deepwater Operations Plan (CDWOP or DWOP) into the regulatory text with
the objective of obtaining field-wide approvals when it is anticipated
that a lower drilling margin may be needed on numerous wells. The
commenter asserted that this would be important for sanctioning major
capital projects, since regulatory certainty is critical when making
multi-billion dollar investment decisions. In particular, the commenter
asserted that industry needs clarity on the requirements for permit
approval and reasonable certainty that BSEE will approve an engineered
drilling margin before incurring major costs that would be wasted if
approval were denied.
     Response: BSEE declines to accept the commenter's
suggestion. The DWOP or CDWOP is a field overview and not well-
specific. The operator submits a DWOP for each development project in
which it will use non-conventional production or completion technology,
however that submission does not include the full scope of relevant
information required in the APD. BSEE does not believe that the
relevant determinations can be reached at a field level through the
DWOP process, as opposed to the well-specific level. However, BSEE
recognizes that the timing of drilling margin approval may affect
sanctioning of major capital projects, and BSEE is revising Sec.
250.414(c)(2) to allow operators the option to submit the required
justification for a proposed alternative safe drilling margin for BSEE
approval at an earlier date prior to the APD. Any such approval will be
contingent upon confirmation in the APD that the plans and information
underlying the BSEE approved justifications have not changed. BSEE is
not revising the requirements to use a default 0.5 ppg drilling margin
or the standards for obtaining approval of a deviation from the default
under certain circumstances. As such, this change will have no impact
on safety or environmental protection. The revision to Sec.
250.414(c)(2) will simply provide operators with the option to request
BSEE approval for alternative safe drilling margins on a well-by-well
basis at any time that the necessary information is available. BSEE
drilling engineers review drilling margins and the APD with intimate
knowledge of the particular field and are the subject matter experts on
drilling in their respective BSEE regions.
What well casing and cementing requirements must I meet? (Sec.
250.420)
    This section of the existing regulations imposes specific
requirements for casing and cementing of all wells.
Summary of Proposed Revisions
    BSEE proposed to incorporate by reference API Standard 65--Part 2
in paragraph (a)(6) of this section for purposes of specifying the
standards to ensure centralization of the pipe during cementing. BSEE
determined that the standards set forth in API Standard 65--Part 2
would provide clearer guidelines for operators than the existing
regulatory language.
Summary of Final Rule Revisions
    BSEE received a few comments in general support of the proposed
revisions to this section and is including the proposed language in the
final rule without change.
What are the casing and cementing requirements by type of casing
string? (Sec.  250.421)
    This section of the existing regulations specifies casing and
cementing requirements applicable to certain types of casing strings
(e.g., drive or structural strings, conductor strings).
Summary of Proposed Revisions
    BSEE proposed to make minor revisions in paragraphs (c), (d), (e),
and (f) to clarify that all identified length requirements are to be
taken from measured depth. This clarification of the existing
regulatory requirements would provide consistency for planning and
permitting purposes. Also, in paragraph (f), BSEE proposed removing the
specifics of the listed example regarding when a liner may be used as
intermediate casing. The proposed rule stated that the example is
redundant because it restates the same information already contained in
this section.
Summary of Final Rule Revisions
    BSEE received a few comments in general support of the proposed
revisions to this section, and is including the proposed language in
the final rule without change.
What are the requirements for casing and liner installation? (Sec.
250.423)
    This section of the existing regulations establishes requirements
for proper installation of casing in the subsea wellhead or liner in
the liner hanger, including requirements for latching or lock down
mechanisms and pressure testing on the seal assembly.
Summary of Proposed Revisions
    BSEE proposed to revise paragraphs (a) and (b) by removing the
words ``and cementing'' after ``upon successfully installing.'' The
proposed rule explained that revisions to this section are necessary
because there are many situations in the design of the casing or liner
string running tool where the latching or lock down mechanism is
automatically engaged upon installing the string. BSEE proposed these
revisions to allow more flexibility on an operational, case-by-case
basis for determining the appropriate time to engage these mechanisms
and thus reduce the number of alternate procedure requests submitted to
BSEE for approval under Sec.  250.141.
Summary of Final Rule Revisions
    BSEE received and considered comments on the proposed revisions and
includes the proposed revisions in the final rule. Additionally, as
suggested by some commenters, BSEE is revising paragraphs (a) and (b)
by removing from each the following language: ``If there is an
indication of an inadequate cement job, you must comply with Sec.
250.428(c).'' These statements are unnecessary because Sec.  250.428(c)
is applicable for any cementing operation and does not need to be
specifically cross referenced in this section. Removing this cross
reference does not change any requirements for how operators must
respond to indications of an inadequate cement job; if there are any
indications of an inadequate cement
[[Page 21935]]
job, the operator must evaluate the cement job as required in Sec.
250.428.
Summary of Comments
    Summary of comments: Many commenters agreed with the proposed
changes, and also asserted that references to section Sec.  250.428 in
this section were redundant and should be removed from this section.
     Response: BSEE agrees with the commenters that referencing
Sec.  250.428 is not necessary in this section, and has revised the
final regulatory text accordingly. This language is unnecessary because
Sec.  250.428(c) is applicable for any cementing operation and thus
does not need to be specifically cross-referenced in paragraphs (a) and
(b). Removing this cross-reference does not change any requirements for
how operators must respond to indications of an inadequate cement job;
if there are any indications of an inadequate cement job, the operator
must evaluate the cement job as required in Sec.  250.428.
    Summary of comments: A commenter expressed concerns that the
proposed revisions to this section would compromise safety and asserted
that BSEE failed to explain why its prior rationale for the language of
Sec.  250.423 contained in the 2016 WCR was inaccurate or no longer
applies. The commenter recommended retaining the current regulatory
requirements.
     Response: BSEE disagrees that this revision compromises
safety or is inaccurate and inconsistent with prior rationale. After
further BSEE review since the 2016 WCR, and as discussed in the
proposed rule, some of these latching or locking mechanisms are
designed to automatically engage upon installation of the associated
string. The revisions made by this final rule continue to ensure the
lock down mechanisms are properly securing the appropriate liner or
casing in place to ensure wellbore integrity while eliminating
inconsistency between the existing regulatory text and certain common
designs of the relevant mechanisms.
What are the requirements for pressure integrity tests? (Sec.  250.427)
    This section in the current regulations specifies the requirements
for conducting pressure integrity testing. This section also requires
the operator to revise its drilling program based upon pressure
integrity testing and hole behavior observations and requires the
operator to maintain the safe drilling margin while drilling.
Summary of Proposed Revisions
    BSEE did not propose any revisions to this section. BSEE did,
however, solicit comments regarding potential alternative approaches to
administering the safe drilling margin requirements, including
specifically ``whether there are situations where drilling can continue
prior to receiving alternative safe drilling margin approval from
BSEE,'' such as ``where, despite not being able to maintain the
approved safe drilling margin, an operator's continued drilling with an
alternative drilling margin creates little risk'' and ``what level of
follow-up reporting . . . would be appropriate.''
Summary of Final Rule Revisions
    Based upon comments received, BSEE is revising paragraph (b) to
require notification to the BSEE District Manager in the event the
required safe drilling margin cannot be maintained, and to incorporate
API Bulletin 92L as a standard for further action, where appropriate.
In conjunction with the incorporation of API Bulletin 92L, BSEE is
requiring submittal of a revised permit documenting any responsive
actions taken to remedy lost circulation. BSEE is also clarifying that
the District Manager must review and approve any proposed remedial
actions where the operator suspends drilling operations in response to
an inability to maintain the drilling margin.
Summary of Comments
Comments Related to Proposed Sec.  250.427--Incorporation of API
Bulletin 92L
    Summary of comments: Many commenters requested that BSEE
incorporate API Bulletin 92L, in accordance with NTTAA requirements,
for managing certain well conditions such as mud losses. The commenters
asserted that this document was developed by API with BSEE
participation to provide detailed operational direction in the event of
lost circulation while drilling in the Gulf of Mexico. The commenters
asserted that it is appropriate for operators to specify, in the well's
DWOP or APD, how they will remedy an anticipated loss of circulation on
bottom. They also asserted that, if an operator experiences an
unanticipated loss of circulation or a reduced drilling margin, the
operator should provide notice and the operator's plan for remedying
the issue to BSEE within a reasonable timeframe.
     Response: For the reasons explained in part III.B.1 of
this notice, BSEE agrees with the commenters' recommendations to
incorporate API Bulletin 92L. BSEE is revising Sec.  250.427(b) to
allow operators to take action in accordance with API Bulletin 92L, and
provide notification to the BSEE District Manager documenting the
operator's use of API Bulletin 92L, when the operator cannot maintain
its approved drilling margin. In conjunction with the use of API
Bulletin 92L, BSEE is requiring submittal of a revised permit
documenting any remedial actions. BSEE has evaluated API Bulletin 92L
and determined that reliance on that standard when responding to
drilling margin issues would not reduce safety. BSEE also determined
that this document is consistent with BSEE policy in the approaches
used to address these issues, appropriate for meeting the agency's
regulatory needs, and preferable to an agency-developed standard. API
Bulletin 92L includes flow charts that can be used as an aid to safely
drill ahead when lost circulation occurs and the required criteria and
procedures are met.
What must I do in certain cementing and casing situations? (Sec.
250.428)
    This section of the existing regulations describes actions that
must be taken when certain situations (e.g., unexpected formation
pressures) are encountered during casing or cementing operations.
Summary of Proposed Revisions
    BSEE proposed to revise paragraph (c) to include the term
``unplanned'' when describing the lost returns that provide indications
of an inadequate cement job. BSEE proposed this revision to minimize
the number of unnecessary revised permits submitted to BSEE for
approval. Current cementing practices utilize improved well modelling
to identify and account for zones that may have anticipated losses that
are not indicative of an inadequate cement job.
    BSEE proposed to redesignate existing paragraph (c)(iii) as new
paragraph (c)(iv) and to add new paragraph (c)(iii) to allow the use of
tracers in the cement, and the logging of the tracers' location prior
to drill out, as an alternative approach for locating the top of
cement. BSEE proposed this addition to provide more viable options and
more flexibility for locating top of cement, without compromising
safety, in order to help minimize rig down time from running in and out
of the hole multiple times.
    In addition, BSEE proposed a revision to paragraph (d) to clarify
that, if there is an inadequate cement job, operators are required to
comply with Sec.  250.428(c)(1). This revision would help assess the
overall cement job to
[[Page 21936]]
allow for improved planning of remedial actions.
    BSEE also proposed to revise paragraph (d) to allow BSEE to pre-
approve remedial cementing actions through a contingency plan within
the original approved permit. BSEE proposed to allow operators to
include the remedial actions as contingency plans in the original APD,
for BSEE to consider for pre-approval, in order to minimize the time
necessary for operators to commence approved remedial cementing
actions, and to reduce burdens on operators and BSEE resulting from
multiple submissions of revised permits. However, the rule clarifies
that, if BSEE has not already approved the remedial actions, the
operator must submit the remedial actions in a revised permit
application for BSEE review and approval.
Summary of Final Rule Revisions:
    BSEE received and considered comments on these provisions of the
proposed rule and includes the proposed language in the final rule
without change.
Summary of Comments
Comments Related to Proposed Sec.  250.428(d)--Use of a Professional
Engineer (PE)
    Summary of comments: A commenter opposed the proposal to allow pre-
approval of remedial cementing actions in lieu of requiring [acy]
[Rcy][IEcy] approval at the time, asserting that pre-approval would be
hypothetical since the problem to b[iecy] remedied would not b[iecy]
known at the time of approval.
     Response: BSEE disagrees with the commenter. PE
certification of the remedial actions may be included in the original
permit, if the operator is able to anticipate where losses may occur
(e.g., depleted zones, known geology). The PE may review the proposed
remedial actions in the original permit to ensure integrity and
consistency with BSEE's regulations. If the operator chooses to include
contingency planning in the original permit application, those
contingencies would be reviewed and certified by the PE. If the
operator encounters circumstances that the approved permits do not
address (including PE certification), it would be required to submit a
revised permit for BSEE approval that would include the PE
certification. Accordingly, the commenter's concern that the problem
would not be known at the time of approval is addressed by the fact
that any approval will reach only those issues foreseen and considered
at the time of approval; if the issue that arises was not considered
and approved for remedial action, the operator must obtain separate
approval to remedy the actual issue presented.
Comments Related to Proposed Sec.  250.428--Unplanned Versus
Unanticipated Lost Returns
    Summary of comments: A commenter suggested that the proposed
wording change should be ``unanticipated lost returns'' instead of
``unplanned lost returns.''
     Response: BSEE disagrees with commenter. This change is
not necessary because certain lost returns can be planned for within a
BSEE-approved permit, and the information can be identified, included,
and approved within the permit. Further, there can be lost returns that
an operator may not ``anticipate'' occurring, but which the operator
nevertheless may be able to plan for in advance, should they occur. The
key is whether the operator has an acceptable plan in place for
addressing the lost returns, regardless of whether it anticipates them
occurring or not. If an operator encounters circumstances that are not
described in an approved permit, such as unplanned lost returns, then a
new BSEE approval would be required at that time.
Comments Related to Proposed Sec.  250.428(c)(1)--Use of a Casing Shoe
Test
    Summary of comments: Some commenters suggested that BSEE add the
use of a casing shoe test to locate the top of cement.
     Response: BSEE disagrees with commenter. A casing shoe
test by itself does not confirm cement integrity behind the casing/
liner or verify the top of cement (TOC).
Comments Related to Proposed Sec.  250.428(c)(1)(iii)--Use of Tracers
    Summary of comments: Some commenters expressed concerns about the
proposed language to require logging of the tracers prior to drill out.
The commenters recommended removal of ``prior to drill out.'' The
commenters asserted that tracers are meant to be used when the losses
are more likely, and that operators should be able to find the TOC
through the use of bottom hole assembly (BHA) measurement while
drilling (MWD).
     Response: BSEE does not accept the commenters' suggested
removal of ``prior to drill out.'' The addition of tracers to this
section allows operators another option for determining if the cement
job is adequate. The commenters incorrectly assumed that BSEE is
requiring an additional logging run to confirm the location of the
tracers; however, BSEE expects that operators will still be able to
locate the TOC by logging tracers with the BHA.
Comments Related to Proposed Sec.  250.428(c)--Evaluation Logs
    Summary of comments: A commenter suggested that BSEE require a
cement evaluation log in complex, higher risk wells and for wells in
environmentally sensitive locations. The commenter asserted that
temperature and tracer logs will indicate the cement top, but will not
provide information on cement quality throughout the entire cement
column. The commenter also asserted that a cement evaluation log
provides substantially more information on cement placement and
quality. The commenter also suggested that if remedial cementing is
needed, a cement evaluation log should be run to verify the repair.
     Response: BSEE agrees with the commenter that a cement
evaluation log helps determine cement placement and the overall quality
of the cement job. However, BSEE disagrees with the commenter's
suggestion that a cement evaluation log is necessary for the specified
wells even when there is not an indication of an inadequate cement job.
BSEE requires other tests to help confirm well and cement integrity
(e.g., pressure integrity testing required in existing Sec.  250.427).
The purpose of paragraph (c) is to help determine whether remedial
actions are necessary when there is an indication of an inadequate
cement job, and BSEE's regulations offer the option to run cement
evaluation logs to determine the TOC. Furthermore, BSEE also has the
discretion to require additional logs if warranted on a case-by-case
basis.
Comments Related to Proposed Sec.  250.428(d)--Use of Flow Charts
    Summary of comments: A commenter recommended the addition of
language to allow the use of approved operator flow charts to determine
the extent and timeliness of the remedial actions in lieu of BSEE-
approved permits.
     Response: BSEE declines to expressly include a reference
in the regulations that would allow the use of operator flow charts for
remedial actions in lieu of a BSEE-approved permit. If a cement job is
deemed inadequate according to the criteria specified in the existing
regulations, then the operator must take remedial actions. BSEE does
not limit the information that is submitted within a permit application
for BSEE review and approval. An operator may submit flow charts in the
permit application outlining the
[[Page 21937]]
proposed remedial actions, if it so chooses. BSEE may consider approval
of such flow charts as part of the operator's remedial actions. But
flow charts will not replace permits in the approval process.
What are the diverter actuation and testing requirements? (Sec.
250.433)
    This section of the existing regulations describes the requirements
for diverter actuation, pressure testing, and vent line flow testing.
Summary of Proposed Revisions
    BSEE proposed to revise existing paragraph (b) to modify
requirements for subsequent diverter testing after the initial test, by
allowing partial activation of the diverter element and by not
requiring a flow test. BSEE proposed these changes to codify
longstanding BSEE policy, minimize the number of alternate procedure
requests submitted to BSEE, and help minimize the possibility of
accidental discharge of mud overboard during full flow testing.
Summary of Final Rule Revisions
    BSEE received and considered multiple comments regarding this
proposed provision, including a number in general support, and includes
the proposed language in the final rule without change.
Summary of Comments
Comments Related to Proposed Sec.  250.433--Opposition to Proposed
Changes
    Summary of comments: A commenter opposed the proposed changes
asserting that the proposed rule did not adequately define the proposed
reduced diverter system testing or demonstrate that the new test
regimen would provide a level of safety equivalent to the existing test
requirements.
     Response: BSEE disagrees with the commenter. The final
rule requirements will improve the existing regulation and will ensure
safety at least equivalent to the existing requirements. The revisions
will minimize the risk of hydrocarbons or mud inadvertently being
discharged overboard during subsequent testing while ensuring
functionality and integrity of the components by requiring the partial
activation. Furthermore, BSEE still requires actuation of the diverter
sealing element, diverter valves, and diverter control systems upon
installation, and a flow test of the vent lines as required in existing
Sec.  250.433.
What are the requirements for directional and inclination surveys?
(Sec.  250.461)
    This section of the existing regulations specifies operational
requirements for conducting surveys in vertical and directional wells.
Summary of Proposed Revisions
    BSEE proposed to revise paragraph (b) by extending the maximum
permitted survey intervals during angle-changing portions of
directional wells from 100 feet to 180 feet. This would account for the
majority of the pipe stand lengths in use and would address
technological developments that BSEE has accommodated through approvals
of alternative procedures under Sec.  250.141 since before the 2016
WCR.
Summary of Final Rule Revisions
    BSEE received a few comments in general support of the proposed
revisions to this section, and is including the proposed language in
the final rule without change.
What are the source control, containment, and collocated equipment
requirements? (Sec.  250.462)
    This section of the existing regulations outlines the requirements
for BSEE approval of the operator's source control and containment
capabilities, including a determination of the source control and
containment equipment capabilities, assurance of access to the
equipment, and ability to deploy Source Control and Containment
Equipment (SCCE). This section also includes maintenance, inspection,
and testing requirements for specified containment equipment.
Summary of Proposed Revisions
    In paragraph (b) of this section, BSEE proposed to clarify that the
SCCE to which operators need to have access is based on the
determinations regarding source control and containment capabilities
required in Sec.  250.462(a). BSEE also proposed to clarify that the
identified list of equipment represents examples of the types of SCCE
that may be determined appropriate in specific circumstances rather
than equipment that is universally required.
    BSEE proposed revisions to paragraph (e)(1)(ii) to replace the
phrase ``a BSEE approved verification organization'' with the phrase
``an independent third party.''
    BSEE also proposed revisions to paragraph (e)(3) to clarify that
subsea utility equipment utilized solely for containment operations
must be available for inspection at all times. BSEE proposed revising
paragraph (e)(4) to clarify that it is applicable only to collocated
equipment identified in the Regional Containment Demonstration (RCD) or
Well Containment Plan and not to all collocated equipment. BSEE
proposed revisions to both paragraphs (e)(3) and (e)(4) to help ensure
that the equipment described in those paragraphs is available for BSEE
inspection.
Summary of Final Rule Revisions
    BSEE received and considered multiple comments in support of and in
opposition to the proposed changes. BSEE is including the proposed
language in the final rule. BSEE is also including in this final rule
an administrative revision to paragraph (e)(2)(i) to reflect the
correct cross-reference to the Subpart H regulations. This change is
technical, non-substantive, and necessary due to the updated citations
from another recently published BSEE rulemaking, Final Rule: Oil and
Gas and Sulphur Operations on the Outer Continental Shelf--Oil and Gas
Production Safety Systems (83 FR 49216, September 28, 2018) which
updated the production safety systems requirements of Subpart H.
Summary of Comments
Comments Related to Proposed Sec.  250.462--SCCE Availability
    Summary of comments: Some commenters opposed the proposed revisions
to this section, asserting that the proposed changes would weaken the
requirements to have SCCE available, and could significantly increase
the time involved to control a major oil spill.
     Response: BSEE disagrees with these comments. The
dedicated equipment at issue is used solely for containment and must be
available for inspection by BSEE at all times, and the location of this
collocated equipment will be provided to BSEE. The equipment required
for the specific well location is determined based on the operator's
RCD or Well Containment Plan (WCP). As discussed in the proposed rule,
the majority of SCCE, such as capping stacks and top hats, has no other
commercial purpose and is used solely for containment operations. This
unique containment equipment is maintained and readily available for
inspection by BSEE at any time and would be available for immediate use
if a well control event occurs. Other equipment listed for source
control that has broader commercial purposes, such as ROVs and vessels,
are also required to be readily available. The clarifying revisions to
these regulatory provisions
[[Page 21938]]
do not weaken these key safety elements.
Subpart E--Oil and Gas Well-Completion Operations
Tubing and Wellhead Equipment (Sec.  250.518)
    This section of the existing regulations outlines the completion
operational requirements for tubing, wellhead equipment, subsurface
safety equipment, and packers and bridge plugs.
Summary of Proposed Revisions
    BSEE proposed revisions to paragraph (e)(1) to clarify that only
permanently installed packers or bridge plugs, which are qualified as
mechanical barriers, are required to comply with ANSI/API Spec. 11D1.
BSEE proposed these changes to ensure that the packers and bridge plugs
utilized as required mechanical barriers are ANSI/API Spec. 11D1
compliant, while eliminating the requirement that packers and plugs
used for other, non-critical, purposes meet the standard.
Summary of Final Rule Revisions
    BSEE received and considered comments on the proposed revisions
and, based on that review, BSEE is revising paragraph (e)(1) in this
final rule to further clarify that the ``uppermost'' permanently
installed packer and ``all permanently installed'' bridge plugs, which
qualify as a mechanical barrier, must comply with ANSI/API Spec. 11D1.
These revisions provide further clarity about what packers and bridge
plugs are covered by this section and codify BSEE policy that has been
in place since the implementation of the 2016 WCR. Also based on BSEE's
consideration of comments received on the proposed rule, BSEE is adding
in the final rule a new paragraph (g) to require operators to ``have
two independent barriers, one being mechanical, in the exposed center
wellbore prior to removing the tree and/or well control equipment.''
Summary of Comments
Comments Related to Proposed Sec.  250.518--Barrier clarification
    Summary of comments: Multiple commenters supported the proposed
clarification of this section. However, one commenter expressed
concerns that there would b[iecy] confusion about the use of mechanical
barriers designed for other operations during well completion or
workovers. The commenter asserted that identification of the proper
barriers should b[iecy] stated in the well control plan to eliminate
any potential confusion.
     Response: BSEE agrees with the commenters who expressed
general support for the proposed revisions. BSEE also agrees to some
extent with one commenter's concerns about potential confusion
regarding the mechanical barriers language in the proposed changes to
Sec.  250.518, Tubing and Wellhead Equipment. The required mechanical
barriers are specific to the associated operation (workover,
completion, or decommissioning) and the regulatory text should be clear
and consistent with similar requirements. Based on the consideration of
this comment, BSEE revised the language in final Sec.  250.518 to be
consistent with the language in final Sec.  250.619, pertaining to
workover operations. During comment review, BSEE determined that it
should add a new final paragraph (g) that mimics the language proposed
for Sec.  250.619, Tubing and wellhead equipment, to address the
circumstance of well control equipment being unlatched during initial
completion operations. This language is consistent with how BSEE has
implemented this regulation, and BSEE is making this addition to
further clarify the intent to have two barriers in place prior to
removing the tree or well control equipment. This addition reflects
current BSEE requirements and operational practice. However, BSEE
disagrees with the commenter's suggestion that the barriers should be
identified in the well control plan, as these mechanical barriers are
identified within the well schematics submitted in BSEE permit
applications.
What are the requirements for casing pressure management? (Sec.
250.519)
    This section of the existing regulations requires casing pressure
management and adherence to specified industry standards and the
requirements of this subpart.
Summary of Proposed Revisions
    BSEE proposed minimal revisions to this section in order to update
incorrect citations. These revisions are administrative in nature and
ensure that the appropriate citations are correctly cross referenced.
Summary of Final Rule Revisions
    BSEE received a few comments in general support of the proposed
revisions to this section and is including the proposed language in the
final rule without change.
How do I manage the thermal effects caused by initial production on a
newly completed or recompleted well? (Sec.  250.522)
    This section of the existing regulations specifies operational
requirements regarding thermal casing pressure during initial startup.
Summary of Proposed Revisions
    BSEE proposed minimal revisions to this section to update incorrect
citations. These revisions are administrative in nature and ensure that
the appropriate citations are correctly cross referenced.
Summary of Final Rule Revisions
    BSEE received a few comments in general support of the proposed
revisions to this section and is including the proposed language in the
final rule without change.
When am I required to take action from my casing diagnostic test?
(Sec.  250.525)
    This section of the existing regulations specifies certain
operational conditions that, when identified in the casing diagnostic
tests, would require an operator to take actions.
Summary of Proposed Revisions
    BSEE proposed minimal revisions to paragraph (d) of this section to
update incorrect citations. These revisions are administrative in
nature and ensure that the appropriate citations are correctly cross
referenced.
Summary of Final Rule Revisions
    BSEE received a few comments in general support of the proposed
revisions to this section and is including the proposed language in the
final rule without change.
What do I submit if my casing diagnostic test requires action? (Sec.
250.526)
    This section of the existing regulations specifies the required
submittals in the event of a casing diagnostic test that requires
action.
Summary of Proposed Revisions
    BSEE proposed minimal revisions to this section to update incorrect
citations. These revisions are administrative in nature and ensure that
the appropriate citations are correctly cross referenced.
Summary of Final Rule Revisions
    BSEE received a few comments in general support of the proposed
revisions to this section and is including the proposed language in the
final rule without change.
[[Page 21939]]
What if my casing pressure request is denied? (Sec.  250.530)
    This section of the existing regulations outlines the steps an
operator must take when BSEE denies its casing pressure request.
Summary of Proposed Revisions:
    BSEE proposed minimal revisions to paragraph (b) of this section to
update incorrect citations. These revisions are administrative in
nature and ensure that the appropriate citations are correctly cross
referenced.
Summary of Final Rule Revisions
    BSEE received a few comments in general support of the proposed
revisions to this section and is including the proposed language in the
final rule without change.
Subpart F--Oil and Gas Well-Workover Operations
Definitions (Sec.  250.601)
    This section in the existing regulations lists the definitions
specific to workover operations.
Summary of Proposed Revisions
    BSEE revises the definition of ``routine operations'' in this
section to make it consistent with the definition of routine operations
in Sec.  250.105 by adding paragraph (m) ``Acid treatments.'' The 2016
WCR did not address this provision, however based on BSEE experience,
this revision is necessary to help minimize confusion about the
definition of routine operations.
Summary of Final Rule Revisions
    BSEE received a few comments in general support of the proposed
revisions to this section and is including the proposed language in the
final rule without change.
Coiled Tubing and Snubbing Operations (Sec.  250.616)
    This section of the existing regulations specifies the minimum
requirements for coiled tubing and snubbing equipment as well as
operational requirements for conducting workover operations with the
production tree in place.
Summary of Proposed Revisions
    BSEE proposed to remove and reserve this section, and to move the
content of this section to proposed Sec.  250.750, with minor revisions
discussed in connection with that provision. BSEE proposed these
revisions to help eliminate inconsistencies between similar
requirements throughout different subparts of BSEE's regulations (in 30
CFR part 250) by consolidating those requirements in Subpart G, which
is applicable to drilling, completions, workovers, and decommissioning
operations.
Summary of Final Rule Revisions
    BSEE received a few comments in general support of the proposed
revisions to this section and is including the proposed removal and
reservation in the final rule without change.
Tubing and Wellhead Equipment (Sec.  250.619)
    This section of the existing regulations outlines the workover
operational requirements for tubing, wellhead equipment, subsurface
safety equipment, and packers and bridge plugs.
Summary of Proposed Revisions
    BSEE proposed to revise paragraph (e)(1) by clarifying that only
permanently installed packers and bridge plugs that are qualified as
mechanical barriers are required to comply with ANSI/API Spec. 11D1.
This revision would codify BSEE's policy developed since promulgation
of the 2016 WCR, to ensure that the required mechanical barriers in a
well are held to a higher standard than other common packers or bridge
plugs used for various well-specific conditions and completions design.
Furthermore, BSEE is aware that certain packers and bridge plugs cannot
meet the specifications of ANSI/API Spec. 11D1.
    BSEE also proposed to require operators to have two independent
barriers, including one mechanical barrier, in the exposed center
wellbore prior to removing the tree or well control equipment. This
addition would codify existing BSEE policy and make the workover
requirements in Subpart F regarding mechanical barriers similar to
those already found in existing Sec.  250.720(a).
Summary of Final Rule Revisions
    BSEE received and considered comments on the proposed revisions
and, based on that review, BSEE is revising paragraph (e)(1) in this
final rule to further clarify that both the ``uppermost'' permanently
installed packer and ``all permanently installed'' bridge plugs that
qualify as a mechanical barrier must comply with ANSI/API Spec. 11D1.
These revisions provide further clarity about what packers and bridge
plugs are covered by this section and codify BSEE policy that has been
in place since the implementation of the 2016 WCR. BSEE is also moving
the phrase ``You must have two independent barriers, one being
mechanical, in the exposed center wellbore prior to removing the tree
and/or well control equipment'' from proposed paragraph (e)(1) to new
final paragraph (g). This administrative change will help clarify the
requirements in paragraph (e)(1) and confirm that paragraph (g) is a
stand-alone requirement.
Summary of Comments
Comments Related to Proposed Sec.  250.619--Barrier Clarification
    Summary of comments: Multiple commenters supported the proposed
clarification of this section for the reasons explained in the proposed
rule. However, one commenter expressed concerns that there would
b[iecy] confusion about the use of mechanical barriers designed for
other operations during well completion or workovers. The commenter
asserted that identification of the proper barriers should b[iecy]
included in the well control plan to eliminate any potential confusion.
     Response: BSEE agrees with the commenters' expression of
general support for the proposed revisions. BSEE also agrees to some
extent with one commenter's concerns about potential confusion
regarding the mechanical barriers language in the proposed changes to
Sec.  250.518. The required mechanical barriers are specific to the
associated operation (workover, completion, or decommissioning) and the
regulatory text should be clear and consistent with similar
requirements. Based on the consideration of this comment BSEE revised
the language in final Sec.  250.518 to be consistent with the language
in proposed and final Sec.  250.619, and modified the proposed
organization of Sec.  250.619 for clarity and consistency. This
language is consistent with how BSEE has implemented this regulation,
and BSEE is making this addition to further clarify the intent to have
two barriers in place prior to removing the tree or well control
equipment. This addition reflects current BSEE requirements and
operational practice. However, BSEE disagrees with the commenter's
suggestion that the barriers should be identified in the well control
plan as these mechanical barriers are identified within the well
schematics submitted in BSEE permit applications.
[[Page 21940]]
Subpart G--Well Operations and Equipment
What rig unit movements must I report? (Sec.  250.712)
    This section of the existing regulations specifies the requirements
for reporting to BSEE of rig unit movement on and off location, and
specifies the required content of the reporting.
Summary of Proposed Revisions
    BSEE proposed to revise this section by adding new paragraphs (g)
and (h). BSEE proposed to add paragraph (g) to clarify that reporting
is not necessary for rig movements to and from the safe zone during
permitted operations. BSEE proposed to add paragraph (h) to clarify
that, if a rig unit is already on a well, BSEE would not require a
notification for any additional rig unit movements on that well.
Summary of Final Rule Revisions
    BSEE received a comment in general support of the proposed
revisions to this section and is including the proposed language in the
final rule without change.
When and how must I secure a well? (Sec.  250.720)
    This section of the existing regulations outlines the requirements
for securing a well whenever operations are interrupted (e.g.,
evacuation of the rig crew, inability to keep the rig on location, and
repair to major rig or well-control equipment).
Summary of Proposed Revisions
    BSEE proposed to revise paragraph (a)(1) to add an impending
National Weather Service-named tropical storm or hurricane to the list
of example events that would interrupt operations and require
notification. Furthermore, BSEE also proposed to add new paragraph
(a)(3) to include provisions for testing the applicable BOP or LMRP
upon relatch according to Sec.  250.734 paragraphs (b)(2) or (b)(3),
respectively, and obtaining BSEE approval before resuming operations.
BSEE proposed these revisions to codify the BSEE storm policy reflected
in longstanding guidance and to provide clarity for testing
requirements when an operator has returned to the well location and
relatched the BOP or LMRP. BSEE also proposed to add new paragraph (d)
requiring equipment and capabilities for well intervention and
specifying that equipment used solely for well intervention must be
readily available for use, maintained in accordance with applicable OEM
recommendations, and available for inspection by BSEE upon request.
BSEE proposed this addition to ensure that when intervention is
necessary on a well, the applicable tools (such as the tree interface
tools) are available and ready for their intended use.
Summary of Final Rule Revisions
    BSEE received and considered comments on the proposed revisions and
includes the proposed language in the final rule. Furthermore, based on
comments received, BSEE is also adding language to paragraph
(a)(3)(iii) to require that the operator, upon relatch of a BOP or
LMRP, ``submit a revised permit with a written statement from an
independent third party certifying that the previous certification in
Sec.  250.731(c) remains valid. . . .'' This revision will provide BSEE
with additional assurance that the related equipment is fit for service
upon relatch and clarifies the necessary submittal and associated
information required in order to receive District Manager approval.
This addition reflects current BSEE practice and is the same
information operators must submit with the required BSEE permits. This
provides assurance that the specified BOP certifications are still
valid and provides consistent documentation of recertification.
Corresponding edits are also made to Sec. Sec.  250.734 and 250.738.
    BSEE is also revising paragraph (d) to clarify that operators need
only meet the requirements from the proposed rule for subsea completed
wells with a tree installed that have a shut-in tubing pressure that is
greater than the hydrostatic pressure of the water column, or subsea
wells that are not capable of having the annulus monitored. This
revision will help ensure that operators have available the appropriate
intervention tools for wells with higher risk potential, and will
reduce the unnecessary burden of applying this new requirement to lower
risk wells.
Summary of Comments
Comments Related to Proposed Sec.  250.720(a)--Retesting the Deadman
System
    Summary of comments: Some commenters expressed concerns with the
requirement in Sec.  250.734(b), incorporated here, to re-test the
deadman systems when they have not been repaired or affected by the
suspension. The commenters recommend not to test the deadman upon
relatch. The commenters asserted that, while it is important to verify
that the system is functional, in cases where the system has not been
modified, the previous test should be sufficient.
     Response: BSEE disagrees with the comments. When the
functional system is disconnected, whether it is modified or not, it is
important to ensure that the emergency systems are completely
functional upon reconnection of that system. The deadman system
functionality is verified by testing that system, as required by this
regulation.
Comments Related to Proposed Sec. Sec.  250.720(a)(3)(iii), 734, and
738--Independent Third Party Re-Verifications
    Summary of comments: A commenter recommended that BSEE require a
report from an independent third party if the events listed in Sec.
250.720(a)(1) would invalidate a verification submitted pursuant to
Sec. Sec.  250.731(d) and 250.732(c).
     Response: BSEE agrees with the commenter and added a
requirement for submitting a revised permit with a written statement
from an independent third party certifying that the previous
certification under Sec.  250.731(c) remains valid. BSEE also made
corresponding edits to similar requirements in Sec. Sec.  250.734 and
250.738. These revisions help ensure that the BOP is still fit for
service at the same location following relatch after disconnect.
Comments Related to Proposed Sec.  250.720(d)--Intervention Equipment
Requirements
    Summary of comments: Multiple commenters expressed concerns with
the proposed requirements related to the availability of intervention
equipment. Commenters asserted that the proposed requirements were
``overly prescriptive'' and would place undue financial burden on
operators. The commenters proposed replacing Sec.  250.720(d) with
language that requires operators to prepare and have available a well
intervention readiness plan based on a risk analysis, and that only
requires the equipment identified as necessary through that plan to be
available for use and BSEE inspection. Additionally, one of the
commenters recommended adding a definition for ``readily available.''
     Response: BSEE agrees with the commenter's recommendation
that the operator should determine the required intervention equipment
based on an analysis of the risks associated with a well. Accordingly,
BSEE revised proposed Sec.  250.720(d) to limit the intervention
equipment requirements to subsea completed wells with a tree installed,
that have a shut-in tubing pressure that is greater than the
[[Page 21941]]
hydrostatic pressure of the water column, or that are not capable of
having the annulus monitored. BSEE wants to ensure that appropriate
intervention equipment is available and properly maintained for higher
risk wells, but not to impose unnecessary burdens through application
of these new requirements to low risk wells. BSEE disagrees with the
recommendation to define ``readily available'' because it would be
impractical to establish uniform requirements for the deployment
timeframe of the intervention equipment due to the variability of
equipment and logistics for each well location. Operators should not
rely on SCCE for routine intervention operations where intervention
equipment is required.
What are the requirements for prolonged operations in a well? (Sec.
250.722)
    This section of the existing regulations specifies actions
necessary to determine well integrity for operations continuing longer
than 30 days from a previous casing or liner test. If well integrity
has deteriorated to a level below minimum safety factors, this section
requires repairs or installation of additional casing and subsequent
pressure testing, as approved by the District Manager.
Summary of Proposed Revisions
    BSEE proposed to revise the prolonged operations well casing
reporting requirements in paragraph (a)(2) of this section to clarify
that BSEE does not require District Manager approval to resume
operations if an operator conducts a successful pressure test as
already approved in the applicable permit. BSEE also proposed to
clarify that operators must document the successful pressure test
results in the Well Activity Report (WAR), and also proposed minor
revisions to this paragraph to provide that the calculations are used
to ``indicate'' not ``show'' that the well's integrity is above the
minimum safety factors.
Summary of Final Rule Revisions
    BSEE received a few comments in general support of the proposed
revisions to this section and is including the proposed language in the
final rule without change.
What additional safety measures must I take when I conduct operations
on a platform that has producing wells or has other hydrocarbon flow?
(Sec.  250.723)
    This section of the existing regulations requires additional safety
measures (e.g., installation of an emergency shutdown station for the
production system, and shutting in producing wells for certain rig
movements) for operations on a platform that has a producing well or
other hydrocarbon flow.
Summary of Proposed Revisions
    BSEE proposed to revise this section by removing the phrase ``or
lift boat.'' This would primarily impact paragraph (c)(3), which
requires a shut-in of all producible wells located in the affected
wellbay when a lift boat moves within 500 feet of the platform until
the lift boat is in place, secured, and ready to begin operations.
Summary of Final Rule Revisions
    BSEE received and considered comments on the proposed revisions and
includes the proposed language in the final rule without change. BSEE
received comments in general support of and opposition to the proposed
changes in addition to the following specific, substantive comments.
Summary of Comments
Comments Related to Proposed Sec.  250.723--Lift Boat Activities
    Summary of comments: A commenter recommended requiring lift boats
to approach platforms from the opposite side of subsea pipeline
placement, which the commenter understands is the current industry-
accepted practice. The commenter also asserted that the specific
regulations should take into consideration the type of work the lift
boat is performing to help minimize unnecessary shut-ins.
     Response: BSEE agrees that operators should consider
subsea infrastructure when positioning any type of bottom supported
vessels. BSEE is not including the commenter's recommendations in the
regulations due to the diverse equipment, multiple possible subsea
configurations, and varying operational situations presented by
impacted operations. They are likewise outside the scope of this
rulemaking. Removal of lift boats from this provision should address
the commenter's concerns regarding unnecessary shut-ins.
Comments Related to Proposed Sec.  250.723--Lift Boat Size
    Summary of comments: Multiple commenters expressed concerns with
the removal of lift boats from this section. However, the commenters
also suggested that, if the current regulations are too onerous, the
shut-in requirement should only apply to lift boats that are above a
certain size or class, or when lift boats approach during more
challenging weather or environmental conditions that could make mooring
more difficult.
     Response: BSEE generally agrees with the commenter that
different lift boat sizes may present different risks; however, BSEE is
not making any changes to this section of the proposed rule. BSEE
determined that the vast majority of lift boats used on the OCS are
relatively small compared to the size of a MODU and would not typically
be expected to have the same operational impacts and potential risks as
a MODU. BSEE is considering the effects of the size of lift boats for
potential future rulemakings, and may gather additional information and
provide guidance on a case-by-case basis for any lift boats that could
reasonably be expected to have an operational impact comparable to a
MODU.
What are the real-time monitoring requirements? (Sec.  250.724)
    This section of the existing regulations requires operators to
gather and monitor real-time well data when conducting operations with
a subsea BOP or with a surface BOP on a floating facility, or when
operating in an HPHT environment, and to develop a real time monitoring
(RTM) plan detailing how the operator will develop and utilize RTM.
Summary of Proposed Revisions
    BSEE proposed to revise this section by removing many of the
prescriptive real-time monitoring requirements and moving towards a
more performance-based approach. BSEE proposed to remove existing
paragraph (b) with its associated prescriptive requirements, and to re-
designate existing paragraph (c) as paragraph (b), with minor revisions
to shift certain prescriptive elements to be more performance-based.
BSEE also proposed to continue requiring the items in existing
paragraph (c) in an RTM plan.
Summary of Final Rule Revisions
    BSEE received and considered comments on this section, and is
revising proposed paragraph (a)(2) to clarify that it relates to
monitoring of ``the well's active fluid circulating system.'' This
revision would clarify the intent of the 2016 WCR RTM requirements and
ensure that the system used for circulation of the well fluid is
properly monitored, while removing any implication that RTM is required
for fluids not in active circulation. BSEE is also adding back in
clarifying language similar to the first sentence in existing paragraph
(b) (with certain prescriptive elements removed), as follows: ``(b) You
must transmit these data as they are
[[Page 21942]]
gathered, barring unforeseeable or unpreventable interruptions in
transmission, and have the capability to monitor the data, using
qualified personnel in accordance with a real-time monitoring plan, as
provided in paragraph (c) of this section.'' BSEE is also re-
designating proposed paragraph (b) as final paragraph (c) with no other
changes to the remainder of the proposed section. These revisions
address comments received about clarifying who will be monitoring the
data by making that a matter to be addressed in the RTM plan. These
revisions do not alter the requirements of the substantive RTM
operational capabilities and what is addressed within the company-
specific RTM plan.
Summary of Comments
Comments Related to Proposed Sec.  250.724--Performance-Based Real Time
Monitoring Plan
    Summary of comments: Some of the commenters support the transition
from prescriptive requirements to a performance-based Real Time
Monitoring (RTM) plan. The commenters assert that a performance-based
approach will allow them to develop plans that are tailored to the
operating conditions, risk profiles, and operator policies and
procedures for specific wells.
     Response: BSEE agrees in part with the commenters'
assertion that a performance-based approach has the potential to align
an operator's RTM plan more effectively with a specific well's
operating condition and risk profile. BSEE is establishing an initial
framework for RTM and may supplement the regulations with additional
operational provisions as more experience and research becomes
available.
Comments Related to Proposed Sec.  250.724--Scope and Applicability of
Real Time Monitoring Plan
    Summary of comments: Some of the commenters support limiting the
scope of RTM plans to drilling operations only and providing operators
with discretion regarding whether or not to include workover,
completion, and decommissioning activities in their RTM plans. On the
other hand, multiple other commenters assert that RTM should apply to
all operations.
     Response: BSEE currently requires RTM for all
operations conducted with a subsea BOP, surface BOP on a floating
facility, and BOPs used in HPHT environments. BSEE is not making any
changes to this requirement. As explained in the regulations, the RTM
requirements are located in Subpart G, which covers operations and
equipment associated with drilling, completion, workover, and
decommissioning activities. BSEE agrees with the commenters that RTM
should apply to drilling, completion, workover, and decommissioning
operations because all the operations have similar potential hazards
and risks, and are also usually conducted utilizing the same types of
rigs and equipment.
    Summary of comments: Some of the commenters request that BSEE apply
RTM only to the operations covered in API Standard 53, reduce the data
retention period for RTM data from 2 years to 90 days, and clarify that
an RTM monitoring center located onshore is not required.
     Response: BSEE disagrees with the comments
regarding restricting the applicability of RTM to the scope of API
Standard 53 and reducing the data retention timeframes. BSEE believes
that it is important for the RTM requirements to apply to all
operations conducted with a subsea BOP, surface BOP on a floating
facility, and BOPs used in HPHT environments because these types of
operations usually have the highest potential for hazards and increased
risks. The regulations allow the operator to tailor its approach toward
monitoring the specific operational components covered under paragraph
(a) in the context of the specific rig and operation through the RTM
plan. BSEE is also establishing an initial framework for RTM and may
supplement the regulations to include a reduced time period for data
retention as more experience and research becomes available. For now,
BSEE believes that the longer data retention window is important to
ensure the availability of needed data.
    BSEE agrees with the commenters that an onshore RTM monitoring
center is not required. With currently available technology, operators
are capable of using RTM remotely on computers and tablets using web
based applications. This allows for subject matter experts to utilize
the data anywhere and at any time as necessary, as detailed in the
company's RTM plan. BSEE requires the operator to identify in the RTM
plan how the RTM data will be transmitted and monitored, requires the
rig personnel and monitoring personnel to be separate individuals, and
requires certain communication capabilities among personnel, but does
not prescriptively dictate the establishment of an onshore monitoring
center.
Comments Related to Proposed Sec.  250.724--Weakening Real Time
Monitoring Plan Requirements
    Summary of comments: Many of the commenters oppose BSEE's proposed
elimination of prescriptive requirements for RTM plans and adoption of
a performance-based approach. The commenters also assert that the
proposed rule: Lacks meaningful standardization of RTM requirements;
does not provide sufficient oversight if operators are not required to
transmit data onshore in real time for monitoring by qualified
personnel; and should not limit the requirements to drilling
operations. As the basis for opposing the removal of prescriptive
requirements for RTM plans, many of the commenters cite the findings
and recommendations of the post-Deepwater Horizon investigations and
reports as well as the rationales that support the RTM requirements
found in the 2016 WCR.
     Response: BSEE is establishing an initial
framework for RTM and may supplement the regulations with additional
operational provisions as more experience and research becomes
available. Even though the 2016 RTM requirements have a compliance date
of April 29, 2019, a majority of the operators already utilize many of
the RTM capabilities within their current operations. BSEE was able,
through increased interaction with these companies, to better
understand the logistical and operational considerations for
implementation of the RTM requirements. The 2016 WCR's RTM requirements
were themselves largely performance-based, relying primarily on the
operator's development of an RTM plan tailored to its operations but
built off of core principles. The revisions implemented here do not
reflect a sea change in philosophy, but rather merely remove certain
unnecessarily prescriptive elements (e.g., specifying that the RTM data
must be transmitted onshore, certain communications protocols, and that
monitoring personnel must be onshore). Notwithstanding the performance-
based nature of these revisions, BSEE agrees that it is important to
retain specific requirements concerning data transmission and has
revised the proposed RTM requirements to preserve content similar to
the first sentence of existing paragraph (b), due to confusion from the
commenters about who is allowed to monitor the data. BSEE bases this
revision on comments received seeking clarification regarding who must
monitor the data, but does not require changes to RTM operations or the
contents of the company-specific
[[Page 21943]]
RTM plan. This revision clarifies who must monitor the RTM data as
described in the RTM plan. In accordance with paragraphs (c)(5) and
(6), BSEE requires the rig personnel and monitoring personnel to be
separate individuals. Additionally, the updated regulations still
establish requirements for RTM processes and systems.
Comments Related to Proposed Sec.  250.724--RTM Verification
    Summary of comments: Multiple commenters recommend that BSEE
periodically verify that operators are implementing their RTM plans via
audits conducted by the agency, a BAVO, or an independent third-party.
The commenters also recommend that BSEE clarify the process by which
the implementation of RTM requirements will be verified and enforced.
     Response: This regulation requires that
operators develop and implement RTM plans, and specifically requires
that those plans be made available to BSEE upon request. If BSEE has
any concerns with an operator's RTM operations, then BSEE may undertake
inspections and enforcement actions to ensure compliance with the
regulations. BSEE has additional options such as routine onsite
inspections or verifications through the permitting process to ensure
that RTM plans are implemented in compliance with the regulations.
What are the general requirements for BOP systems and system
components? (Sec.  250.730)
    This section of the existing regulations includes requirements for
the design, fabrication, installation, maintenance, inspection, repair,
testing, and use of BOP systems and components. This section also
requires compliance with certain provisions of API Standard 53 and
several related industry standards, and requires operators to use
failure reporting procedures.
Summary of Proposed Revisions
    BSEE proposed to revise paragraph (a) by removing ``excluding
casing shear'' and replacing ``at all times'' with ``in the event of
flow due to a kick.'' BSEE requires the BOP system as a whole to be
capable of closing and sealing the wellbore. BSEE also proposed to
clarify that the BOP system must be able to close and seal the wellbore
in the event of flow due to a kick. BSEE knows there are mechanical and
operational design limits of equipment, and expects operators to ensure
ram closure time and sealing integrity to avoid exceeding those
operational and mechanical limits.
    BSEE proposed to amend paragraph (b) to clarify that BSEE expects
the use of ``applicable'' OEM recommendations for the design,
fabrication, maintenance, and repair of BOP systems, as well as
personnel training in their use. The proposed revision to include
``applicable'' is necessary because some OEMs may not have specific
recommendations for every item required by this paragraph.
    BSEE also proposed to revise the failure reporting requirements in
paragraph (c) to codify BSEE guidance and current practice. BSEE
proposed to remove the failure reporting references to ANSI/API Specs
6A and 16A because the failure reporting process outlined in those
standards is redundant to API Standard 53 and the remaining
requirements of this section. Proposed revisions to this paragraph also
included clarification on submitting failure data and reports to BSEE,
unless BSEE has designated a third party to collect the data and
reports, and ensuring that an investigation and failure analysis are
started within 120 days. BSEE reevaluated the timeframes set forth in
the 2016 WCR for performing the investigation and failure analysis and
determined that certain operations would preclude operators from
meeting the original timeframes. Accordingly, BSEE proposed to require
that operators start their investigation and failure analysis within
120 days of the failure. BSEE then proposed a 120-day timeframe for the
operator to complete the investigation and failure analysis once they
have started the process.
    BSEE proposed to revise paragraph (c)(4) to explain that BSEE may
designate a third party to collect failure data and reports on behalf
of BSEE, and if it does so, operators must send the failure data and
reports to the designated third party.
    BSEE also proposed to revise paragraph (d) by removing the
reference to a document incorrectly incorporated by reference, and
incorporating the correct document. The regulations promulgated
pursuant to the 2016 WCR require that BOP stacks be manufactured
pursuant to a quality management system certified by an entity that
meets the requirements of ISO 17011. The reference to the ISO 17011
standard in the 2016 WCR is incorrect, and BSEE proposed to correct the
error by incorporating the ISO/IEC 17021-1 standard.
Summary of Final Rule Revisions
    BSEE received and considered comments on the proposed revisions,
and includes in the final rule most of the proposed language without
change, except for the following revisions to paragraph (c). BSEE is
revising proposed paragraph (c) by replacing the references to ``BSEE''
with ``the Chief, Office of Offshore Regulatory Programs (OORP)'' for
purposes of directing where to send submittals, and adding the address
for the Chief of OORP in paragraph (c)(4). These revisions clarify to
whom and where to send failure reporting submittals within BSEE, unless
BSEE designates a third party to receive that information. Based on
comments received, BSEE is also clarifying how to request an extension
to the failure analysis timeframe. BSEE is adding to paragraph (c)(2) a
requirement that, if an operator cannot complete the investigation and
analysis within the allotted time, they must submit a request for an
extension of time detailing how the investigation and analysis will be
completed. The request for an extension of time must be submitted for
approval to BSEE through the Chief of OORP.
Summary of Comments
Comments Related to Proposed Sec.  250.730--What Are the General
Requirements for BOP Systems and System Components?
Casing Shear Ram Requirements
    Summary of comments: BSEE received a comment regarding the proposed
changes to Sec.  250.730(a) removing the phrase ``excluding casing
shear'' from requirements for the BOP. The commenter expressed concern
that BSEE's justification refers to the fact that BSEE ``expects
operators to ensure ram closure time and sealing integrity before
exceeding those operational and mechanical limits.'' The commenter
asserted that BSEE should clearly define and state these expectations
in the regulations. The commenter also asserted that BSEE should
confirm all relevant specifications through their permitting process,
inspection program, and performance testing requirements, asserting
that [Acy][Rcy][Iukcy] Standard 53 and [Acy][Rcy][Iukcy] Spec 16D
include details about the accumulator system that enable BSEE to
confirm compliance.
     Response: BSEE disagrees with the comment. The
requirements in this section ensure that operators properly design,
install, maintain, inspect, test, and operate each BOP component and
the entire BOP system. The requirements of this section apply to the
entire BOP system, including the casing
[[Page 21944]]
shear. BSEE requires the BOP system as a whole to be capable of closing
and sealing the wellbore before exceeding mechanical or operational
limits of the equipment. BSEE reviews compliance with the incorporated
documents through the permit and inspection process.
Comments Related to Proposed Sec.  250.730(c)--Failure Reporting
Requirements
    Summary of comments: A commenter recognized BSEE's efforts related
to the reporting, analysis, and use of failure data. However, the
commenter was concerned that the proposed changes to failure reporting
do not provide a clear definition of [acy] reportable failure.
     Response: BSEE disagrees that the definition of
failure provided in Sec.  250.730(c)(1) is unclear. The definition
aligns with the definition used by the Blowout Preventer Reliability
Joint Industry Project (JIP), a joint effort of the International
Association of Drilling Contractors (IADC) and the International
Association of Oil and Gas Producers (IOGP). This definition is
generally used and understood by the industry and adopted in the
SafeOCS implementing guidance, which was informed by input from the
JIP.
Comments Related to Proposed Sec.  250.730(c)--Timing of Failure
Investigations
    Summary of comments: Multiple commenters expressed concern
regarding the timing requirements related to failure investigations.
One commenter recognized that BSEE did propose to add additional time
for the investigation, but asserted that this did not address potential
extenuating circumstances (operational or investigation related) that
may prevent the operator from completing an investigation within 120
days. Therefore, the commenter requested that BSEE include a provision
in the final rule to address investigations that cannot be completed
within the allotted time. The commenter proposed that the provision
require operators to provide a progress report, reasons regarding why
the investigation was not completed, and a defined period for the
extension.
     Response: BSEE disagrees with including a
provision that would allow operators a blanket extension of the 120
days to complete the failure analysis. The final rule provides adequate
time for an operator to initiate and complete a failure analysis. BSEE
does, however, acknowledge that there may be extenuating circumstances
that prevent an operator from meeting these timelines. Accordingly, the
final rule provides that the operator may request an extension to the
failure analysis timeframes by submitting a request to the Chief, OORP
and, if appropriate, BSEE may approve an extension. The nature of
certain operational failures--such as systematic failures, stack pulls,
and lower marine riser pulls--may warrant additional case-by-case
consideration, as it is reasonable to expect the related analyses would
require more time than allowed in the rule. In 2017, only 1.5% of the
reported failure notifications resulted in an investigation and failure
analysis that required more than 120 days to complete. BSEE extended
the timeframe in the final rule to reduce its own administrative burden
for those cases where extra time could enable the timely resolution and
completion of an investigation and analysis report. For those rare
cases requiring more time, BSEE believes that providing for an
extension request is appropriate and that the request may reasonably be
expected to include the items recommended by the commenter.
    Summary of comments: A commenter stressed that the failure
investigation and submittal of the reports to BSEE should occur as soon
as practicable, preferably immediately after the failure. The commenter
asserted that, for conducting a failure investigation and analysis, it
makes more sense to provide a required time ``from the time equipment
first becomes available for testing'' and not from the time of the
incident. In addition, the commenter asserted that, in addition to an
option for operators to request an extension, there should be a
provision for BSEE to require an accelerated investigation, if
warranted by the circumstances. The commenter also suggested that BSEE
should not tie the failure analysis to continuing well operations,
asserting that continuing well operations should depend on the
replacement of the failed equipment with properly functioning
equipment.
     Response: BSEE agrees that an investigation and
failure analysis should occur as soon as practicable after a failure.
For subsea BOP operations, equipment is not readily available for
investigation until it is returned to the surface. If BSEE were to tie
the requirement to begin the investigation and failure analysis to the
time the equipment becomes available for testing, rather than the time
of the incident, it could result in delays in commencing the
investigation. BSEE believes that the new timeframes provide ample time
for commencing the investigation without leaving the timing open and
indefinite.
    BSEE disagrees that a provision is needed for BSEE to require
accelerated investigations. BSEE has determined that the timeframes
required by the final rule are reasonable for conducting timely and
thorough investigations, given that they will generally involve
multiple parties and complex, large equipment.
    BSEE disagrees that the continuation of well operations should
always require the replacement or repair of failed equipment. BSEE
regulations require redundant components for well control. Thus, in
some cases, well operations may continue following an equipment
component failure.
    Summary of comments: A commenter asserted that allowing the same
amount of time to initiate the failure investigation as to perform and
complete the investigation does not seem appropriate. The commenter
asserted that an operator should start the investigation within 30
days, and then complete the investigation within 120 days of
commencement. The commenter also suggested that if the operator cannot
complete the report within the timeframe allotted, the operator should
submit monthly progress reports to show progress towards a solution.
Another commenter observed that the proposed changes would essentially
double the time permitted for failure investigation, thereby delaying
completion of the investigation by four months. This commenter asserted
that delaying a failure investigation does not make sense because the
purpose of this requirement is to inform BSEE and the manufacturer of
problems, so those problems may be resolved quickly in order to prevent
other accidents or failures.
     Response: The commenter's assumption that
operators will use all available time to delay a submission does align
with BSEE's experience with the recent history of reporting since the
rule implementation began. BSEE's experience shows operators to be
making a good faith effort to complete investigations as soon as
practicable. Based upon a substantial number of submissions, BSEE
expects most submitters will have completed their investigation and
analysis reports long before the allowable time runs. In 2017, only
1.5% of the reported failure notifications resulted in an investigation
and failure analysis that required more than 120 days to complete. The
provision in the rule allows extra time for the moderately complicated
cases that require more time to process. For example, the nature of
certain operational failures--such as systematic
[[Page 21945]]
failures, stack pulls, and lower marine riser pulls--may warrant
additional case-by-case consideration, as it is reasonable to expect
the related analyses would require more time beyond that allowed in the
rule. BSEE extended the timeframe in the final rule to reduce
administrative burden for those cases where extra time could enable the
timely resolution and completion of an investigation and analysis
report. For those rare cases requiring more time than the rule allows,
BSEE believes that providing for an extension request is appropriate.
BSEE does not, however, expect these revised timelines to result in
general delays of the type described by the commenter.
    We agree with the commenter that it is important for BSEE and the
manufacturer to acquire and review the equipment failure information to
make recommendations to prevent similar failures in the future. BSEE
works with the U.S. Department of Transportation's Bureau of
Transportation Statistics (BTS),\29\ to ensure technical review of the
information provided by submitters. The analysis considers potential
consequences related to specific failures, potential systematic
concerns, and any reduction in effective barrier operation. When
significant safety concerns are identified, there are processes in
place to raise awareness in a timely manner to prevent similar
failures. Items of lesser potential significance are dealt with through
public reports based on aggregated data.
---------------------------------------------------------------------------
    \29\ Operators submit failure information through
www.SafeOCS.gov, where it is received and processed by BTS. BSEE
identified BTS as the designee and recommended that SPPE failure
information should be sent to BTS via www.SafeOCS.gov through a
press release issued on October 26, 2016 (https://www.bsee.gov/newsroom/latest-news/statements-and-releases/press-releases/bsee-expands-safeocs-program). BSEE and BTS entered into a Memorandum of
Understanding (MOU) that provides for BTS to collect BOP and SPPE
failure reports. The MOU may be viewed on BSEE's website at: https://www.bsee.gov/sites/bsee.gov/files/bsee-bts-mou-08-18-2016_0.pdf.
Reporting instructions are on the SafeOCS website at: https://www.SafeOCS.gov.
---------------------------------------------------------------------------
    Summary of comments: A commenter suggested that the rule include a
method to extend investigations that have been started, but are not
complete within the 120 days. This commenter recommended including a
requirement for the operator to submit a status update to BSEE
detailing the progress to date, the reasons why the investigation was
not completed within the required timeframe, and an extension period,
if any. The commenter is concerned that the fixed number of 120 days
may result in conclusions that do not identify the true root cause,
thereby ultimately compromising safety.
     Response: BSEE disagrees with allowing a blanket
extension of the 120-day completion date for the failure analysis. BSEE
does, however, acknowledge that there may be extenuating circumstances
that prevent an operator from meeting these timelines. Accordingly, the
final rule provides that if an operator cannot meet the required
timeframes, the operator may request an extension to the failure
analysis timeframes by submitting a request to the Chief, OORP and, if
appropriate, BSEE may approve an extension. Due to the potential for
some failures to have broader safety implications, it is not reasonable
to allow the operator to define an open-ended period in which to
complete the investigation. Extension requests will be handled on case-
by-case basis to allow consideration of circumstances. In 2017, only
1.5% of the reported failure notifications resulted in an investigation
and failure analysis that required more than 120 days to complete. BSEE
extended the timeframe in the final rule to reduce administrative
burden for those cases where extra time could enable the timely
resolution and completion of an investigation and analysis report. For
those rare cases requiring more time than the rule allows, BSEE
believes providing for an extension request is appropriate and that
such a request may reasonably be expected to address the items
recommended by the commenter.
    Summary of comments: A commenter asserted that proposed Sec.
250.730(c)(1) would reduce the clarity, safety, and effectiveness of
BOP systems by limiting information exchange about equipment failures.
The commenter opposed the proposed language because it does not specify
who the operator must notify at BSEE or other entities, such as the
equipment manufacturer. The commenter also asserted that the use of
third parties to receive data and reports on behalf of BSEE will make
it substantially more difficult for the public to acquire those data
and reports using the Freedom of Information Act (FOIA). The commenter
contends that because the focus is on equipment failure, it would be
important for technical experts to acquire and review the equipment
failure information to make recommendations to prevent similar failures
in the future. The commenter supported the 120-day failure analysis
completion date in the existing regulations, asserting that this
timeframe ensures that any needed equipment changes are quickly
identified, and changes can be made at problematic wells as soon as
possible to prevent additional failures.
     Response: BSEE disagrees with the assertion that
the language in paragraph (c)(1) will ``reduce the clarity, safety, and
effectiveness of BOP systems by limiting information exchange about
equipment failures.'' In terms of specifying to whom data should be
submitted, BSEE agrees that this was less than clear with respect to
submissions to BSEE, and accordingly modified the proposed rule text to
clarify that submissions directed to BSEE should be sent to the Chief,
OORP. With respect to a third party designated to receive data, BSEE
can provide information on who operators should submit this data to
through a variety of public notices, such as a press release or NTL.
Not including these specifics in the regulations allows BSEE to change
the designated third party without undertaking rulemaking. With respect
to reporting to equipment manufacturers, it is up to the operator to
find out from the equipment manufacturer to whom the required data and
information should be submitted.
    With respect to the use of a third party to receive data, as
previously discussed, BSEE currently has an agreement with BTS to
receive and process the data through the SafeOCS program. This
agreement is consistent with the policies of the Confidential
Information Protection and Statistical Efficiency Act (CIPSEA).\30\
CIPSEA requires that BTS treat and store such reports confidentially,
under strict criminal and civil penalties for noncompliance.
Information submitted under CIPSEA also is protected from release to
other government agencies (including BSEE), from Freedom of Information
Act (FOIA) requests and subpoenas. If the information were to be
submitted to BSEE, BSEE could only protect its confidentiality to the
extent allowed by Federal law other than CIPSEA. The SafeOCS program
was designed to protect the confidentiality of information submitted
and promote failure reporting without fear of reprisals. BSEE uses this
third-party approach for submission of equipment component failure
information in the interest of promoting the sharing of safety data and
information, while protecting sensitive identifying information the
release of which could
[[Page 21946]]
reduce the incentive to share all of the facts related to an incident.
This determination was made to protect trade secrets and proprietary
information and especially to ensure facts that pertain to safety are
not left out of reports due to concerns about disclosure under FOIA.
BSEE believes placing this raw data at risk of disclosure under FOIA
would reduce operator openness in what is shared regarding equipment
component failures. For this reason, the Bureau of Transportation
Statistics currently houses BSEE's system of record on this collection
effort.
---------------------------------------------------------------------------
    \30\ Reports submitted through www.SafeOCS.gov are collected and
analyzed by BTS and protected from release under the Confidential
Information Protection and Statistical Efficiency Act (CIPSEA) (44
U.S.C. 101). Annual reports for 2016 and 2017 reporting periods for
well control regulations are available at: https://www.safeocs.gov/wcr_home.htm.
---------------------------------------------------------------------------
    We agree with the commenter that it is important for technical
experts and others to acquire and review the equipment failure
information to make recommendations to prevent similar failures in the
future. BTS engages subject matter experts to analyze the reports and
prepare public reports that are available to all stakeholders. BTS has
the ability under CIPSEA to have a confidentiality officer from BTS
communicate with a respondent when safety issues arise of particular
concern to subject matter experts. The BTS confidentiality officer may
recommend that the submitter of the information communicate the safety
issue directly with BSEE and the OEM.
    In addition, Sec.  250.730(c)(1) requires that operators follow the
failure reporting procedures in API Standard 53, which is incorporated
by reference in BSEE regulations at Sec.  250.198. API Standard 53
includes processes for the sharing of equipment failure information
between the manufacturers and owners of blowout prevention equipment.
This would include reporting of any malfunction or failure by the
equipment owner to the equipment manufacturer and the manufacturer's
response to the equipment owner with a timeline for failure resolution.
Comments Related to Proposed Sec.  250.730(c)--Anonymous Failure
Reporting
    Summary of comments: One commenter expressed concern that the
proposal to allow companies to anonymously submit the results of
equipment failure investigations through a third-party would
effectively make the failure reporting requirement voluntary.
     Response: BSEE disagrees. The failure reporting
is required regardless of where and how an operator submits the data.
This revision does not provide for anonymous failure reporting through
a designated third party. The failure reporting is not anonymous. Each
time BTS receives a notification of failure under Sec.  250.730(c), it
provides BSEE with a notification that a submission was made and
includes the name of the company. BSEE may choose to open an
investigation at any time when information received from non-BTS
sources demonstrates operators are not complying with the requirements.
However, it is important to note, BSEE does not receive any information
from BTS about a single failure report other than the name, submittal
date, and reference ID numbers of the report of the reporting company.
    BTS maintains the raw data and entity information to allow
aggregated reporting. BTS also has measures available under CIPSEA
whereby a confidentiality officer from BTS may communicate with a
respondent when safety issues of particular concern to subject matter
experts arise and warrant immediate action. Thus far, BSEE has observed
a close correlation between the companies engaged in drilling activity
and those reporting equipment component failures.
Comments Related to Proposed Sec.  250.730(d)--BOP Stack Manufacturing
Requirements
    Summary of comments: A commenter recommended that BSEE add the
phrase ``or stack sub-assemblies'' to the BOP stack manufacturing
requirements under Sec.  250.730(d). The commenter asserted that this
change would clarify that the rule covers the overall BOP stack and the
component assemblies contained within the stack.
     Response: BSEE disagrees with this
recommendation. The commenter did not provide enough information or
justification to substantiate the recommended change. Stack sub-
assemblies are part of the BOP stack; therefore it is BSEE's view that
they are already covered under these requirements.
Comments Related to Proposed Sec.  250.730(b)--Corrective Maintenance
    Summary of comments: A commenter recommended that BSEE remove
``maintenance'' and ``repair'' from the requirement for the operator to
follow original equipment manufacturer (OEM) recommendations for the
BOP systems in Sec.  250.730(b). The commenter suggested adding
``remanufacture'' to this requirement. According to the commenter, the
recommended changes would ensure consistency with API 53, further
noting that maintenance is covered in Sec.  250.730(a).
     Response: BSEE disagrees with the comment. The
OEM designs the equipment according to detailed specifications.
Therefore, the OEM recommendations, if they exist, for maintenance and
repair are important for ensuring the condition of the equipment
remains within the design limits. BSEE is not adding ``remanufacture''
because this is covered under ``repair''.
Comments Related to Proposed Sec.  250.730--Proposed Revisions Reduce
Operational Requirements for BOPs
    Summary of comments: A commenter asserted that the proposed
revisions in Sec.  250.730 would reduce the conditions under which a
BOP must function, while increasing the time allowed for operators to
investigate and report on a BOP failure. The commenter asserted that
the proposed revisions would only require a BOP to be capable of
closing and sealing a wellbore ``in the event of flow due to a kick,''
eliminating the existing language that requires a BOP to be capable of
closing and sealing the wellbore ``at all times.'' The commenter
emphasized that there are other conditions that may necessitate closure
and sealing besides a kick, such as an approaching hurricane or a fire
or other malfunction. This commenter asserted that the proposed change
would substantially narrow the conditions under which a BOP would be
required to be capable of closing.
     Response: BSEE disagrees. The proposed revisions
would not weaken or alter the underlying requirements that the BOP
system must be able to function during all operations. This section
ensures that the BOP system is designed to close and seal a well in the
event of flow from a kick from the well because that is representative
of the most critical and challenging circumstances a BOP must address.
The operator must verify the ability of the BOP to function during a
non-kick event through the regular function and pressure testing as
required by final Sec.  250.737. The operator will also still be
required to obtain independent third-party certification that the BOP
is designed, tested, and maintained to perform under the maximum
environmental and operational conditions anticipated to occur at the
well under Sec.  250.731.
Comments Related to Proposed Sec.  250.730--Incorporate API Standard 53
Addendum 1 and API Standard 53, 5th Edition
    Summary of comments: A commenter recommended that the incorporation
by reference of API Standard 53, Blowout Prevention Equipment Systems
for Drilling Wells, Fourth Edition, July 2016, should include Addendum
1 of that standard. The commenter also
[[Page 21947]]
noted that the 5th edition of that standard is being finalized and
recommended that BSEE consider the 5th edition for incorporation by
reference to ensure operations on the OCS are conducted according to
the latest edition of the API standard for well control systems and are
consistent with operations around the world.
     Response: BSEE reviewed the addendum and
determined it is appropriate for incorporation into the regulations.
The addendum addresses multiple issues that BSEE has had to deal with
through departures from compliance with the incorporated API Standard
53 (without the addendum) since the development of the 2016 WCR (e.g.,
section 7.2.3.2.9 Side outlet location and section 7.3.13.2.5 fire
rating of MUX lines). The inclusion of the addendum to API Standard 53
brings the regulations in line with the current latest edition of this
standard. BSEE understands that API is developing a 5th Edition of API
Standard 53, and BSEE will evaluate that document when it is finalized
for possible incorporation into the regulations in a future rulemaking.
Comments Related to Proposed Sec.  250.730--Use of OEM Recommended
Maintenance Practices
    Summary of comments: A commenter asserted that the OEMs do not have
operational experience and the type of continuous feedback needed to
develop effective maintenance practices to manage assets. The commenter
also asserted that because OEMs do not need to worry about rig
downtime, they can afford to be conservative. The commenter concluded
that this poses a significant risk that the OEM-developed maintenance
practices would require the operator to perform unnecessary maintenance
and repairs. The commenter also asserted that this practice could
result in OEMs leveraging this as an aftermarket revenue generator, and
this approach presents a technical barrier to trade and causes a
conflict of interest. The commenter generally challenged certain OEM
maintenance recommendations, based on proven field results.
     Response: This regulation does not require the
OEM to perform the maintenance or train the personnel performing
maintenance. With regard to the OEM recommendations, operators are
required to comply only with applicable OEM recommendations to the
extent that they exist. If an operator has a specific issue with OEM
recommendations, BSEE may recognize other alternative procedures. OEMs
of offshore operational equipment generally maintain close
communications with operators and drilling contractors, including
coming on location as needed. OEMs develop maintenance procedures
through an effective communication program including practices for
sharing information under API Standard 53 and through notification
requirements under this final rule.
    The TBT Agreement seeks to avoid unnecessary obstacles to
international trade, in part by requiring that technical regulations
and conformity assessment procedures be consistent with international
standards promulgated by international standards developing
organizations (SDOs). This rule does not create a technical barrier to
trade because it is neutral as to the national origin of regulated
equipment. The proposed rule did not, and this final rule does not,
discriminate in favor of U.S.-fabricated equipment. The final rule is
equally applicable to all relevant equipment, regardless of the
equipment's country of origin. Accordingly, BSEE's proposed rule did
not, and the final rule does not, create an unnecessary technical
barrier to trade.
Comments Related to Proposed Sec.  250.730--Use of Word ``applicable''
for Applying OEM Recommendations
    Summary of comments: A commenter asserted that ``applicable'' is
subjective and the proposed rule is not clear about who determines if
an OEM recommendation is applicable. The commenter was concerned that
an operator or drilling contractor could decide to simply disregard OEM
recommendations as not applicable. The commenter recommended changing
the proposed regulations to state that the operator must follow the OEM
recommendations unless BSEE directs them otherwise or they receive
other directions in writing from the OEM.
     Response: BSEE disagrees. As BSEE explained in
the proposed rule preamble, and included in the final Sec.  250.730(b)
clarifies that BSEE expects the use of ``applicable'' OEM
recommendations for the design, fabrication, maintenance, and repair of
BOP systems, as well as personnel training in their use. The proposed
revision to include ``applicable'' is necessary because some OEMs may
not have specific recommendations for every item required by this
paragraph, and operators are not required to follow recommendations
that are not applicable to the relevant equipment or operation. BSEE
expects operators to follow OEM recommendations to the extent relevant
recommendations exist.
Comments Related to Proposed Sec.  250.730(a)--Request To Incorporate
API RP 59
    Summary of comments: A commenter recommended that BSEE incorporate
by reference API Recommended Practice 59, Second Edition--Recommended
Practice for Well Control, Section 4.4 in Sec.  250.730(a). The
commenter asserts that the methodology of API RP 59, section 4.4
focuses on one open hole interval of flow, not on the entire open well
bore interval pertinent to the worst case discharge. This addresses the
long-standing, safe well control practice of drilling 10 to 20 feet
into a drilling break or a prospective hydrocarbon interval, then
stopping drilling operations to ``check for flow'' as the proven method
of determining a kick in a well.
     Response: BSEE will evaluate API RP 59 for
possible incorporation by reference in a future rulemaking. Operators
should develop appropriate control procedures based on specific well
and site conditions and accepted good engineering practices.
Comments Related to Proposed Sec.  250.730--BOP System Requirements
    Summary of comments: A commenter strongly opposed the proposed
revisions to requirements in Sec. Sec.  250.730, 250.733, and 250.734
regarding the BOP systems. The commenter expressed concern that the
proposed revisions would allow the use of BOPs that cannot close and
seal a wellbore under the range of conditions encountered, including
high-pressure, high-temperature drilling environments. The commenter
noted that the existing language in Sec.  250.730(a) is unambiguous
regarding the key capabilities of the BOP system, stating that the BOP
system is required to be able to close and seal the wellbore at all
times. The commenter asserted that the proposed rule would weaken this
language by specifying only certain circumstances in which the BOP
system must function, i.e., only in the event of flow due to a kick.
     Response: BSEE disagrees. The revisions do not
weaken or alter the underlying requirement that the BOP system must be
able to function during all operations. This section specifically
ensures that the BOP system is designed to close and seal a well in the
event of flow from a kick from the well because that is representative
of the most critical and challenging circumstances a BOP must address.
The operator is required to verify the ability of the BOP to operate in
a non-kick event through regular function and pressure testing required
by Sec.  250.737. The regulation
[[Page 21948]]
still requires that the operator obtain independent third-party
certification that the BOP is designed, tested, and maintained to
perform under the maximum environmental and operational conditions
anticipated to occur at the well under Sec.  250.731.
What information must I submit for BOP systems and system components?
(Sec.  250.731)
    This section of the existing regulations details the information
that must be included in the applicable BSEE permit (e.g., APD or APM)
for any operation that uses a BOP. The required information includes a
complete description of the BOP system and system components, schematic
drawings, and verifications demonstrating that the BOP is fit for
service on the applicable well.
Summary of Proposed Revisions
    BSEE proposed to revise the information submitted to BSEE pursuant
to paragraph (a)(5) by replacing ``to achieve an effective seal of each
ram BOP'' with ``to close each ram BOP.'' This revision would affect
information submitted to BSEE and would more accurately align with the
control system and regulator control setting requirements of API
Standard 53.
    BSEE also proposed to revise this section by removing the BAVO
verification requirements in existing paragraphs (d) and (f). The BAVO
verifications required by existing paragraphs (d)(1) and (d)(3) were
redundant to the verifications required by paragraph (c). However, the
verifications required by current paragraph (d)(2) are still necessary
and BSEE therefore proposed to add them to revised paragraph (c). BSEE
proposed to remove paragraph (f) because the Report that is the subject
of that paragraph would be eliminated by the proposed revisions to
Sec.  250.732(d). The independent third-party verifications under
paragraph (c) help ensure that the BOP is fit for service at each
specific well. BSEE also proposed to revise this section by replacing
references to a BAVO with references to an independent third party that
meets the requirements of Sec.  250.732(b).
Summary of Final Rule Revisions
    BSEE received and considered comments on the proposed revisions and
includes the proposed language in the final rule without change.
Summary of Comments
Comments Related to Proposed Sec.  250.731(a)(5)--Regulator Set Points
    Summary of comments: Multiple commenters asserted that there is
[acy] difference between sealing and closing in this context and
requested clarification on the intent of the regulation. Commenters
expressed concerns with BSEE's explanation and reference to
[Acy][Rcy][Iukcy] Standard 53 to adequately clarify the intent.
Commenters also requested justification for the removal of the word
``effective''.
     Response: BSEE does not agree with the comments. Paragraph
(a)(5) principally identifies information that must be submitted to
BSEE for BOP systems and system components. Subsequent sections
regulate operational and equipment requirements for these systems and
components. BSEE used the term ``close'' because the regulator settings
are not changed throughout operations. The requirements of paragraph
(a)(5) only relate to the regulator set points, and do not alter any of
the ram operational requirements contained in Sec. Sec.  250.733 and
250.734 for surface and subsea BOPs, respectively. Some of the rams do
not seal, such as the casing shear ram, and BSEE utilizes this data in
the permit application to evaluate ram closing and sealing
capabilities. The word ``effective'' in this context is not necessary
and does not provide any supplemental regulatory standard.
Comments Related to Proposed Sec.  250.731(c)--Applicability to Coiled
Tubing
    Summary of comments: A commenter requested clarification about the
applicability of paragraph (c) to coiled tubing. The commenter also
asserted that Sec.  250.731(c)(1) can be interpreted to mean that a
shear test at depth is required. In reality, the depth adjustment is a
calculation based on different densities of hydraulic fluid and
seawater. The commenter, therefore, recommended adding the words ``and
depth'' to Sec.  250.732(a)(3) so that the provision states, ``Include
shearing and sealing pressures for all pipe to be used in the well
including correction for MASP and depth.'' The commenter also suggested
removing Sec.  250.731(c)(1).
     Response: Section 250.731(c) applies to coiled tubing;
however, Sec.  250.731(c)(4) is only applicable to the specified
situations (subsea BOP, a BOP in an HPHT environment, or a surface BOP
on a floating facility). BSEE disagrees with the suggestion to add the
term ``and depth'' because the definition of MASP already takes into
account depth, whether at surface or subsea. BSEE also disagrees with
the recommendation to revise Sec.  250.732(a)(3) and remove Sec.
250.731(c)(1) because the requirements in Sec.  250.732 are utilized to
provide supporting documentation for the verifications required in
Sec.  250.731.
What are the independent third party requirements for BOP systems and
system components? (Sec.  250.732)
    This section of the existing regulations describes the criteria for
an organization to become a BAVO, and identifies the circumstances in
which an operator must use a BAVO to satisfy certification,
verification, or reporting requirements.
Summary of Proposed Revisions
    BSEE proposed to revise this section by removing all references to
a BAVO and, where appropriate, replacing those references with an
independent third party. This change would also be made in appropriate
locations throughout Subpart G where BAVOs are referenced. Independent
third parties have been utilized as a long-standing industry practice
to carry out certifications and verifications similar to those that a
BAVO would perform. Independent third parties have been performing the
functions identified for BAVOs since promulgation of the 2016 WCR.
Based on BSEE's determination to remove the use of BAVOs, as previously
discussed under section IV of this final rule preamble, BSEE revised
the section heading to reflect the change from a BAVO to an independent
third party, removed paragraphs (a)(1) and (a)(3), and replaced all
remaining BAVO references with references to an independent third
party. The independent third-party qualifications in existing paragraph
(a)(2) remain in this section, but would now be in proposed paragraph
(b).
    BSEE also proposed to remove the requirements in current paragraph
(b)(1)(iv) to verify that testing was performed on the outermost edges
of the shearing blades of the shear ram positioning mechanism. This
proposed change would align the verification requirements with BSEE's
proposal to remove the centering mechanism requirement from existing
Sec.  250.734(a)(16) that is the subject of this verification. BSEE
also proposed to remove from existing paragraph (b)(1)(i)--a vestigial
reference to a compliance deadline that has already passed. This is
merely an administrative revision.
[[Page 21949]]
    BSEE also proposed to revise existing paragraph (b)(2)(ii) by
changing the testing facilities' verification pressure testing hold
time demonstration from 30 minutes to 5 minutes. This revision would
allow the use of previously established historical data to help
demonstrate the blind shear ram functionality in the applicable permit
application.
    BSEE proposed to make a minor revision to paragraph (c) to update
an incorrect citation--the referenced definition of HPHT environments
is found in Sec.  250.804(b), rather than Sec.  250.807(b), as stated
in the existing regulations.
    BSEE proposed to remove the Mechanical Integrity Assessment (MIA)
report requirements from paragraph (d). The MIA report was required as
a function of the use of BAVOs. BSEE determined that an MIA report is
no longer necessary because BSEE proposed to eliminate the use of BAVOs
and the information contained within the MIA report is redundant with
the BOP equipment capability verifications required by Sec.  250.731.
Summary of Final Rule Revisions
    BSEE received and considered comments on the proposed revisions,
and includes in the final rule most of the proposed language without
change, except for the following revisions. BSEE is revising proposed
paragraphs (a)(1)(i) and (iii) and (iv) (final paragraphs (a)(1)(i) and
(iii) and (v)) by replacing ``drill pipe'' with ``tubular body of any
drill pipe (excluding tool joints, bottom-hole tools, and bottom hole
assemblies such as heavy-weight pipe or collars), workstring, tubing
and associated exterior control lines and any electric-, wire-, and
slick-line to be used in the well.'' BSEE made these revisions to
provide consistency with the shearing requirements of Sec. Sec.
250.733(a)(1) and 250.734(a)(1)(ii). This clarification would help
ensure that the shear testing applies to the required equipment that
needs to be shearable. This revision does not add new equipment
required for shear testing, but instead clarifies BSEE's established
practice.
    BSEE also is re-designating proposed paragraphs (a)(1)(iv) and
(a)(1)(v) as (a)(1)(v) and (a)(1)(vi) respectively, and retaining (in
large part) existing paragraph (b)(1)(iv) as new (a)(1)(iv) to ensure
that testing is performed on the outermost edges of the shearing blades
of the shear ram. This retention was based on comments, and modifies
the existing text of the relevant provision only to remove reference to
the shear ram positioning mechanism that is no longer required under
the cross-referenced regulation. BSEE is retaining in Sec.
250.734(a)(16)(i) the centering requirement for shearing, but not
requiring that it utilize a positioning mechanism. BSEE is making
corresponding edits to this section to help ensure the shearing
verifications and certifications align with the revised shearing
requirements. This requirement helps verify that the shear rams will
shear along any point of the shearing surface.
    BSEE is revising proposed paragraph (a)(2) to clarify that the
pressure integrity test applies to sealing components. A pressure
integrity test for a non-sealing component is not practicable or
feasible. BSEE is also revising proposed paragraph (a)(2)(i) to
indicate that testing is conducted after the shearing is completed and
prior to opening. BSEE made this revision based on comments to provide
clarity for defining how the verification is conducted. BSEE revised
this section to help ensure that the testing is accomplished in one
continuous action to better simulate sealing after shearing in real-
world well control applications.
Summary of Comments
Comments Related to Proposed Sec.  250.732(a)(1)--Definition of Drill
Pipe
    Summary of comments: A commenter asserted that the use of the word
``drill pipe'' throughout Sec.  250.732(a) is not complete. The
commenter recommends that BSEE include terms, such as coiled tubing,
shear subs, and landing strings in this section for completeness.
     Response: BSEE agrees with the commenter and has revised
proposed paragraphs (a)(1)(i), (iii), and (v) by replacing ``drill
pipe'' with ``tubular body of any drill pipe (excluding tool joints,
bottom-hole tools, and bottom hole assemblies such as heavy-weight pipe
or collars), workstring, tubing and associated exterior control lines
and any electric-, wire-, and slick-line to be used in the well.''
These revisions make these testing requirements consistent with the
shearing requirements of Sec. Sec.  250.733(a)(1) and 734(a)(1)(ii).
This clarification will help ensure that the shear testing applies to
the required equipment that needs to be shearable.
Comments Related to Proposed Sec.  250.732(a)(2)(i)--Pressure Integrity
Testing Procedures
    Summary of comments: A commenter recommended that BSEE remove
``immediately'' and add ``after the shearing is completed and prior to
opening the rams'' to provide clarity to the pressure integrity
testing.
     Response: BSEE agrees with the commenter and has revised
this paragraph to reflect the commenter's recommendation, except that
we have used the phrase ``prior to opening the component.'' BSEE
revised this paragraph to help ensure that the testing is done in one
continuous action to better simulate sealing after shearing in real
world well control applications.
Comments Related to Proposed Sec.  250.732(a)(2)(ii)--Lab 30 Minute vs
5 Minute Pressure Hold Time
    Summary of comments: Multiple commenters oppose the proposed
replacement of the existing requirements in Sec.  250.732(b)(2)(ii) of
[acy] 30-minute hold time for [acy] verification pressure test with the
proposed Sec.  250.732(a)(2)(ii) [acy] 5-minute hold time. The
commenters asserted that [acy] 30-minute test is an established
practice according to various standards organizations, and therefore
the commenters see no reason for the change. The commenters also
asserted that BSEE does not provide any analysis or data to support
this change and should make any data available.
     Response: BSEE does not agree that holding a constant
pressure for 30 minutes is necessary to demonstrate sealing
capabilities. Based on BSEE experience since the promulgation of the
2016 WCR and a review of longstanding historical data demonstrating
successful application of 5 minute hold time testing, BSEE concluded
that 30 minute testing is unnecessary. BSEE is unaware of standards
referencing a standardized 30-minute lab test pressure holding time for
BOP shearing verification. However, BSEE is aware of an industry
standard, API 16TR1, Shear Ram Performance Test Protocol, that includes
field performance testing and specifies a 5 minute pressure hold time
after shearing pipe. BSEE reviewed the publicly available incident data
on the BSEE website to try to identify any past incidents involving
failure of equipment after successfully sealing in a well, but was
unable to identify any such incidents. BSEE is also unaware of any data
showing lab failures during the hold times between the 30-minute and 5-
minute intervals. BSEE also reviewed permits issued prior to 2010 to
verify the historic lab shear and seal data hold times. Of the permits
reviewed, pressure hold times did not indicate any failures after the
5-minute mark. BSEE uses this 5 minute testing data to verify that the
component will provide a seal when activated.
[[Page 21950]]
Comments Related to Proposed Sec.  250.732--BAVOs
    Summary of comments: A commenter expressed concerns about the
removal of the BAVO and MIA report. A commenter recommended that in the
absence of the BAVO and MIA report requirements, it is critical that
BSEE ensure strict compliance with all third-party certification
requirements, including the BOP equipment capability verifications
required by Sec.  250.731.
     Response: BSEE agrees with the commenter that it is
important to ensure compliance with independent third-party
certification and verification requirements. In final Sec.  250.731(c),
BSEE requires certifications by an independent third party, in lieu of
a BAVO, that include verification, for a subsea BOP, a BOP in an HPHT
environment as defined in Sec.  250.804(b), or a surface BOP on a
floating facility, that the BOP has not been compromised or damaged
from previous service. BSEE expects full compliance with these
certification requirements, regardless of who is performing the
certification. The requirements of Sec.  250.731 adequately cover the
substance of the matters previously addressed in the MIA report, and
BSEE expects that independent third parties will capably perform the
same functions previously assigned to BAVOs, as they have since
promulgation of the 2016 WCR.
    Summary of comments: Multiple commenters oppose the proposed
revisions to remove the BAVO, and recommend that the companies that
operators use to assess blowout preventers should continue to be BSEE-
certified. The commenters assert that this is important to ensure that
reviews of important equipment are objective and standardized through
the use of BSEE-certification of third-parties.
     Response: BSEE disagrees that BSEE needs to certify the
parties used to assess blowout preventers. BSEE is maintaining rigorous
qualification requirements for independent third parties that ensure
their professional qualification and independence. The independent
third party must be a technical classification society, or a licensed
professional engineering firm, or a registered professional engineer
capable of providing the required certifications and verifications. If
BSEE becomes aware of any performance issues with an independent third
party, BSEE has options for addressing the issues (e.g., verifications
through the permitting process).
Comments Related to Proposed Sec.  250.732--MIA Report Content
    Summary of comments: A commenter suggested that specific items in
the MIA report are not redundant of other requirements and should be
included in the regulations (e.g., existing Sec. Sec.  250.732(d)(5),
250.732(d)(8), 250.732(d)(9), 250.732(d)(11), and 250.732(d)(13)).
     Response: BSEE disagrees with the suggested changes. The
MIA report content is not only redundant of Sec.  250.731, but also of
other independent third-party reviews, certifications, and
verifications required in Sec. Sec.  250.734, 250.738, and 250.739, as
well as personnel operational requirements in existing Sec.  250.710,
What instructions must be given to personnel engaged in well
operations? among others. It is not necessary to retain the identified
elements of the MIA report.
What are the requirements for a surface BOP stack? (Sec.  250.733)
    This section of the existing regulations describes the capability,
type, and number of BOPs required when an operator uses a surface BOP
stack for drilling or for conducting operations. This section also
describes the requirements for the risers and BOP stack when a surface
BOP is used on a floating production facility.
Summary of Proposed Revisions
    BSEE proposed to revise paragraph (a)(1) by removing the reference
to an extended time for compliance with exterior control line shearing
requirements under the 2016 WCR, which has elapsed and no longer
warrants reference in the regulations. BSEE also proposed to remove the
requirement to have an alternative cutting device used for shearing
electric-, wire-, or slick-line if your blind shear rams are unable to
cut and seal under maximum anticipated surface pressure (MASP).
    BSEE also proposed to revise paragraph (b)(1) by extending the
compliance date from April 29, 2019, to April 29, 2021, to correspond
with the same requirements for subsea BOP stacks. This revision would
align the dual shear ram requirements for surface BOPs installed on
floating facilities and subsea BOPs. Aligning these dates will reduce
confusion between the different effective dates of the similar
requirements for surface BOPs used on floating facilities and subsea
BOPs.
    BSEE proposed to add new paragraph (e) to clarify the minimum
requirements of a surface BOP system for well-completion, workover, and
decommissioning operations where estimated well pressures are low. The
provisions in this proposed paragraph were inadvertently removed from
the regulations through the 2016 WCR, and are consolidated from
Sec. Sec.  250.516, 250.616, and 250.1706 of the regulations as they
existed before the 2016 WCR. BSEE proposed minor revisions to the
original language to conform to the applicable operations covered under
revised Subpart G and to update cross-referenced citations.
Summary of Final Rule Revisions
    BSEE received and considered comments on the proposed revisions and
includes in the final rule most of the proposed language without
change, except for the following revisions. BSEE is revising paragraph
(a)(1) by adding: ``Prior to April 29, 2021, if your blind shear rams
are unable to cut any electric-, wire-, or slick-line under MASP as
defined for the operation and seal the wellbore, you must use an
alternative cutting device capable of shearing the lines before closing
the BOP. This device must be available on the rig floor during
operations that require their use.'' BSEE is retaining the alternative
cutting device requirements, similar to those found in existing
regulations, based on comments. As many commenters stated, BSEE is
aware that not all OEMs currently offer wireline cutting capability for
all BOP sizes and rated working pressures. This addition is necessary
to ensure that a device capable of cutting wire is available to help
ensure sealing efficiency. BSEE is limiting this requirement to the
window prior to April 29, 2021, because, after that point, shear rams
must be capable of shearing wire. Since the publication of the proposed
rule, BSEE has discussed these shearing requirements with relevant OEMs
and has determined that the technology currently exists, but is not yet
available for commercial off-the-shelf use.
    BSEE is also revising paragraph (b)(1) to clarify that, after April
29, 2021, operators must follow the BOP requirements in Sec.
250.734(a)(1) for new floating production facilities installed with a
surface BOP. These revisions are based on comments seeking clarity.
Since the publication of the 2016 WCR, including in the comments for
this rulemaking, stakeholders have expressed confusion about the
requirements in this section that reference Sec.  250.734 regarding
dual shear rams, which do not take effect until 2021. BSEE is making
the compliance date of April 29, 2021 the same for Sec. Sec.
250.733(b)(1) and 250.734(a)(1) to
[[Page 21951]]
avoid confusion. This will apply only to new floating production
facilities with a surface BOP, and the expected number of those types
of facilities is minimal. The intent of the proposed rule was for the
requirements to apply to new facilities installed after 2021. These
regulations do not apply to existing facilities, even if they are
redeployed at another location because of several issues, including,
but not limited to, clearance and weight issues.
    BSEE is revising proposed paragraph (e)(4) to clarify that the
drill string should include the drill pipe, work string, or tubing,
depending on the operation. Based on BSEE's review of the proposed rule
and submitted comments, this clarification will help ensure the set of
pipe rams can seal around drill pipe, work string, or tubing. When
conducting well completions, workover, and decommissioning operations,
there are many types of equipment that are run in the hole through the
BOP. This requirement reflects longstanding and current BSEE practice.
This revision does not change or affect an operator's burden, as it is
currently reflected in operational practice and does not add new
equipment required for shear testing. The revision simply clarifies
current, longstanding BSEE practice.
Summary of Comments
Comments Related to Proposed Sec.  250.733--Compliance Dates
    Summary of comments: A commenter suggests that it would be
preferable to apply the April 2019 deadline for surface BOPs to both
subsea and surface BOPs.
     Response: BSEE disagrees that the compliance dates for
subsea BOP dual shear ram requirements should be 2019, because there
would not be sufficient time to install and implement the required
equipment modifications. BSEE understands that there is potential
confusion about the compliance date applicable to this section's
reference to the dual shear ram requirements of Sec.  250.734, because
those requirements do not take effect until 2021. Therefore, BSEE is
making the compliance dates of April 29, 2021 the same for Sec. Sec.
250.733(b)(1) and 250.734(a)(1) to avoid confusion. This requirement
only applies to newly installed floating production facilities that use
a surface BOP.
Comments Related to Proposed Sec.  250.733(e)--5K Systems
    Summary of comments: A commenter asserted that there are
differences and confusion between the regulations pertaining to 5,000
psi (5K) systems and API Standard 53. The commenter recommended that
BSEE align those regulations with API Standard 53 to avoid confusion.
     Response: BSEE agrees that there are differences between
the regulations and API Standard 53; furthermore, BSEE does not agree
with using the API Standard 53 options for stack arrangements for 5K
systems. Paragraph (e) applies to well-completion, workover, and
decommissioning operations.
Comments Related to Proposed Sec.  250.733(b)(1)--Floating Facilities
    Summary of comments: Multiple commenters assert that paragraph
(b)(1) is applicable only to new floating production facilities.
     Response: BSEE agrees with the commenters and has revised
proposed paragraph (b)(1) to clarify its applicability only to new
floating production facilities installed after April 29, 2021, that use
a surface BOP.
Comments Related to Proposed Sec.  250.733(a)(1)--Alternative Cutting
Device
    Summary of comments: Multiple commenters oppose removing the
alternative cutting device requirement, as there are no qualified OEM
blind shear rams for certain BOPs. Commenters assert that the
alternative cutting device is considered necessary to meet the
requirement and considered part of the BOP system; therefore, BSEE must
allow the alternative cutting device. A commenter also suggested that
BSEE should allow the use of the alternative cutting device prior to
April 29, 2021, and, after this date, require that the shearing rams be
capable of shearing the wire.
     Response: BSEE agrees with the commenters and has added
back in the provisions related to the alternative cutting device to
paragraph (a)(1). BSEE is aware that not all OEMs currently offer
wireline cutting capability for all BOP sizes and rated working
pressures. As encouraged by Congress \31\ to ensure that offshore
operations promote safety and protect the environment in a technically
feasible manner, this addition is necessary to ensure that a device
capable of cutting wire is available to ensure sealing efficiency.
Consistent with an option discussed in the proposed rule to extend the
compliance date, BSEE is limiting the timeframe for allowing the
alternative cutting device. The cutting device may only be used until
April 29, 2021, after which the shear rams must be capable of shearing
wire.
---------------------------------------------------------------------------
    \31\ See n. 10, supra.
---------------------------------------------------------------------------
Comments Related to Proposed Sec. Sec.  250.733 and 250.734--Dual Blind
Shear Rams
    Summary of comments: Multiple commenters recommended that BSEE
require dual blind shear rams. The commenters assert that blind shear
rams provide an extra layer of safety because they are designed to be
capable of sealing and shearing the drill pipe during active drilling.
     Response: BSEE disagrees with the recommendation to
require dual blind shear rams. Other shearing rams have other shearing
utility besides shearing the listed components in Sec. Sec.  250.733
and 250.734 (e.g., the casing shear ram is still necessary to shear
casing, which the BSR cannot shear). The current regulations provide
the operators flexibility for how they utilize the BOP system and
components for operations, while still requiring all critical shearing
capabilities. This final rule does not change the requirement for
operators to utilize dual shear rams by 2021, and does not require both
shear rams to seal.
What are the requirements for a subsea BOP system? (Sec.  250.734)
    This section of the existing regulations identifies the
requirements of a subsea BOP system used for drilling or to conduct
operations. The section describes the requirements for subsea BOP
system capabilities, as well as the functionality, type, and quantity
of required equipment (e.g., BOPs, pod control systems, accumulator
capacity, ROVs, autoshear and deadman, acoustic control system, and
management and operating protocols). This section also describes the
actions that an operator must take if it suspends operations to repair
the subsea BOP system.
Summary of Proposed Revisions
    BSEE proposed to revise paragraph (a)(1)(ii) by providing that a
``combination of the'' shear rams must be capable of shearing all the
items specified in the paragraph. This revision would have aligned the
functionality of the BOP system with API Standard 53 and proposed Sec.
250.730(a). BSEE explained that certain casing shears still have
difficulty shearing electric-,wire-, or slick-line, while certain blind
shear rams have difficulties shearing larger casing sizes. This
proposed revision would have provided the operators flexibility in
designing the BOP system and components for operations while still
ensuring all critical shearing capabilities. BSEE further proposed to
revise paragraph
[[Page 21952]]
(a)(1)(ii) by removing references to the extended compliance dates for
certain shearing requirements under the 2016 WCR, which have passed and
no longer warrant reference in the regulations.
    BSEE proposed to revise the accumulator requirements in paragraph
(a)(3) to better align with API Standard 53. BSEE also proposed to
remove the reference to the subsea location of the accumulator
capacity. BSEE understands that the accumulator system works together
with the surface and subsea accumulator capacity to achieve full
functionality, and BSEE proposed that it would be unnecessary for this
provision to identify only subsea requirements when the entire system
is covered under API Standard 53.
    BSEE proposed to revise paragraph (a)(3)(i) by clarifying that the
accumulator capacity must be sufficient to close each required shear
ram, ram locks, and one pipe ram and to disconnect the LMRP. During a
well control event, the most critical functions would be to close the
BOP components and seal the well.
    BSEE proposed to revise paragraph (a)(3)(ii) to clarify that the
accumulator capacity must have the capability to perform the ROV
functions within the required times specified in API Standard 53 using
the ROVs or flying leads. These revisions were proposed to better align
this section with API Standard 53, and to account for technological
advancements in ROV capabilities to meet the appropriate BOP closing
times.
    BSEE proposed to revise paragraph (a)(3)(iii) by removing the word
``dedicated'' before bottles, thus allowing bottles to be shared among
emergency and secondary control system functions to secure the
wellbore. This revision would further align the accumulator capacity
requirements with API Standard 53, account for the appropriate number
of accumulator bottles on the subsea BOP stack, help ensure that the
regulatory requirements do not exceed the operational or mechanical
design limits of the wellhead and BOP systems, and help minimize risks
associated with approaching those design limits.
    BSEE also proposed to revise paragraph (a)(4) by removing the word
``opening'' and adding references to the ROV function response times
contained in API Standard 53. After publication of the 2016 WCR, the
API Standard 53 committee clarified that standard's definition of
``operate,'' with respect to critical functions, included only the
``close'' function and not the ``open'' function. Removal of the ROV
``open'' function could limit the ability for well intervention after
the well has already been secured. However, it would not affect or
decrease the ROV's ability to close the required components for well
control purposes. During a well control event, the most critical
functions would be to close the BOP components and seal the well.
    BSEE also proposed to revise paragraph (a)(4) by requiring the ROV
to function the appropriate BOP component within the required response
time contained in API Standard 53. BSEE proposed to revise this
paragraph not only to better align it with API Standard 53, but also to
account for recent technological advancements in ROV capabilities to
meet the appropriate BOP closing times. BSEE is aware that operators
currently use high flow rate ROVs to meet the BOP component closing
times of API Standard 53.
    BSEE proposed to incorporate the latest edition (i.e., the 2nd
edition) of API RP 17H in proposed paragraph (a)(4). BSEE explained
that there is a conflict between the ANSI/API RP 17H 1st edition, as
incorporated by reference in the 2016 WCR, and the API Standard 53 ROV
requirements. The 2nd edition of API RP 17H eliminates the conflict
with API Standard 53. By incorporating by reference the 2nd edition of
API RP 17H, BSEE would ensure that the appropriate methods are utilized
to comply with the API Standard 53 ROV closure timeframe of 45 seconds.
    BSEE proposed to revise paragraph (a)(6)(iv) by clarifying that the
autoshear/deadman functions must be able to close, at a minimum, two
shear rams in sequence, but do not need to operate every emergency
function. Closing two shear rams in sequence may not be advantageous
for certain Emergency Disconnect Sequence (EDS) functions, as discussed
in the proposed rule (83 FR 22140).
    BSEE proposed to revise paragraph (a)(16) by removing references to
the centering mechanism and the ability to mitigate compression of the
pipe between the shear rams in paragraphs (a)(16)(i) and (ii),
respectively. Many of the shear ram designs have improved the shearing
capabilities to help ensure the shearing is conducted on the
appropriate shearing area of the shear blades.
    BSEE proposed to revise paragraph (b)(1) by replacing the BAVO
references with references to an independent third party.
    BSEE also proposed to revise paragraph (b)(2), redesignate existing
paragraph (b)(3) as (b)(4), and add new paragraph (b)(3) in order to
include provisions for testing the applicable BOP or LMRP upon relatch
of the BOP or LMRP to the well. BSEE proposed these revisions to codify
longstanding BSEE policy and to clarify testing requirements when an
operator has returned to the well location and relatched the BOP or
LMRP to the well. These tests would help confirm that the BOP or LMRP
is properly functional prior to resuming operations after the BOP or
LMRP is removed.
Summary of Final Rule Revisions
    BSEE received and considered comments on the proposed revisions and
includes most of the proposed language in the final rule without
change, except for the following revisions.
    BSEE is not finalizing the proposed revisions to paragraph
(a)(1)(ii) and is keeping many of the existing requirements, except for
the references to the now-past compliance date from the 2016 WCR. This
change from the proposed rule is based on BSEE's consideration of
comments received and on BSEE's understanding concerning the importance
of shearing redundancy. It is also based on BSEE's recognition that the
proposed language would have permitted reliance on a ``combination'' of
shear rams, which would have created some potential ambiguity regarding
the number of rams subject to this shearing requirement.
    BSEE revised final paragraph (a)(3)(iii) by removing the extended
compliance date and clarifying that the accumulator bottles for
autoshear and deadman must be located subsea. Based on comments
received, BSEE is removing the existing compliance date of April 29,
2021, for this provision because an extension of time is no longer
necessary due to the current operational abilities of the accumulator
systems. The autoshear/deadman systems are functions not controlled by
surface personnel and are essentially considered failsafe. The bottles
need to be located subsea to ensure there is enough fluid and pressure
to operate the associated respective functions. BSEE revised final
paragraph (a)(4) by clarifying that the operator must have the ROV
intervention capability to close the identified BOP components. This
revision is based on comments received and will help ensure that the
BOP components can be properly functioned, if necessary, through the
use of an ROV hot stab. BSEE emphasizes that the response times are a
critical function of the ROV capabilities; BSEE does not want to limit
the options available to function the required BOP components. The use
of flying leads, a Subsea Accumulator Module (SAM) unit, or a
[[Page 21953]]
high flow ROV can all meet the required component closing time. This
revision is consistent with a BSEE Q and A posted on BSEE's website at
https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule.
    BSEE also revised paragraph (a)(6)(iv) by adding ``and an EDS
mode'' after ``functions.'' This revision is based on BSEE's
consideration of comments and is intended to clarify that an EDS mode
must be able to shear in an emergency situation. This is also
consistent with guidance provided in the BSEE Q and As posted on BSEE's
website at https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule.
    Based on consideration of comments, BSEE is revising paragraph
(a)(6)(v) to retain a modified version of the existing requirement that
the sequencing must allow a sufficient delay when closing two shear
rams in order to provide maximum sealing efficiency. Due to the various
BOP configurations across industry, BSEE wants to provide clarity about
how the BOP systems should function properly to achieve necessary
shearing and sealing during a well control event.
    Based on consideration of comments received, BSEE is revising
paragraph (a)(16)(i) to preserve a modified version of the existing
requirement for operators to have the capability to position the entire
pipe completely within the area of the shearing blade. This capability
cannot be another ram BOP or annular preventer, but these may be used
during a planned shear. BSEE recognizes that the technology exists to
help ensure the pipe is positioned within the shear surface to optimize
shearing capabilities. BSEE agrees with some commenters that, even
though this technology exists, the proposed rule's wholesale removal of
the positioning requirement did not specifically require the use of
such technology. BSEE is restoring the requirement to have the
capability to position the pipe within the shearing blade; however,
BSEE does not require this to be achieved with a separate mechanism and
allows use of the shear ram. As encouraged by Congress \32\ to ensure
that offshore operations promote safety and protect the environment in
a technically feasible manner, BSEE does not want to limit the use of
improved technological advancements in shear blade designs. BSEE
retained the compliance date of May 1, 2023, associated with the
original centering mechanism requirement.
---------------------------------------------------------------------------
    \32\ See n. 10, supra.
---------------------------------------------------------------------------
    BSEE is also revising paragraph (b)(1) to require operators to
submit a revised permit with a written statement from an independent
third party documenting the BOP system repairs and certifying that the
previous certification, required in Sec.  250.731(c), remains valid.
This revision is necessary for consistency with similar requirements
and revisions based on BSEE's consideration of comments received on
proposed Sec.  250.720. This revision will provide BSEE with additional
assurance that the related equipment is fit for service upon relatch of
the BOP to the well, and will reflect current BSEE practice. The type
of information required within this new submittal is similar to the
type of information operators submit with their original required BSEE
permits. This revision helps provide assurance that there is a current
certification of the BOP and provides consistent documentation of
recertification. BSEE includes the proposed language for paragraphs
(b)(2) and (3) in the final rule without change.
Summary of Comments
Comments Related to Proposed Sec.  250.734--(Dual Shear Rams)
    Summary of comments: Numerous commenters opposed the proposed
elimination of the existing requirement that both shear rams be capable
of shearing certain equipment in the hole and the proposal to replace
that requirement with a requirement that a combination of shear rams be
capable of shearing the equipment. The commenters asserted that this
proposed change would weaken the regulations and negatively impact
safety because it would not provide for a fully redundant shear ram as
a backup. The commenters also asserted that the proposed revision would
not account for situations in which one of the shear rams malfunctions.
One of these commenters requested an explanation from BSEE as to why
requiring only one shear ram to seal under MASP is acceptable. Another
commenter suggested that the regulations should prescribe a minimum
design basis capability for shear rams, along with a clear date for
compliance.
     Response: BSEE agrees with the comments about the utility
of redundant shear rams and is revising the proposed requirement in
Sec.  250.734(a)(1)(ii) that a ``combination of the shear rams must be
capable of . . .'' to preserve in the final rule the existing
requirement that ``[b]oth shear rams must be capable of . . . .'' This
revision will keep that portion of paragraph (a)(1)(ii) as it is in the
existing regulations. BSEE's analysis is set forth in further detail
above at Section III.B.3. BSEE may consider possible revisions to this
provision in future rulemakings.
Comments Related to Proposed Sec.  250.734(a)(3)(iii)--Compliance Date
for Shared Accumulator Bottles
    Summary of comments: A commenter questioned whether the reference
to the April 29, 2021, date is necessary if there is no longer a
requirement to have dedicated bottles in the accumulator system.
     Response: BSEE agrees with the commenter and removed the
reference to the compliance date of April 29, 2021 from final Sec.
250.734(a)(3)(iii). BSEE is removing the compliance date because no
extension of time is necessary due to the current operational
capabilities of the accumulator systems.
Comments Related to Proposed Sec.  250.734(a)(6)(v)--Shearing Risk
Assessment
    Summary of comments: A commenter suggested that a risk assessment
should be performed to ensure the fish of the sheared tubular is clear
of the blind ram while it is trying to close. For example, the
commenter asserted, if the drill pipe was in compression and the
sequence was casing shear ram (CSR) then BSR, the BSR would not be
closing on an open hole due to fact that it must be located above the
CSR. The commenter also requested clarification that, for emergency
functions, no additional steps can be taken (such as lifting the drill
pipe, hanging off on pipe rams, etc.).
     Response: BSEE does not agree with the suggestion that a
risk assessment should be required for shearing procedures. However, an
operator may use a risk assessment to help identify the actions by
personnel required in the well control plan in accordance with Sec.
250.710, What instructions must be given to personnel engaged in well
operations? The regulations also require that the well control plan
contain specific procedures regarding how operators would seal the
wellbore and shear pipe, including what to do when non-shearables are
located across a BSR.
    Summary of comments: A commenter suggested adding a requirement
that a single shear ram, or a combination of shear rams, must be
capable of performing the shearing tasks.
     Response: BSEE does not agree with the suggested revision.
BSEE is keeping the existing provision in Sec.  250.734(a)(1)(ii) that
requires both shear rams to be capable of shearing the specified
components. The suggested
[[Page 21954]]
revisions would not support a fully redundant shear ram in the event
one shear ram is unable to function. BSEE may evaluate revisions to
this provision in future rulemakings.
Comments Related to Proposed Sec.  250.734--Centering Pipe While
Shearing
    Summary of comments: Several commenters supported removing the
requirement to have a centering mechanism to center the drill pipe
prior to shearing. Those same commenters, however, disagreed with the
need for prescriptive design requirements for the shear ram, since
those requirements are already adequately addressed in ANSI/API Spec.
16A 4th Edition--Specification for Drill-through Equipment.
     Response: BSEE disagrees in part and agrees in part. BSEE
is retaining the requirement that operators have the capability to
position the pipe within the shearing blade; however, BSEE does not
require this to be achieved with a separate mechanism and will allow
this capability to be established with the shear ram. BSEE recognizes
that the technology exists to help ensure the pipe is positioned within
the shear surface to optimize shearing capabilities. The proposed rule,
however, did not specifically require the use of such centering
technology. As encouraged by Congress \33\ to ensure that offshore
operations promote safety and protect the environment in a technically
feasible manner, BSEE agrees with the importance of such capabilities,
but does not want to limit the use of improved technological
advancements in shear blade designs. For further analysis, see Section
III.B.2. BSEE currently incorporates ANSI/API Spec. 16A, Third edition
in Sec.  250.198.
---------------------------------------------------------------------------
    \33\ See n. 10, supra.
---------------------------------------------------------------------------
    Summary of comments: Numerous commenters disagree with eliminating
the requirement for a drill pipe centering mechanism. These commenters
cite numerous reasons for why they disagree, including that the need
for a centering mechanism was a lesson learned from the Deepwater
Horizon investigation, and that the existing shear rams that do not use
newer technology would not be able to center the drill pipe. One of
these commenters suggests that using the newer shearing blades that can
center a pipe should be a baseline requirement, and that a specific
timeframe for compliance should be established. The commenters also
question whether the agency has sufficient experience with implementing
the centering mechanism requirement of the 2016 WCR, because that
requirement is not currently in effect. One commenter agrees that a
centering mechanism is not necessary, but asserts that there should be
a requirement for the capability to shear the tubular in any position
in the wellbore.
     Response: BSEE agrees with the comments about the
importance of requiring pipe centering capabilities, and is retaining
the requirement that operators have the capability to position the pipe
within the shearing blade. However, BSEE will not find it necessary for
this to be achieved with a separate mechanism and will allow this
capability to be established with the shear ram (e.g., shear ram blade
design). BSEE recognizes the technology exists to help ensure the pipe
is positioned within the shear surface to optimize shearing
capabilities. The proposed rule, however, did not specifically require
the use of such centering technology. As encouraged by Congress \34\ to
ensure that offshore operations promote safety and protect the
environment in a technically feasible manner, BSEE agrees with the
importance of such capabilities, but does not want to limit the use of
improved technological advancements in shear blade designs. For further
analysis, see Section III.B.2.
---------------------------------------------------------------------------
    \34\ See n. 10, supra.
---------------------------------------------------------------------------
Comments Related to Proposed Sec.  250.734--Emergency Functions--EDS,
Autoshear/Deadman
    Summary of comments: One commenter asserts that the justification
for eliminating the requirement for the Emergency Disconnect Sequence
(EDS) system to be capable of closing two shear rams in sequence is
inadequate because the proposed revisions would not sufficiently
address how shear ram closure will be assured when an EDS occurs.
     Response: BSEE has revised paragraph (a)(6)(iv) by adding
``and an EDS mode'' after ``functions'' to provide clarity about how
the BOP systems should function properly to achieve necessary shearing
and sealing. This revision is based on BSEE's consideration of comments
and is intended to clarify that an EDS mode must be able to shear in an
emergency situation. BSEE wants to ensure optimal shearing and sealing
functionality during a well control event. Depending on the rig
operations, operators develop different EDS modes that would function
different BOP components at appropriate times. The selection of the EDS
mode and the specific sequencing of emergency functions should be
developed by the operator based on safety considerations and an
operational risk assessment. The EDS mode is a separate type of
emergency function from the autoshear/deadman. EDS is a function that
is manually initiated and operated by rig personnel and involves a
controlled disconnect.
    Summary of comments: Multiple commenters support the requirement
that the autoshear/deadman systems close, at a minimum, two shear rams
in sequence. A commenter proposed to add that: The sequence should
allow a sufficient delay to complete the shearing function before
sealing and that a risk assessment should be performed to ensure no
conditions exist where the sealing rams would be expected to shear
after the non-sealing ram shears, and no additional procedures, such as
lifting the drill pipe, can be performed for emergency systems.
     Response: BSEE has revised paragraph (a)(6)(v) to retain a
modified version of the existing requirement that the sequencing must
allow a sufficient delay when closing two shear rams in order to
provide maximum sealing efficiency. Due to the various BOP
configurations across industry, BSEE wants to provide clarity about how
the BOP systems should function properly to achieve necessary shearing
and sealing during a well control event. BSEE wants to ensure optimal
shearing and sealing functionality during a well control event.
Depending upon the rig operations, operators develop different EDS
modes that would function different BOP components at appropriate
times. The selection of the EDS mode and the specific sequencing of
emergency functions should be developed by the operator based on safety
considerations and an operational risk assessment. The EDS mode is a
separate type of emergency function from the autoshear/deadman. EDS is
a function that is manually initiated and operated by rig personnel and
involves a controlled disconnect. Operators may use a risk assessment
to help identify the actions required of personnel in the well control
plan in accordance with Sec.  250.710. The well control plan contains
specific procedures about how operators would seal the wellbore and
shear pipe, including what to do when non-shearables are located across
a BSR.
Comments Related to Proposed Sec.  250.734--Pipe Compression
    Summary of comments: Several commenters identified a potential pipe
compression issue when functioning the shear rams. Commenters asserted
that pipe compression could compromise
[[Page 21955]]
the proper functioning of the BOP, and a commenter adds that a better
understanding of dynamic fluid conditions inside the BOP is needed in
order to improve shearing and sealing capabilities. Another commenter
asserted that drill pipe compression along with a sequence of casing
shear ram then blind shear ram would preclude the blind shear ram from
closing on an open hole, and that operators must have the ability to
mitigate compression of the pipe stub between the shearing rams when
both shear rams are closed. The commenters question whether there have
been sufficient technological advances in BOP and shear ram design in
the two years since the adoption of the 2016 WCR, and the validity of
the assumption that there will be industry-wide adoption of the new
technologies if they exist.
     Response: As a general matter, BSEE agrees that
understanding the dynamic fluid condition inside the BOP is an
important research area. BSEE is requiring in Sec.  250.734(a)(16)(i)
of the final rule the capability to position the pipe within the
shearing blade, which will help mitigate the concerns about the ability
to shear pipe due to compression. BSEE recognizes that the technology
exists to help ensure the pipe is positioned within the shear surface
to optimize shearing capabilities. BSEE is retaining the requirement to
utilize such technology, but allowing for different technologies to
meet this requirement.
Comments Related to Proposed Sec.  250.734--Retesting Deadman
    Summary of comments: Multiple commenters disagreed with the
requirement to retest the deadman system when the system has not been
repaired or affected by a suspension of operations. The commenters
asserted that retesting the deadman subsea after a successful surface
certification is not necessary every time the BOP or LMRP is latched to
the wellhead, and that the previous test is sufficient to demonstrate
the system's proper functioning when the system has not been modified.
The commenters assert that testing the deadman system in such
situations presents unnecessary risks.
     Response: BSEE disagrees. When the functional system is
disconnected, it is important to ensure that the emergency systems are
completely functional upon reconnection of that system. BSEE has
determined that this requires retesting upon relatch.
    Summary of comments: One commenter is concerned with allowing
operators to conduct the deadman test at a low psi, so long as
operators end the test with an acceptable psi, because allowing such a
test procedure would place a significant amount of trust in industry
self-regulation.
     Response: BSEE is allowing the use of a 1,000 psi test for
the initial deadman test to verify functionality of the system. BSEE
will still require operators to fully pressure test the components used
within the deadman system according to Sec.  250.737(d)(4). BSEE will
oversee and enforce compliance with these testing requirements and will
not rely on industry self-regulation.
Comments Related to Proposed Sec.  250.734(a)(4)--ROV Intervention
    Summary of comments: Numerous commenters supported removing the
open function requirement from the ROV panel. However, the commenters
also requested clarity regarding whether the timing requirements could
be met by using only an ROV or by using a flying lead. These commenters
suggested aligning the timing requirements with those in API Standard
53 and prior references in the rule with respect to ROV capability.
     Response: BSEE is revising this section to clarify that
operators must have the capability to perform the required function in
the response times outlined in API Standard 53. This can be
accomplished with a flying lead or SAM unit, or the ROV. This
clarification is based on a BSEE Q and A related to the 2016 WCR. BSEE
agrees that the response times are the critical function of the ROV
capabilities. BSEE has not mandated a high capacity ROV, but rather
that the ROV hot stabs would accept the high flow via flying leads.
    Summary of comments: Some commenters expressed concern about the
reference to compliance with API RP 17H 2nd Edition, since API Standard
53 already covers the same requirement and the relevant receptacles are
not materially different from those addressed in ANSI/API RP 17H 1st
Edition.
     Response: BSEE disagrees with the assertion that BSEE
should only reference API Standard 53. API Standard 53 does not contain
all of the same information or the same level of specificity covered
under API RP 17H.
    Summary of comments: One commenter opposed removing the requirement
that ROVs be capable of opening each shear ram, ram lock, or pipe ram,
since the ability to temporarily open the ram or lock may be necessary
for well control intervention. The commenter also disagreed with
relying on API Standard 53 because industry standards can be weakened,
whereas standards established by the agency and set in regulations can
be more stringent.
     Response: As more thoroughly described in the preamble to
the proposed rule, the most critical ROV functions would be to close
the BOP components and seal the well for well control purposes. This
regulatory revision does not limit the operator's ability to include
the open function on the ROV panel. With respect to the comments
regarding reliance on industry standards, BSEE incorporates a specific
edition of a standard; when a standard is updated by the standards
organization, BSEE evaluates the updated edition and would only
incorporate the updated edition as appropriate. In other words, BSEE
only incorporates into its regulations (through public rulemaking)
those standards that it has determined to be adequate and appropriate,
and the regulatory force and content of those incorporated standards
can only be altered through subsequent rulemaking. BSEE also utilizes
industry standards to establish foundational requirements which it can
supplement.
Comments Related to Proposed Sec.  250.734--Accumulator Systems and
Capacity
    Summary of comments: A commenter supported BSEE's proposed
revisions to allow sharing of bottles among emergency and secondary
control system functions to secure [acy] wellbore. The commenter
recommended that BSEE reference the [Acy][Rcy][Iukcy] Spec. 16D,
Specification for Control Systems for Drilling Well Control Equipment
and Control Systems for Diverter Equipment, Second Edition,
incorporated by reference in Sec.  250.198 related to controls systems,
and clarify whether sharing bottles would be [acy] sufficiently
redundant system to allow for emergency use.
     Response: BSEE agrees with the commenter generally about
the use of API Spec. 16D related to control systems; however, BSEE
disagrees that a reference to API Spec. 16D is necessary in this
section. BSEE already incorporates API Spec. 16D and API Standard 53,
and requires sufficient accumulator volume for the emergency
operations. The accumulator requirements are covered under Sec.
250.735.
    Summary of comments: A commenter asserted that BSEE's proposed
revisions to the accumulator requirements in Sec.  250.734(a)(3) would
reduce safety and severely weaken the ability of the subsea BOP system
to function in the
[[Page 21956]]
event of a lost connection to the surface rig. The commenter further
asserted that BSEE does not explain how removing the reference to the
subsea location of accumulator capacity would ensure that the
accumulator system could adequately function if there is a loss of the
power fluid connection to the surface, and that BSEE therefore must
continue to require that the necessary accumulator capacity be located
subsea. The commenter recommended that BSEE should retain the
requirement in Sec.  250.734(a)(3)(iii) for dedicated bottles.
     Response: BSEE agrees with the commenter and has revised
the language in final Sec.  250.734(a)(3)(iii) to clarify that the
accumulator capacity for autoshear/deadman must be located subsea. The
autoshear/deadman systems are considered failsafe systems that function
automatically in emergency situations and do not require surface
personnel action to function. Consistent with the current requirements,
the accumulator bottles that function those systems need to be located
subsea to ensure there is enough fluid and pressure to operate the
associated functions. This is a clarification to ensure there is no
confusion about where the required fluid and pressure must reside to
operate the autoshear/deadman emergency functions. Autoshear/deadman
are separate triggers to operate the same equipment and would not be
functioned together. Each emergency function has different criteria
that must be met before it will automatically function.
Comments Related to Proposed Sec.  250.734--Accumulators and Industry
Standards
    Summary of comments: Multiple commenters asserted that BSEE should
explain why allowing operators to simply use industry standards, which
do not necessarily require accumulators, is justified.
     Response: BSEE disagrees with the commenters. BSEE
incorporates industry standards, not all of which include accumulator
specifications, into the regulations as required by the NTTAA. Before
incorporating standards, BSEE thoroughly evaluates them for adequacy
and appropriateness. BSEE also supplements those standards with its own
regulatory requirements related to operations and equipment, as we do
in the case of accumulators.
Comments Related to Proposed Sec.  250.734--Centering Pipe While
Shearing
    Summary of comments: A commenter asserted that this section refers
to the use of ``newer shearing blades'' which [scy][acy]n center
[rcy][iukcy][rcy][iecy] as justification for the removal of
requirements to verify that testing is performed [ocy]n the outermost
edges of the shearing blades of the shear ram positioning mechanism.
The commenter asserted that this assumes that these newer blades, which
are not clearly defined, are used universally. Multiple commenters
recommended that BSEE should clarify that the newer shearing blades
that [scy][acy]n center [rcy][iukcy][rcy][iecy] are required and that
BSEE should give [acy] specific time frame for operators to comply.
     Response: BSEE generally agrees with the commenters and
has retained (with modifications) provisions in Sec.  250.734(a)(16)(i)
that require operators to have the capability to position the entire
pipe completely within the area of the shearing blade. This capability
can be achieved by a separate mechanism or by ram design. As encouraged
by Congress \35\ to ensure that offshore operations promote safety and
protect the environment in a technically feasible manner, BSEE agrees
with the importance of positioning capabilities, but does not want to
limit the technology that can be used to meet those requirements.
---------------------------------------------------------------------------
    \35\ See n. 10, supra.
---------------------------------------------------------------------------
What associated systems and related equipment must all BOP systems
include? (Sec.  250.735)
    This section of the existing regulations details the associated
systems and related equipment that all BOP systems must include. The
required items include an accumulator system; an automatic backup to
the primary accumulator-charging system; at least two full BOP control
stations; choke, kill, and fill-up lines; and locking devices.
Summary of Proposed Revisions
    BSEE proposed to revise paragraph (a) by clarifying that the
accumulator system must have the fluid volume capacity and appropriate
pre-charge pressures in accordance with API Standard 53. These proposed
revisions would provide consistency with API Standard 53 and conform to
the other proposed accumulator system revisions in Sec.  250.734.
Summary of Final Rule Revisions
    BSEE received and considered comments on the proposed revisions and
includes the proposed language in the final rule without change.
Summary of Comments
    Comments Related to Sec.  250.735(g)(2)(i)--Remotely Operated
Locking Devices
    Summary of comments: A commenter suggested that BSEE remove the
requirements for remotely operated locking devices on surface BOP blind
shear rams that are required by April 29, 2019. The commenter asserted
that, while these types of devices are necessary by design for subsea
BOPs, due to the inability to manually access the rams and engage
locking devices, manual access is not an issue on surface BOPs and the
manual locking devices that have been successfully utilized for decades
are sufficient to allow securing of these surface rams when necessary.
The commenter asserted that there are multiple surface BOP sizes and
ratings that would require these modifications and expressed concerns
about space issues to accommodate the modified locking systems,
depending on the rig size and type being utilized.
     Response: BSEE did not propose or discuss changes to this
provision in the proposed rule and as such would not be in a position
to make the suggested changes in this final rule. Regardless, BSEE
disagrees with the suggestion about removing the remotely locking
device requirement for surface BOP blind shear rams. BSEE's position is
that a manual lock would require rig personnel to enter a potentially
hazardous area and that a remotely locking device would help limit
personnel exposure to the potentially hazardous area, if a shearing
event is necessary.
    Summary of comments: A commenter requested clarification in
paragraph (g)(2) that a pilot-operated check valve is considered a
remotely operated locking device. The commenter suggested that the rule
should be modified to read as follows: ``(2) For surface BOPs: (i)
Remotely operated locking devices (i.e., pilot operated check valve)
must be installed on blind shear rams no later than April 29, 2021. . .
.''
     Response: BSEE did not propose or discuss changes to this
provision in the proposed rule, and as such would not be in a position
to make the suggested changes in this final rule. Regardless, BSEE does
not want to limit the types of devices (e.g., pilot operated check
valve) that can be used for locking. Operators should contact the
appropriate BSEE District Manager if there are any questions about the
specified use of this type of equipment.
[[Page 21957]]
What are the requirements for choke manifolds, kelly-type valves inside
BOPs, and drill string safety valves? (Sec.  250.736)
    This section of the existing regulations describes the requirements
for the installation, use, and capability of choke manifolds, BOP
systems, valves, pipes, and flexible hoses appropriate for the working
pressure and temperature and operating conditions.
Summary of Proposed Revisions
    BSEE proposed to revise paragraph (d)(5) by including equipment
requirements for the safety valve when running casing with a subsea
BOP. This revision would specify that the safety valve must be
available on the rig floor if the length of casing being run exceeds
the water depth, which would result in the casing being across the BOP
stack and the rig floor prior to crossing over to the drill pipe
running string. This revision would provide clarity and consistency
throughout BSEE permitting and minimize the number of alternate
procedure or equipment requests submitted to BSEE.
Summary of Final Rule Revisions
    BSEE received a few comments in general support of the proposed
revisions to this section and is including the proposed language in the
final rule without change.
What are the BOP system testing requirements? (Sec.  250.737)
    This section of the existing regulations details the pressure test
frequency, procedures, and duration for BOP systems. This section also
contains additional testing requirements, including compliance with API
Standard 53, using water to test a surface BOP system, stump testing a
subsea BOP system, performing an initial subsea BOP test, alternating
testing pods between control stations, as well as pressure and function
tests of various components.
Summary of Proposed Revisions
    BSEE solicited comments in the proposed rule ``on whether the BOP
testing interval should be 7 days, 14 days, or 21 days for all types of
operations including drilling, completions, workovers, and
decommissioning,'' as well as ``on the specific cost and operational
implications of each testing interval.'' \36\ BSEE proposed to revise
paragraph (b) to clarify the BOP system pressure testing requirements.
These proposed revisions included clarification that the test rams and
non-sealing shear rams do not need to be pressure tested, because the
non-sealing shear rams are not pressure holding components and the test
ram is an inverted ram that is not utilized for well control purposes.
BSEE also proposed to revise paragraph (b)(2) to reflect the current
BSEE policy for conducting the high-pressure test for specific
components. For example, some of the proposed revisions included
specific procedures and testing parameters for initial equipment
pressure testing, as well as provisions for subsequent pressure testing
on the same equipment.
---------------------------------------------------------------------------
    \36\ 83 FR 22143 (May 11, 2018).
---------------------------------------------------------------------------
    In the proposed rule, BSEE proposed to revise paragraphs (d)(2)(ii)
and (d)(3)(iii) by removing the requirement to submit test results to
BSEE where BSEE is unable to witness testing. These proposed revisions
would significantly reduce the number of submittals to BSEE and
minimize the associated burden for BSEE to review those submittals. If
BSEE is unable to witness the testing, BSEE may access the testing
documentation upon request, in accordance with Sec. Sec.  250.740,
250.741, and 250.746.
    BSEE proposed to revise paragraph (d)(3)(iv) by removing ``test
and[.]'' BSEE would remove this term to minimize confusion regarding
verification and testing. In this instance, verification of closure
qualifies as testing the ROV functions. The purpose of the stump test
is to help ensure the BOP components and control systems can function
properly before being utilized on a well.
    BSEE proposed to revise paragraph (d)(3)(v) to clarify that
pressure testing of each ram and annular on the stump test is only
required once. This revision would help ensure that the testing of BOP
components during stump testing would limit unnecessarily duplicative
pressure testing of each ram or annular. It is unnecessary to pressure
test a ram or annular multiple times during stump testing if that
component has already been successfully pressure tested, verifying
proper functionality.
    BSEE proposed to revise paragraph (d)(4)(i) to clarify that the
initial subsea BOP test on the seafloor would need to begin ``within 30
days of the stump test.'' BSEE receives many questions about the timing
of the initial subsea test and, as written, the regulation was
ambiguous regarding exactly what needed to occur within the 30 days.
BSEE proposed this revision to clarify that the testing must begin
within 30 days of the stump test. BSEE wants to ensure that the time
between the stump testing and the initial subsea test is minimal to
help confirm that all of the BOP components can properly function upon
installation on the well.
    BSEE proposed to revise paragraph (d)(4)(iii) to include annulars
in the pressure testing requirements of paragraphs (b) and (c) of this
section. This proposed revision would not alter the current testing
requirements for annulars and would provide clarity for where to find
them.
    BSEE proposed to revise paragraph (d)(4)(v) to clarify the initial
subsea pressure testing requirements to confirm closure of the selected
ram through an ROV hot stab. This revision would require the operator
to confirm closure through a 1,000 psi pressure test held for 5
minutes. This proposed revision would codify BSEE policy for pressure
testing the selected ram through the ROV hot stabs. BSEE has concluded
that testing to higher pressures is not necessary for this circumstance
because the intended purpose of this test is to verify operability of
the ROV hot stab to close the selected ram. Selected rams must be
pressure tested according to other regularly required pressure testing
intervals and prior to commencing well operations.
    BSEE proposed to remove existing paragraph (d)(4)(vi) because the
testing requirements of the selected ram would now be covered under
proposed paragraph (d)(4)(v).
    BSEE also proposed to revise paragraph (d)(5) by clarifying the
alternating testing schedules of control stations and pods. These
proposed revisions help ensure that operators develop a testing
schedule that provides for alternating testing between the control
stations, and also between the pods for subsea BOPs. The intended
result of alternating the testing is to ensure that each control
station, and each pod for subsea, can properly function all required
BOP components. BSEE proposed to revise paragraph (d)(12)(iv) by
clarifying that, during the deadman test on the seafloor, operators are
not required to indicate the discharge pressure of the subsea
accumulator throughout the entire test. These revisions would require
that the remaining pressure be documented at the end of the test, to
help verify the proper accumulator settings required to function the
specific critical BOP components.
    BSEE proposed to revise paragraph (d)(12)(vi) to clarify the
pressure testing requirements of the 2016 WCR, and to confirm closure
of the BSR(s) during the autoshear/deadman and EDS testing. This
proposed revision would require confirmation of closure through a 1,000
psi pressure test held for 5 minutes.
[[Page 21958]]
Testing to higher pressures is not necessary for this circumstance
because the BSR(s) will be pressure tested according to other regularly
required pressure testing intervals and prior to commencing well
operations.
    BSEE proposed to add paragraph (d)(13) setting forth exceptions
from the requirements for pressure testing the choke and kill side
outlet valves. This proposed addition would codify BSEE policy and
provide consistency for permitting throughout the Regions and Districts
without meaningfully reducing safety or environmental protection.
Summary of Final Rule Revisions
    BSEE received and considered comments on the proposed revisions and
includes most of the proposed language in the final rule without
change, except for the following revisions. Based on comments received,
BSEE is redesignating existing paragraph (a)(4) as (a)(5) and adding
new paragraph (a)(4) to allow the use of a 21-day BOP pressure testing
frequency, in lieu of meeting the schedule established in paragraph
(a)(2), if certain criteria are met and BSEE approves an operator's 21-
day BOP testing frequency request. BSEE is requiring operators to
demonstrate, in the 21-day BOP testing frequency request, that they
have developed a BOP health monitoring plan that includes certain
system capabilities. BSEE is requiring the BOP health monitoring plan
to include condition monitoring tools that are able to provide
continuous surveillance of sensor readings from the BOP control system,
real-time condition analysis and displays, functional pressure signal
analysis, and historical sensor data. The plan also must include
failure propagation analysis and a failure tracking and resolution
system to identify recurring problems. BSEE is also requiring the
operators to submit quarterly reports of the data collected to the BSEE
Regional Supervisor, District Field Operations.
    BSEE is revising paragraph (b)(3) by adding ``or APM'' after APD.
This addition is based on BSEE's further analysis of the proposed rule
and provides clarification. This revision codifies longstanding BSEE
practice of identifying the applicable operational permit that is used
for specific types of operations.
    Based on comments received, BSEE is revising paragraph (c) to
clarify that the use of a digital recorder is an acceptable method for
documenting the duration of pressure tests. This revision is only a
minor clarification. BSEE already allows the use of a digital recorder
on subsea BOP tests and this revision codifies current practice.
    BSEE is revising paragraph (d)(10) to address the 21-day BOP
pressure testing option in new paragraph (a)(4). If BSEE approves an
operator's request to use a 21-day BOP test frequency in accordance
with paragraph (a)(4), then BSEE will allow the operator to function
test its shear ram(s) BOPs every 21 days in accordance with the terms
of that approval.
    BSEE is also making minor corresponding revisions to paragraph
(d)(13)(i) to remove the reference to the 14-day BOP testing and to
clarify that the specified procedure applies to BOP testing,
irrespective of the BOP testing frequency.
Summary of Comments
Comments Related to Sec.  250.737(a)(2)--21-Day BOP Testing Frequency
    Summary of comments: BSEE received multiple comments supporting and
opposing any changes to the BOP testing frequency, as discussed in
sections III and IV of this preamble. However, a commenter recommended
that BSEE allow a 21-day testing frequency if additional requirements
were put in place to help provide assurances of BOP functionality,
equivalent performance, and operational risk as under a 14-day BOP
testing frequency. The commenter recommended that BSEE require
condition monitoring tools, failure propagation analysis, and a failure
tracking and resolution system. In addition, the commenter suggested
that if BSEE allowed a 21-day BOP testing frequency, it should require
the operator to collect lifecycle data related to the reliability of
performance of functioned components, determine whether there is a
relationship between usage and deterioration, and understand the impact
of testing frequency on reliability. In addition, a commenter asserted
that the proposed rule did not identify to which technologies BSEE was
referring with regard to possible revisions to BOP system testing
requirements, or under what circumstances or based on what information
BSEE might amend or restructure Sec.  250.737.
     Response: BSEE agrees with the commenter's recommendations
about allowing a 21-day BOP testing frequency if there are additional
requirements to help provide assurance of equivalent performance and
operational risk when compared to a 14-day BOP testing frequency. In
the final rule, BSEE is allowing the use of a 21-day BOP testing
frequency. However, before an operator can use this option, it must
submit a request to BSEE for approval to use a 21-day BOP testing
frequency. In the 21-day BOP testing frequency request, BSEE is
requiring the operator to develop a BOP health monitoring plan that
includes the use of condition monitoring tools capable of providing
continuous surveillance of sensor readings from the BOP control system,
real-time condition analysis and displays, functional pressure signal
analysis, and trending capabilities of the sensor data. The plan must
include failure propagation analysis and a failure tracking and
resolution system to identify recurring problems. BSEE is also
requiring operators to submit quarterly reports of the data collected
to the BSEE Regional Supervisor, District Field Operations. BSEE will
review this data to help ensure compliance with the requirements of the
regulations and help evaluate the effectiveness and appropriateness of
the 21-day testing frequency. BSEE disagrees with the assertion that it
did not identify clearly enough the types of actions it was
considering. The proposed rule solicited comments on a number of issues
related to this topic, along with context for the solicitation (see 83
FR 22143) and BSEE's final rule is based on its analysis of the input
received in response to that solicitation and other elements of the
record. Further analysis of BSEE's action on this issue is found at
Sections III.B.5 and IV.C of this preamble.
Comments Related to Proposed Sec.  250.737(b)--BOP Testing Validity
    Summary of comments: Multiple commenters recommended that BSEE
align the regulations with the testing requirements of API Standard 53
and allow the use of alternative pressure testing systems that can
determine test validity in less than 5 minutes. The commenters
requested that BSEE clarify the statement in paragraph (b) that states
``. . . test must hold pressure long enough to demonstrate the tested
component(s) holds the required pressure.''
     Response: BSEE disagrees with the recommendation that BSEE
should allow the use of systems that can test in less than 5 minutes.
More research and consistency is necessary before BSEE will be in a
position to allow pressure testing systems that demonstrate test
validity in less than 5 minutes. BSEE also disagrees with the
commenters' request to clarify that the test must hold pressure long
enough to demonstrate the tested component(s) holds the required
pressure, because more research and consistency is necessary before
BSEE
[[Page 21959]]
will be in a position to validate alternative timeframes.
Comments Related to Proposed Sec.  250.737(d)--Verification of ROV
Intervention Functions
    Summary of comments: Multiple commenters recommended that any
additional installed ROV intervention functions must be verified per
the equipment owner's maintenance program, but not to exceed once per
year.
     Response: BSEE disagrees with this recommendation. BSEE
wants to ensure that operators verify all ROV hot stabs prior to
commencing operations on each well.
Comments Related to Proposed Sec.  250.737(d)(2) and (3)--Review of
Testing Results
    Summary of comments: Multiple commenters opposed the proposed
removal of the requirement that the operator must provide the initial
test results to the District Manager if BSEE cannot witness testing.
The commenters expressed concerns with removing the real-time
supervision of the methods used to conduct inspections of well control
system components, asserting that the change would allow too much
discretion to operators, and would remove a safeguard that prevents
inadequate testing, thus reducing safety.
     Response: BSEE disagrees with the assertion that the
removal of the requirement to provide the initial test results to BSEE,
when BSEE is unable to witness testing, reduces safety. BSEE reviews
the test results during routine inspections of facilities. The operator
is still required to make the results available to BSEE upon request
for verification. BSEE also retains the option for BSEE to witness the
testing.
Comments Related to Proposed Sec.  250.737(d)(3)(iv)--Testing of ROV
Panels During Stump Testing
    Summary of comments: A commenter asserted that, since BSEE proposed
that BOP ROV panels should not be required to have open functions, BSEE
should remove the requirement to test systems that currently have open
functions for rams on the ROV panels. The commenter was concerned that
operators with systems that already have open functions for rams will
remove them so they do not have to test.
     Response: BSEE disagrees with the comment. The referenced
testing requirement is applicable to the stump test, which is performed
before the BOP is installed. The stump test is used to verify the
functionality of the ROV components while on the surface, before the
equipment is run subsea and latched onto the well. BSEE wants to ensure
that the equipment, as configured, is operational before it is run
subsea.
Comments Related to Proposed Sec.  250.737(d)(4)(v)--Verifying Closure
of Rams Through ROV Hot Stabs
    Summary of comments: A commenter asserted that although the
proposed method for confirming closure of the rams may be a valid
method of verifying closure, there are other methods that should be
approved, such as position indicators, and a combination of parameters
such as volume, time, and a pressure spike at the end of travel. The
commenter asserted that the pressure of 1,000 psi seems completely
arbitrary and had been specifically rejected by BSEE in the alternate
procedure/departures section of the August 17, 2016 WCR presentation in
Houston, Texas.
     Response: BSEE disagrees with the recommendation to accept
use of the identified methods to confirm closure of the rams. More
research and data is necessary to fully evaluate those methods and BSEE
may include those methods in future rulemakings, depending on future
findings. BSEE is allowing the use of 1,000 psi pressure for the ROV
test because that is sufficient to verify functionality of the system.
The BOP system and each BOP component are still required to be fully
pressure tested according to Sec.  250.737(b).
Comments Related to Proposed Sec.  250.737(d)(5)(ii)--Testing of Remote
Panels
    Summary of comments: Multiple commenters recommended that BSEE
revise the regulations to allow additional alignment between the
proposed rule and API Standard 53, Section 7.6.5.1.4, which states,
``[i]f installed, remote panels where all BOP functions are not
included (e.g. lifeboat panels, etc.) shall be function tested in
accordance with the equipment owner's procedures.'' The commenters
asserted that the inclusion of the phrase ``in accordance with the
equipment owner's procedures'' in the regulations would allow the
operator to conduct the test with the BOP on-deck and would not alter
the effectiveness or intent of the proposed BSEE text.
     Response: BSEE disagrees with the comment. Operators must
function test the remote panels upon the initial BOP test to ensure
functionality with the complete installed system. On-deck testing alone
is not sufficient.
Comments Related to Proposed Sec.  250.737(d)(3)(v)--Stump Test
Procedures
    Summary of comments: Multiple commenters expressed concerns with
the proposed revisions to Sec.  250.737(d)(3)(v) that stated ``pressure
testing of each ram and annular component is only required once.'' The
commenters further expressed concerns with BSEE's proposed rationale to
eliminate ``unnecessarily duplicative pressure testing'' and to limit
the risk of component wear. Section 250.737(c) requires repeat testing
if a pressure test under Sec.  250.737(b) and (c) is not successful.
The commenters asserted that the proposed revision to Sec.
250.737(d)(3)(v) does not appear to take into account the possibility
of a failed test and the need for a repeat test.
    The commenters further asserted that the Department also proposed
to weaken Sec.  250.737(d)(5)(i)(A) and (B) by reducing BOP control
station testing from weekly to every other week and that this change
would cut in half the BOP control station testing frequency.
     Response: BSEE disagrees with the assertion that the
proposed revisions would weaken the regulations. Paragraph (d)(3)(v)
applies to the stump testing which is conducted prior to the subsea BOP
stack being latched onto the well. The stump test is the main
opportunity to identify and correct issues with the stack before
deployment. There is additional required testing once the BOP stack is
installed, plus regularly scheduled testing during operations while the
BOP is latched onto the well. Section 250.737(c) requires a successful
pressure test of the required components and applies to paragraph (d).
Accordingly, paragraph (c) states that ``If the equipment does not hold
the required pressure during a test, you must correct the problem and
retest the affected component(s).''
Comments Related to Proposed Sec.  250.737(d)(12)(iv)--Deadman Test
Procedures
    Summary of comments: A commenter disagreed with the proposed
changes to the deadman system test procedures. The commenter expressed
concerns with the proposed revision that would only require operators
to record starting and stopping pressure to determine deadman closing
efficiency.
     Response: BSEE disagrees that there is any basis for
concern. In paragraph (d)(12)(iv) testing is used to verify that there
is sufficient accumulator capacity for the required BOP deadman
functions. Documenting the final pressure on the subsea accumulator
[[Page 21960]]
after a deadman test is sufficient to verify that the subsea
accumulation system can deliver the necessary fluid volume to execute
this emergency operation. This verification demonstrates the system is
adequately deployed in the application on the well for safe operation.
Comments Related to Proposed Sec.  250.737(d)(12)(vi)--Deadman Test
Procedures
    Summary of comments: A commenter asserted that BSEE's proposed
revision to paragraph (d)(12)(vi) would place a significant amount of
trust in industry self-regulation because the revision seems to allow
for operators to conduct the deadman test at low pounds per square inch
(psi) during the test, as long as operators complete the test with an
acceptable psi. The commenter recommended that BSEE provide
justification for the revisions.
     Response: BSEE is allowing the use of a 1,000 psi test for
the initial deadman test because that is sufficient to verify
functionality of the system. The components utilized within the deadman
system are still required to be fully pressure tested according to
Sec.  250.737(d)(4). BSEE will oversee compliance with and enforcement
of these testing requirements and will not rely on industry self-
regulation.
What must I do in certain situations involving BOP equipment or
systems? (Sec.  250.738)
    This section of the existing regulations describes actions that
operators must take when certain situations occur with BOP systems,
such as if the BOP equipment does not hold the required pressure during
a test or if the BOP control station or pod does not function properly.
Summary of Proposed Revisions
    BSEE proposed to revise paragraphs (b), (i), (m), and (o) by
replacing the references to BAVOs with references to an independent
third party throughout.
    BSEE proposed to revise paragraph (f) to clarify the testing
requirements implemented by the 2016 WCR necessary to verify the
integrity of the affected casing ram or casing shear ram and
connections. This proposed revision would codify BSEE policy to allow
the pressure testing to test the pressure of the BOP component above
this ram, as specified in the approved permit.
    BSEE also proposed to revise paragraph (m) to replace the term
``well-control equipment'' with ``circulating or ancillary equipment.''
This revision would eliminate confusion arising from the use of
conflicting terms that may have different meanings throughout the
regulations.
Summary of Final Rule Revisions
    BSEE received and considered comments on the proposed revisions and
generally includes the proposed language in the final rule without
change, except for the following revisions. BSEE is reversing the order
of existing paragraphs (b)(3) and (b)(4), and redesignating them
appropriately. This change was necessary to avoid confusion about the
process for submitting and then getting BSEE approval and reflects the
logical order for the process. BSEE is revising final paragraph (b)(3)
with conforming edits to Sec. Sec.  250.720 and 250.734, to require
operators to submit a revised permit instead of a report. The revised
permit must include a written statement from an independent third party
documenting the BOP repairs, replacement, or reconfiguration and
certifying that the previous certification under Sec.  250.731(c)
remains valid. This revision is necessary to be consistent with the
independent third-party certification comments on proposed Sec.
250.720 and BSEE's final approach to that provision. This revision will
provide BSEE with additional assurance that the relevant BOP system is
fit for service upon relatch and reflects current BSEE practice. The
independent third-party certification contains the same type of
information operators submit with their original required BSEE permits.
This revision provides assurance that there is a current certification
of the BOP and provides consistent documentation of recertification.
    BSEE removes the language ``with the new, repaired, or reconfigured
BOP.'' from existing paragraph (b)(3); redesignated by this final rule
as paragraph (b)(4) because they are redundant to the updated
introductory language for paragraph (b).
Summary of Comments
Comments Related to Proposed Sec.  250.738(f)--Shell Test for Casing
Rams
    Summary of comments: Multiple commenters agreed with the intent of
this revision, but requested that BSEE clarify the timing and location
of the test.
     Response: BSEE disagrees that the timing and location of
the shell test needs to be clarified. The regulations state that the
operator must conduct the shell test before running casing.
Comments Related to Sec.  250.738--Riser Gas Handler Systems
    Summary of comments: A commenter recommended requiring the use of a
riser gas handler system for all rigs with marine risers. The commenter
asserted that requiring the use of riser gas handler systems would
safely manage gas in the marine riser, prevent future incidents like
Deepwater Horizon, and prevent environmental damage.
     Response: BSEE disagrees with the recommendation to
require the use of a riser gas handler system on all wells. Operators
are currently allowed to use riser gas handler systems pursuant to this
section. However, it is beyond the scope of this rulemaking to require
it for all rigs with marine risers. BSEE may evaluate the use of riser
gas handler systems for possible inclusion in future rulemakings.
Comments Related to Proposed Sec.  250.738(b)--Reverification of BOP
System
    Summary of comments: A commenter recommended that BSEE should
consider requiring a report from an independent third party if
operations are interrupted due to the events listed in Sec.
250.720(a)(1). The commenter asserted that the events listed in Sec.
250.720(a)(1) would invalidate a verification submitted under
Sec. Sec.  250.732(c) and 250.731(d) and that consideration should be
given to including or moving these requirements to Sec.  250.738, as
well.
     Response: BSEE agrees with the commenter, in part, and
added a requirement for submitting a revised permit with a written
statement from an independent third party certifying that the previous
certification under Sec.  250.731(c) remains valid. BSEE also made
corresponding edits to similar requirements in Sec. Sec.  250.734 and
250.738. These revisions help ensure that the BOP remains fit for
service at the same location.
What are the BOP maintenance and inspection requirements? (Sec.
250.739)
    This section of the existing regulations details the maintenance
and inspection requirements for BOPs. The requirements include: Meeting
or exceeding minimum thresholds for maintenance and inspection; a
complete breakdown and physical inspection of the BOP every 5 years; a
visual inspection of the surface BOP system on a daily basis; and
training of all personnel who maintain, inspect, or repair BOPs.
[[Page 21961]]
Summary of Proposed Revisions
    BSEE proposed to revise paragraph (b) by replacing ``complete
breakdown and detailed physical inspection'' with a ``major, detailed
inspection,'' identifying examples of well control system components,
replacing references to the BAVO with references to an independent
third party, and replacing the requirement to have a BAVO present
during each inspection with a requirement for an independent third
party to review inspection results.
    BSEE proposed replacing ``complete breakdown and detailed physical
inspection'' with a ``major, detailed inspection'' to correct the
industry misconception, prevalent since the promulgation of the 2016
WCR, that each component of the BOP must be dismantled to its smallest
possible part. This was never the intent behind this provision of the
2016 WCR and the proposed revisions would clarify BSEE's positions on
the 2016 WCR requirement and resolve perceived ambiguities, without
substantively altering the inspection requirement.
    BSEE also proposed to remove the requirement for the BAVO to be
present during each inspection and replace it with a requirement that
an independent third party review the inspections results. BSEE expects
the independent third party to review the documentation of the
inspections to help ensure that the appropriate entities accurately and
appropriately complete the activities. The proposed revisions would
ease the logistical and economic burdens derived from the 2016 WCR
requirement to have the BAVO onsite at all times during all
inspections.
Summary of Final Rule Revisions
    BSEE received and considered comments on these provisions of the
proposed rule and includes the proposed language in the final rule
without change. BSEE received comments in general support and
opposition to the proposed changes, in addition to the following
comments.
Summary of Comments
Comments Related to Proposed Sec.  250.739--BOP Complete Breakdown
Versus Major Detailed Inspection
    Summary of comments: Multiple commenters asserted that the proposed
rule would make a number of provisions more confusing. For example, one
proposed revision to Sec.  250.739 replaces the requirement for regular
``complete breakdowns and detailed physical inspections'' with a
requirement for ``major, detailed inspections.'' The commenters
asserted that changing this phrase makes the associated requirements
less specific, adds ambiguity to otherwise clear language, and leaves
some testing requirements open for interpretation, which cannot ensure
the safety and environmental protection provided by BOPs. The
commenters suggested that BSEE should be more specific in its proposed
regulation in explaining how far the BOP must be broken down to meet an
acceptable BOP ``major, detailed'' 5-year inspection.
     Response: BSEE disagrees with the assertion that the
proposed language adds ambiguity regarding what is required for the 5
year inspection. This revision is designed to provide clarity and
eliminate misconceptions regarding the existing inspection requirement,
not to substantively alter that requirement. BSEE expects this 5-year
inspection to be conducted in the same manner, whether it is called a
complete breakdown and detailed physical inspection or a major detailed
inspection. This revision is consistent with the guidance posted on the
BSEE website at https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule. As discussed in the proposed rule, BSEE
used the term ``major detailed inspection'' to correct the industry
misconception prevalent since the promulgation of the 2016 WCR that
each BOP component must be dismantled to its smallest possible part.
This was never the intent behind this provision of the 2016 WCR. These
revisions clarify BSEE's position on the 2016 WCR requirements and
resolve perceived ambiguities, without substantively altering the
inspection requirement.
    Summary of comments: Multiple commenters supported the proposed
clarification to the rule. The commenters asserted that the proposed
language codifies clarification previously given by BSEE regarding the
intent of the phrase ``complete breakdown'' in the current regulation
and also ensures that proven industry practice to phase recertification
as part of a continuous maintenance and inspection program is
acceptable. The commenters also asserted that this approach is
consistent with the requirements of API Standard 53 and that BSEE
appropriately retained the requirement that inspections be documented
and reviewed by an independent third party.
     Response: BSEE agrees with the commenter and no changes
are necessary.
Comments Related to Proposed Sec.  250.739--BAVO Present During
Inspections
    Summary of comments: Multiple commenters asserted that BSEE
proposed to weaken the rule by eliminating the requirement for a BAVO
to be physically present at the 5-year BOP inspection and by proposing
an inadequate substitute of having a third-party inspector read
industry's inspection report after-the-fact before compiling its own
report. The commenters asserted that if a third-party inspector is not
physically present at the 5-year BOP inspection, that person would not
have the opportunity to physically inspect the equipment, collect
independent data and photos, or make recommendations for repairs/
replacements before the BOP is returned to service or rebuilt. The
commenters further asserted that any report prepared by a third-party
absent the opportunity to participate in the actual inspection would
have little value and would come much too late in the process to effect
real change/improvement.
     Response: BSEE disagrees with the assertions that having
an independent third party reviewing the documents, instead of being
physically present for the inspections, is inadequate. BSEE requires
the independent third party to review the documentation of the
inspections and compile a detailed inspection report. These independent
third party responsibilities help ensure that the appropriate entities
accurately and appropriately complete the inspection activities, as
well as identify any necessary corrective actions. The independent
third party document review allows the comparison of the design data
with the current status of the equipment. The intent of the major
inspection is to verify that the well control system components are fit
for service and within design tolerances to be utilized for specific
well conditions. These goals can be verified during a data review and
do not require the independent third party to be physically present
during the major inspection to make that determination. Because the
inspection may be performed in phased intervals, as provided in the
2016 WCR, having a BAVO or third party present during the inspection
would not be practical or logistically feasible. For example, in the
situation where the rig is arriving on the OCS from overseas, the
independent third party would not be present during any maintenance and
inspections, and the independent third party review of the major
inspections results would correspond to the certifications and
verifications required
[[Page 21962]]
by Sec. Sec.  250.731 and 250.732, without being present during the
inspections.
What are the coiled tubing and snubbing requirements? (Sec.  250.750)
    This is a new section in which BSEE proposed to consolidate coiled
tubing and snubbing operational requirements.
Summary of Proposed Revisions
    The content of this proposed section was moved from current
Sec. Sec.  250.616 and 250.1706, both titled Coiled tubing and snubbing
operations and removed and reserved both in this final rule. BSEE
proposed this section to consolidate some of the minimum BOP system
component requirements for coiled tubing and snubbing operations. BSEE
proposed minor revisions to the original language to conform to the
applicable operations covered under Subpart G. BSEE also proposed to
add a paragraph (d) to conform snubbing unit testing with updated
requirements.
Summary of Final Rule Revisions
    BSEE did not receive any comments specific to this section and only
received one comment asking how the proposed requirements of a
different section apply to coiled tubing operations. Based on BSEE's
review and continued analysis of the proposed rule and the single
comment applicable to coiled tubing, BSEE is making administrative and
technical revisions by modifying the proposed undesignated center
heading and separating out the coiled tubing and snubbing requirements
to create separate sections only applicable to snubbing operations. To
avoid confusion between coiled tubing and snubbing requirements in this
final rule, BSEE is separating their respective requirements into
different sections. The coiled tubing requirements are addressed under
new Sec. Sec.  250.750, What are the coiled tubing requirements? and
250.751, Coiled tubing testing requirements. The requirements for
snubbing operations, which were proposed as Sec.  250.750 paragraphs
(b), (c), and (d), were revised and moved to new Sec.  250.760, What
are the snubbing requirements? in the final rule. BSEE is also
including minor clarifications to the proposed text to more accurately
reflect BSEE's longstanding coiled tubing practices. BSEE is removing
``with the production tree in place'' proposed in paragraph (a) because
coiled tubing requirements apply to any well operation that uses coiled
tubing. BSEE is also adding ``follow the applicable requirements of
this subpart . . .'' to final Sec. Sec.  250.750(a) and 250.760(a) to
align with the Q and A guidance on the BSEE website at https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule.
Many regulations contained in Subpart G are applicable to coiled tubing
operations, such as, but not limited to, the items listed in the
relevant Q and A on the BSEE website at https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule.
    In Sec.  250.750, BSEE is adding a new paragraph (b) to clarify
that BSEE considers all coiled tubing operations to be non-routine.
BSEE is making this clarification based on our review of the proposed
rule and a review of the comments associated with the definition of
routine operations in Sec.  250.601, Definitions. This clarification
also codifies longstanding BSEE policy that considers operations with a
coiled tubing unit to be non-routine and require a permit. This
addition helps clarify the approval process for use of coiled tubing
for workovers.
Coiled Tubing Testing Requirements (Sec.  250.751)
    This is a new section in which BSEE proposed to consolidate coiled
tubing and snubbing operational requirements.
Summary of Proposed Revisions
    BSEE proposed to add this section to codify current BSEE policy
regarding the coiled tubing testing and recording requirements. In this
addition, BSEE proposed to reintroduce language similar to provisions
that were inadvertently removed from the regulations through the 2016
WCR, consolidating elements from Sec. Sec.  250.617 and 250.1707 of the
regulations as they existed before the 2016 WCR. Both sections are
currently reserved. BSEE proposed revisions to the original language to
conform to the applicable requirements of Subpart G. For example, in
the proposed rule, this section would not include the former provisions
regarding testing of the coiled tubing connector, because the proposal
would instead state that operators ``must test the coiled tubing unit
in accordance with Sec.  250.737 paragraphs (a), (b), (c), (d)(9), and
(d)(10).'' Section 250.737 requires testing of the system when
installed and provides testing criteria. As proposed, identifying the
connector testing in this section is not necessary because it is
already covered by the testing requirements of Sec.  250.737.
Summary of Final Rule Revisions
    BSEE did not receive any comments specific to this section. BSEE is
making minor revisions to better reflect changes to the undesignated
center heading that applies only to coiled tubing. As previously stated
in the final rule discussion under Sec.  250.750, based on BSEE's
review of the proposed rule, BSEE is revising this new section and
separating out the snubbing requirements, creating a separate section
applicable only to snubbing operations under final Sec.  250.760.
What are the snubbing requirements? (Sec.  250.760)
Summary of Proposed Revisions
    BSEE did not propose to add this new section, however the content
was included in proposed Sec.  250.750.
Summary of Final Rule Revisions
    BSEE is adding this new section and undesignated center heading to
clarify the snubbing requirements. To avoid confusion between coiled
tubing and snubbing requirements in this final rule, BSEE is separating
their respective requirements into different sections and relocating
the proposed snubbing requirements under this new section. The content
of this section is being moved from proposed Sec.  250.750(b), (c), and
(d), with minor conforming revisions to reflect the separation of
coiled tubing requirements and the applicability only to snubbing
operations and equipment. These changes are administrative and non-
substantive. BSEE did not receive comments on the relevant language
from proposed Sec.  250.750 and is finalizing it as described.
Subpart Q--Decommissioning Activities
What are the general requirements for decommissioning? (Sec.  250.1703)
    This section of the existing regulations details decommissioning
requirements, including getting District Manager approval, permanently
plugging all wells, removing all platforms and facilities,
decommissioning all pipelines, and clearing the seafloor of
obstructions.
Summary of Proposed Revisions
    BSEE proposed to revise paragraph (b) to clarify that only packers
or bridge plugs used as mechanical barriers are required to comply with
ANSI/API Spec. 11D1. BSEE proposed this revision to codify BSEE's
policy to ensure that the required mechanical barriers in a well are
held to a higher standard than other common packers or bridge plugs
used for various well specific conditions and completions design.
Furthermore, BSEE is aware that certain packers and bridge plugs cannot
meet the specifications of ANSI/API
[[Page 21963]]
Spec. 11D1. This revision would reduce the number of alternate
equipment requests submitted to BSEE. BSEE also proposed to add that
operators must have two independent barriers, one being mechanical, in
the exposed center wellbore (e.g., this could be the tubing or casing
depending on the well configuration) prior to removing the tree or well
control equipment. BSEE proposed this addition to codify BSEE policy,
align the well decommissioning requirements with similar requirements
from Sec. Sec.  250.720(a) and 250.1712(g), and to help ensure the well
is properly secured before removal of the tree or well control
equipment.
Summary of Final Rule Revisions
    BSEE received no substantive comments on these provisions of the
proposed rule, however BSEE did receive comments on similar mechanical
barrier requirements in Sec. Sec.  250.518 and 250.619. Based on its
consideration of the comments, BSEE is revising paragraph (b) to
clarify that only the required mechanical barrier must be ANSI/API
Spec. 11D1 qualified. This revision is consistent with the similar
requirements in final Sec. Sec.  250.518 and 250.619 and BSEE's
implementation of the mechanical barrier requirements finalized in the
2016 WCR.
What decommissioning applications and reports must I submit and when
must I submit them? (Sec.  250.1704)
    This section of the existing regulations provides a table that
identifies the required decommissioning applications and subsequent
reports, as well as the deadlines for when to submit them.
Summary of Proposed Revisions
    BSEE proposed to revise paragraph (g) by shifting the requirements
for submittal of the site clearance verification activity information
to an Application for Permit to Modify (APM). The site clearance
verification activity information will be removed from the end of
operations report (EOR). BSEE proposed these revisions to better
reflect current practice and limit redundant reporting.
    BSEE also proposed to revise paragraph (h) by adding the submittal
of the decommissioning activity information, upon completion, to the
EOR. BSEE proposed these revisions to better reflect current practice
and limit redundant reporting.
Summary of Final Rule Revisions
    BSEE received and considered comments on the proposed revisions and
includes the proposed language in the final rule without change.
Summary of Comments
Comments Related to Proposed Sec.  250.1704--Plug and Abandonment Plans
    Summary of comments: One commenter suggested that plugging and
abandonment plans should be based on risk acceptance and planned on a
well-by-well basis. The commenter also recommended the use of a DNV
Recommended Practice.
     Response: BSEE disagrees with the suggestion that plugging
and abandonment activities should be based on risk. BSEE does not
consider a risk assessment by itself sufficient for determination of
all plugging and abandonment operations. Plugging and abandonment
operations are currently conducted on a well specific basis as approved
within the applicable BSEE permits. BSEE will review the identified DNV
Recommended Practice for possible inclusion in future rulemakings, as
appropriate.
Coiled Tubing and Snubbing Operations (Sec.  250.1706)
Summary of Proposed Revisions
    BSEE proposed to remove and reserve this section. BSEE proposed to
move the content of this existing regulation to proposed Sec.  250.750.
BSEE proposed these revisions to help eliminate inconsistencies between
similar requirements spread throughout different regulatory subparts by
consolidating those requirements into Subpart G, which is applicable to
drilling, completions, workovers, and decommissioning operations.
Summary of Final Rule Revisions
    BSEE received no substantive comments on these provisions of the
proposed rule and will remove and reserve this section in the final
rule.
Must I notify BSEE before I begin well plugging operations? (Sec.
250.1713)
Summary of Proposed Revisions
    BSEE proposed to remove and reserve this section. Based upon BSEE
experience with the implementation of the 2016 WCR, BSEE determined
that the submittal of the information required by this section is
redundant with similar rig movement notification information required
under Sec.  250.712, What rig unit movements must I report?
Summary of Final Rule Revisions
    BSEE received no substantive comments on these provisions of the
proposed rule and will remove and reserve this section in the final
rule.
To what depth must I remove wellheads and casings? (Sec.  250.1716)
    This section of the existing regulations establishes the minimum
depth below the mud line for removal of all wellheads and casings,
unless an alternate depth is approved by the District Manager.
Summary of Proposed Revisions
    BSEE proposed to revise paragraph (b)(3) by changing the water
depth criteria for when BSEE may approve an alternate depth for removal
of the wellhead or casing from 800 meters to 1,000 feet. At depths
greater than 1,000 feet, there is little risk of obstruction to other
users of the OCS or its waters or contact with other equipment, and
little risk of safety or environmental issues from removal to an
alternate depth.
Summary of Final Rule Revisions
    BSEE received comments in general support of the proposed revisions
to this section and is including the proposed language in the final
rule without change.
If I install a subsea protective device, what requirements must I meet?
(Sec.  250.1722)
    This section of the existing regulations states that if a subsea
protective device is installed, then it must be done in a manner that
allows fishing gear to pass over the obstruction without damage to the
obstruction, the protective device, or the fishing gear.
Summary of Proposed Revisions
    BSEE proposed to revise paragraph (d) to direct the submittal of
the trawl test report to the EOR rather than an APM. This proposed
revision would not affect the substance of the reporting requirement or
the information BSEE receives, only the mechanism through which it is
received.
Summary of Final Rule Revisions
    BSEE received no substantive comments on these provisions of the
proposed rule and includes the proposed language in the final rule
without change.
VI. Procedural Matters
Regulatory Planning and Review (Executive Orders (E.O.) 12866, 13563,
and 13771)
    Executive Order 12866 provides that the Office of Information and
Regulatory Affairs (OIRA) within the OMB will review all significant
rules. This action is an economically significant regulatory
[[Page 21964]]
action that was submitted to OMB for review as it would have a positive
annual effect on the economy of $100 million or more. BSEE coordinated
development of an economic analysis to assess the anticipated costs and
potential benefits of the final rule. The significant positive economic
effect on the economy is the result of the estimated cost savings of
this rule. BSEE estimates the amendments in this rulemaking would save
the regulated industry $152 million annually over ten years (discounted
at 7 percent).
    Details on the estimated cost savings of this rule can be found in
the rule's regulatory impact analysis. The cost savings for this final
rule are due to regulatory clarifications, reduction in paperwork
burdens, adoption of industry standards, and migration to performance-
based standards for select provisions.
    This rule revises regulatory provisions in 30 CFR part 250,
subparts D, E, F, G, and Q. BSEE has reassessed a number of the
provisions in the (1014-AA11) 2016 WCR and revises some provisions to
reflect performance-based standards rather than prescriptive
requirements. Other revisions reduce or eliminate parts of the
paperwork burden, without impacting the current levels of safety and
environmental protection. BSEE sought the best available data and
information to analyze the economic impact of these changes. The
Regulatory Impact Analysis (RIA) for this rulemaking can be found in
the https://www.regulations.gov/ docket (Docket ID: BSEE-2018-0002).
The Final RIA (FRIA) indicates that the estimated overall cost savings
to the industry over the next 10 years would exceed $1.5 billion in
nominal dollars.
    BSEE revised certain provisions of the 2016 WCR to support the
goals of the Administration's regulatory reform initiatives, while
ensuring safety and environmental protection. BSEE has received
additional information since the publication of the 2016 WCR and
revisited several of the compliance cost assumptions in the economic
analysis for the 2016 final rule. The modifications to the BSEE
compliance cost estimates in the 2016 WCR analysis are primarily
because that analysis:
    (1.) Underestimated the cost for revising permits or reporting
certain operations to the District Manager (Sec. Sec.  250.428 and
250.722), and
    (2.) Underestimated both the number of subsea BOPs that would
require modifications and the cost of those modifications under the
1014-AA11 regulations (Sec.  250.734).
    The revisions to existing ram and accumulator requirements for
subsea BOPs (Sec.  250.734) yield cost savings of $369 million (nominal
$). The changes to Sec.  250.734 better align the shear ram provisions
with API Standard 53 and revise the accumulator capacity requirements
for subsea BOP stacks.
    With changes to Sec.  250.737, BSEE is allowing operators to move
to a 21-day BOP testing interval upon satisfaction of certain
conditions. These changes align the testing interval with industry and
global standards and help avoid premature wear and tear on critical
components. BSEE expects operators using subsea BOPs to seek to move to
a 21-day interval, realizing a cost savings of $919 million (nominal $)
over 10-years. The changes to this provision represent the single
largest cost savings in the rule.
    This rule will reduce the regulatory burden on industry, while
maintaining worker safety and environmental protection. BSEE is
providing industry flexibility, when practical, to meet the safety or
equipment standards, rather than specifying the compliance method. For
example, BSEE will eliminate the requirement that operators resubmit an
APD in the event of planned mud losses or inadequate cement jobs.
Instead, BSEE will allow the operator to outline remedial actions to
these scenarios in contingency plans included in the original BSEE-
approved APD. This revision will not change the operational responses
to these events, and therefore reduces the paperwork burden and
expensive operational downtime without affecting operational risks.
Other changes remove BOP stack certification requirements regarding
design specifications and equipment conditions and replace the BAVO
requirements for BOP systems and system components with independent
third party requirements. The previous provisions were either
duplicative or required a more burdensome certification process than
reasonably necessary. The changes to the certification processes do not
affect worker safety and the environment.
    The revisions to final Sec.  250.734 better define the BOP
components functionality requirements, revise the requirements for ROV
capability and functionality, and amend accumulator capacity
requirements for subsea BOP stacks. This revision to the accumulator
requirements increases operator flexibility to utilize the appropriate
accumulator capacity to perform the necessary emergency functions.
Through the implementation of the WCR, BSEE was able to better evaluate
the effects of the WCR accumulator requirements on subsea BOP space and
weight limitations. After reevaluating the API 53 standards, BSEE
agrees that certain prescriptive requirements in the current
regulations are unnecessary. The regulatory text revisions to Sec.
250.734 align BSEE regulations with the performance standards in API
Standard 53, ensuring the subsea accumulator capacity is sufficient to
actuate the BOP ram functions necessary to seal the well. This
performance standard meets the intent of the 1014-AA11 WCR without the
prescriptive and unnecessarily burdensome requirements.
    The Sec.  250.737 paragraph (d)(5) amendments allow operators to
alternate BOP tests between the two control stations rather than
testing from both control stations on each test. The rule returns the
regulations to pre-2016 WCR regulatory language in order to prevent the
additional wear and tear on the BOP components. This change aligns BSEE
regulations with the industry testing standards.
    BSEE's estimate of the net total, annualized and discounted
regulatory cost savings can be found in the following table.
          Total 10-Year Estimated Cost Savings Associated With Amendments to Subparts D, E, F, G, and Q
----------------------------------------------------------------------------------------------------------------
                          Year                              Undiscounted     Discounted at 3%   Discounted at 7%
----------------------------------------------------------------------------------------------------------------
Total..................................................     $1,543,093,357     $1,309,246,758     $1,067,468,876
Annualized.............................................        154,309,336        153,483,661      * 151,983,553
----------------------------------------------------------------------------------------------------------------
* The annualized cost savings assuming the rule is effective in 2019 and discounted over an infinite time
  horizon, would be $60,996,080 at a 7% discount rate (using 2016$).
    This rule reduces the burden imposed on industry, while ensuring
continued safety and environmental protection. Additional information
on the compliance costs, savings, and benefits
[[Page 21965]]
can be found in the FRIA posted in the docket.
    This rule revises multiple provisions in the current regulations to
implement performance-based provisions based upon reasonably obtainable
safety, technical, economic, and other information. Other redundant or
unnecessary reporting requirements are also being eliminated. BSEE is
providing industry flexibility, when practical, to meet the safety or
equipment standards, rather than specifying the compliance method.
Based on a consideration of the qualitative and quantitative safety and
environmental factors related to the rule, BSEE's assessment is that it
is consistent with the policies of the applicable E.O.s and the OCSLA.
    Executive Order 13563 reaffirms the principles of E.O. 12866 while
calling for improvements in the Nation's regulatory system to promote
predictability, to reduce uncertainty, and to use the best, most
innovative, and least burdensome tools for achieving regulatory ends.
The E.O. directs agencies to consider regulatory approaches that reduce
burdens and maintain flexibility and freedom of choice for the public
where these approaches are relevant, feasible, and consistent with
regulatory objectives. E.O. 13563 emphasizes further 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 have developed this rule in a manner consistent with these
requirements.
    Executive Order 13771 requires Federal agencies to take proactive
measures to reduce the costs associated with complying with Federal
regulations. This rule is an E.O. 13771 deregulatory action.
Regulatory Flexibility Act and Small Business Regulatory Enforcement
Fairness Act
    The Regulatory Flexibility Act, 5 U.S.C. 601-612, requires agencies
to analyze the economic impact of 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.
601 note, requires agencies to produce compliance guidance for small
entities if the rule has a significant economic impact. For the reasons
explained in this analysis, BSEE believes the rule may have a
significant economic impact and, therefore, a Regulatory Flexibility
Analysis (RFA) for the rule is required by the Regulatory Flexibility
Act. The RFA, which assesses the impact of this rule on small entities,
can be found in the FRIA within the docket for this rulemaking.
    As defined by the Small Business Administration (SBA), a small
entity is one that is ``independently owned and operated and which is
not dominant in its field of operation.'' What characterizes a small
business varies from industry to industry in order to properly reflect
industry size differences. This rule affects lease operators that are
conducting OCS drilling or well operations. BSEE's analysis shows this
includes about 69 companies with active drilling or well operations. Of
the 69 companies, 21 (30 percent) are large and 48 (70 percent) are
small. Entities affected by this rule are classified primarily under
North American Industry Classification System (NAICS) codes 211120
(Crude Petroleum Extraction), 211130 (Natural Gas Extraction), and
213111 (Drilling Oil and Gas Wells). The rule indirectly impacts OCS
drilling contractors that are classified under NAICS code 21311,
however this analysis focuses on the OCS oil and gas lessees and
operators to which the rule's provisions will apply directly. For NAICS
codes 211120 and 211130, SBA defines a small company as having fewer
than 1,251 employees.
    BSEE considers that a rule will have an impact on a ``substantial
number of small entities'' when the total number of small entities
impacted by the rule is equal to or exceeds 10 percent of the relevant
universe of small entities in a given industry. BSEE's analysis shows
that there are 48 small companies with active operations on the OCS and
all of these companies could be impacted by the rule if conducting
drilling or well operations. Therefore, BSEE expects that the rule
would affect a substantial number of small entities.
    Large companies are responsible for the majority of activity in
deepwater, where subsea BOPs are used with floating MODUs. BSEE's
first-order estimate for the rule's small entity cost savings is
proportional to the number of drilling rigs being operated or
contracted by small companies (circa October 2017).
    This rule is a deregulatory action; BSEE has evaluated possible
costs and benefits and has estimated that there is an overall
associated cost savings. BSEE has estimated the annualized cost savings
by regulatory provision and then allocated those savings to small or
large entities based on drilling/well activity (circa October, 2017;
activity breakouts can be found in the RFA). The changes to Sec. Sec.
250.423, 250.734, and 250.737(d)(5) would only apply to subsea BOPs and
would yield cost savings that sum to $47,421,114. All remaining changes
apply to all well operations or subsea/surface BOPs and yield cost
savings that sum to $106,888,221. Using the share of small and large
companies subject to each suite of provisions, we estimate that small
companies would realize 25 percent of the cost savings from this rule
and large companies 75 percent. The allocation is displayed in the
following table.
                                          Cost Savings by Operator Size
                                           [Undiscounted annualized $]
----------------------------------------------------------------------------------------------------------------
                                          Small companies                 Large companies
                                 ----------------------------------------------------------------   Total cost
            Provision               Percent of                      Percent of                        savings
                                     operators     Cost savings      operators     Cost savings
----------------------------------------------------------------------------------------------------------------
Subsea BOP Provisions...........              12      $5,578,955              88     $41,842,160     $47,421,114
All Other Provisions............              30      32,315,044              70      74,573,178     106,888,221
                                 -------------------------------------------------------------------------------
    Total.......................  ..............     *37,893,998  ..............   **116,415,337     154,309,336
----------------------------------------------------------------------------------------------------------------
* (25% of Total).
** (75% of Total).
[[Page 21966]]
    This rule:
    a. Will have a positive economic effect on the economy of $100
million or more. The cost savings will not materially affect the
economy nationally or in any local area.
    b. Will not cause a major increase in costs or prices for
consumers; individual industries; Federal, State, Tribal, or local
governments; or regions of the nation. This rule will have positive
effects on OCS operators and is not anticipated to negatively impact
oil, gas, and sulfur production or the cost of fuels for consumers.
    c. Will not have significant or adverse effects on competition,
employment, investment, productivity, innovation, or the ability of
U.S.-based enterprises to compete with foreign-based enterprises.
    This rule is a major rule because it will have an annual effect on
the economy of $100 million or more in at least one year of the 10-year
period analyzed. The requirements apply to all entities operating on
the OCS regardless of company designation as a small business. For more
information on the small business impacts, see the RFA in the FRIA.
Small businesses may send comments on the actions of Federal employees
who enforce, or otherwise determine compliance with, Federal
regulations to the Small Business and Agriculture Regulatory
Enforcement Ombudsman, and to the Regional Small Business Regulatory
Fairness Board. The Ombudsman evaluates these actions annually and
rates each agency's responsiveness to small business. If you wish to
comment on actions by employees of BSEE, call 1-888-REG-FAIR (1-888-
734-3247).
Unfunded Mandates Reform Act of 1995
    This final rule will not impose an unfunded mandate on State,
local, or tribal governments or the private sector of more than $100
million per year. The final rule will not have a significant or unique
effect on State, local, or tribal governments or the private sector. A
statement containing the information required by the Unfunded Mandates
Reform Act (2 U.S.C. 1531 et seq.) is not required.
Takings Implication Assessment (E.O. 12630)
    Under the criteria in E.O. 12630, this final rule does not have
significant takings implications. The rule is not a governmental action
capable of interference with constitutionally protected property
rights. A Takings Implication Assessment is not required.
Federalism (E.O. 13132)
    Under the criteria in section 1 of E.O. 13132, this final rule does
not have sufficient federalism implications to warrant the preparation
of a federalism summary impact statement. This rule will 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 rule will not affect that role. A
federalism summary impact statement is not required.
    The BSEE has the authority to regulate offshore oil and gas
drilling, completion, workover, and decommissioning operations. State
governments do not have authority over offshore drilling, completion,
workover, and decommissioning operations on the OCS. None of the
changes in this rule will affect areas that are under the jurisdiction
of the States. It will not change the way that the States and the
Federal government interact, or the way that States interact with
private companies.
Civil Justice Reform (E.O. 12988)
    This final rule complies with the requirements of E.O. 12988.
Specifically, this rule:
    (1) Meets the criteria of section 3(a) requiring that all
regulations be reviewed to eliminate errors and ambiguity and be
written to minimize litigation; and
    (2) Meets the criteria of section 3(b)(2) requiring that all
regulations be written in clear language and contain clear legal
standards.
Consultation With Indian Tribes (E.O. 13175)
    BSEE is committed to regular and meaningful consultation and
collaboration with tribes on policy decisions that have tribal
implications. Under the criteria in E.O. 13175 and the Department's
Policy on Consultation with Indian Tribes (S.O. 3317, Amendment 2,
dated December 31, 2013), we have evaluated this final rule and
determined that it has no substantial direct effects on federally
recognized Indian tribes.
National Technology Transfer and Advancement Act (NTTAA)
    BSEE complies with the National Technology Transfer and Advancement
Act (NTTAA) (15 U.S.C. 3701 et seq.) requirement that an agency ``use
standards developed or adopted by voluntary consensus standards bodies
rather than government-unique standards, except where inconsistent with
applicable law or otherwise impractical.'' (OMB Circular A-119 at p.
13). BSEE also complies with the OFR regulations governing
incorporation by reference. (See, 1 CFR part 51.) Those regulations
specify the process for updating an incorporated standard at Sec.
51.11(a), including seeking approval by OFR for a change to a standard
incorporated by reference in a final rule.
Paperwork Reduction Act (PRA) of 1995
    This final rule contains collections of information that will be
submitted to OMB for review and approval under the PRA, 44 U.S.C. 3501
et seq. As part of its continuing effort to reduce paperwork and
burdens on respondents, BSEE invites the public and other Federal
agencies to comment on any aspect of the reporting and recordkeeping
burden. If you wish to comment on the information collection (IC)
aspects of this final rule, you may send your comments directly to OMB
and send a copy of your comments to the Regulations and Standards
Branch (see the ADDRESSES section of this final rule). Please reference
30 CFR 250, subpart G, Blowout Preventer Systems and Well Control,
1014-0028, in your comments. To see a copy of the information
collection request submitted to OMB, go to http://www.reginfo.gov
(select Information Collection Review, Currently Under Review); or you
may obtain a copy of the supporting statement for the collection of
information by contacting the Bureau's Information Collection Clearance
Officer at (703) 787-1607.
    The PRA provides that an agency may not conduct or sponsor, and a
person is not required to respond to, a collection of information
unless it displays a currently valid OMB control number. The OMB is
required to make a decision concerning the collection of information
contained in these regulations 30-60 days after publication of this
document in the Federal Register.
    The public may comment, at any time, on the accuracy of the IC
burden in this rule and may submit any comments to DOI/BSEE; ATTN:
Regulations and Standards Branch; VAE-ORP; 45600 Woodland Road,
Sterling, VA 20166; email [email protected], or fax (703) 787-1093.
    The title of the collection of information for this rule is 30 CFR
part 250, Blowout Preventer Systems and Well Control Revisions (Final
Rulemaking). The final regulations concern BOP system requirements and
maintaining well control, among others, and the information is used in
BSEE's efforts to regulate oil and gas operations on the OCS to protect
life and the environment, conserve natural resources, and prevent
waste.
[[Page 21967]]
    Potential respondents comprise Federal OCS oil, gas, and sulphur
operators and lessees. Responses to this collection of information are
mandatory, or are required to obtain or retain a benefit; they are also
submitted on occasion, daily and weekly (during drilling operations),
monthly, quarterly, biennially, and as a result of situations
encountered, depending upon the requirement. The IC does not include
questions of a sensitive nature. The BSEE will protect proprietary
information according to the Freedom of Information Act (5 U.S.C. 552)
and DOI implementing regulations (43 CFR part 2), 30 CFR part 252, OCS
Oil and Gas Information Program, and 30 CFR 250.197, Data and
information to be made available to the public or for limited
inspection.
    This final rule will increase BSEE's IC inventory by +87,744 annual
hour burdens; as well as increase annual non-hour costs burdens by
$10,918,000 for Independent Third Party (ITP) costs. BSEE-Approved
Verification Organization (BAVO); is being replaced with ITP. In
connection with the original WCR, BSEE assumed hour burdens in place of
non-hour costs associated with BAVO submissions; however, in this final
rule, we are capturing non-hour costs associated with hiring ITPs.
Below is a list of the current OMB Control Numbers affected by this
final rulemaking and their associated increases/decreases in hour
burdens and non-hour costs:
     Applications for Permits to Drill (APD-1014-0025,
expiration 4/30/20) will increase annual burden by +14,523 hours
annually (-69 hours due to this rulemaking, and +14,592 due to re-
estimating the annual number of response) and increase +$3,999,000
annual non-hour costs for ITP;
     Applications for Permits to Modify (APM-1014-0026,
expiration 7/31/20) will decrease annual burden by -33 hours (+277
hours due to this rulemaking, and -310 hours due to re-estimating the
annual number of responses) and increase +$6,138,000 annual non-hour
costs for ITP;
     Subpart A (1014-0022, expiration 2/28/21), BSEE is not
making any changes to hour-burden or non-hour costs;
     Subpart B (1014-0024, expiration 10/31/21), BSEE is not
making any changes to hour-burden or non-hour costs;
     Subpart D (1014-0018, expiration 3/31/2021) will increase
the annual burden by +40 hours (+40 due to this rulemaking) and
increase +$16,000 annual non-hour costs for ITP;
     Subpart G (1014-0028, expiration 07/31/19) will increase
annual burden by +73,214 hours (+4,048 hours is due to this rulemaking
and +69,166 hours due to re-estimating the annual number of responses)
and increase +$765,000 annual non-hour costs for ITP.
    The following is a brief explanation of how the final regulatory
changes will affect the various subpart hour burdens:
Application for Permit To Drill (APD) 1014-0025
    Sec.  250.414(c)(2) is new and will allow operators the option to
submit the required justification and documentation for a proposed
alternative safe drilling margin for BSEE approval at an earlier date
prior to the APD. This will increase the annual burden hour by 15
hours.
    Sec.  250.428 removes the requirement to resubmit an APD in the
event of planned mud losses, or remedial actions for inadequate cement
jobs, if these circumstances are addressed in the original approved
APD. Reductions will be shown during the renewal process (see
Discussion of Final Rule Requirements above).
    Sec.  250.724(b) will eliminate the requirement to submit
certification that you have a real-time monitoring plan that meets the
criteria listed. This will decrease the annual hour burden by 109 hours
(see Discussion of Final Rule Requirements above).
    Sec.  250.731 will add Independent Third Party costs, increasing
the non-hour cost burdens by $31,000 per submission (see Discussion of
Final Rule Requirements above). During this rulemaking it was
discovered that BSEE had underestimated the number of responses/
submittals. We are increasing that by 128 submittals annually, which in
turn increase the annual hour burden by 14,592 hours.
    Sec.  250.738(b) requires operators submit a revised permit with a
written statement from an independent third party documenting the
repairs, replacement, or reconfiguration and certifying that the
previous certification in Sec.  250.731(c) remains valid. This will
increase the annual hour burden by 25 hours (see Discussion of Final
Rule Requirements above).
Application for Permit To Modify (APM) 1014-0026
    Sec.  250.724(b) will eliminate the requirement to submit
certification that you have a real-time monitoring plan that meets the
criteria listed. This will decrease the annual hour burden by 125 hours
(see Discussion of Final Rule Requirements above).
    Sec.  250.731 will add Independent Third Party costs, increasing
the non-hour cost burdens by $31,000 per submission (total of
$6,138,000 annual non-hour costs) (see Discussion of Final Rule
Requirements above). During this rulemaking it was discovered that BSEE
had overestimated the number of responses/submittals. We are decreasing
that by 62 responses; which in turn decrease the annual hour burden by
310 hours.
    Sec.  250.750(a)(4) requires operators that plan to conduct
operations without downhole check valves, describe alternate procedures
and equipment in Form BSEE-0124, APM, and have it approved by the
District Manager. The responses/burden associated with Sec.  250.616
(245 approvals x .75 hour = 184 annual hour burdens) and Sec.  250.1706
(503 requests x .25 hour = 126 annual hour burdens) are being relocated
to 250.750(a)(4) (for a total of 748 requests x 1 hour); increasing the
annual hour burden by 438 hours (see Discussion of Final Rule
Requirements above).
    Sec.  250.1722(d) will direct the submittal of the trawl test
report to the End of Operations Report (EOR) rather than an APM; and
will decrease the annual hour burden by 36 hours (see Discussion of
Final Rule Requirements above).
Subpart A 1014-0022
    Sec.  250.115 is the regulatory text from Sec.  250.198 but moved
and relocated to Sec.  250.115. This burden will remain the same and is
covered under Sec.  250.141 (see Discussion of Final Rule Requirements
above).
    Sec.  250.423 is rewording the requirement in a manner that will
reduce the number of alternative procedure or equipment requests under
Sec.  250.141. Reductions will be shown during the renewal process (see
Discussion of Final Rule Requirements above).
Subpart B 1014-0024
    Sec.  250.292(p) will require less information to be submitted in
the DWOP. Reductions will be shown during the renewal process (see
Discussion of Final Rule Requirements above).
Subpart D 1014-0018
    Sec.  250.427(b) will revise the requirement to include a
notification to BSEE District Manager. BSEE is also clarifying that the
District Manager must review and approve proposed remedial actions.
This will increase the annual hour burden by 40 hours (see Discussion
of Final Rule Requirements above).
[[Page 21968]]
    Sec.  250.462(e)(1) will add Independent Third Party costs
increasing the non-hour cost burdens by $8,000 per notification (total
of $16,000 annual non-hour costs) (see Discussion of Final Rule
Requirements above).
    Sec.  250.1722 will direct the submittal of the trawl test report
to the End of Operations Report (EOR) rather than an APM. Burden hours
associated with Subpart Q are already covered under EOR reporting. Any
reductions/increases will be shown during the renewal process (see
Discussion of Final Rule Requirements above).
Subpart G 1014-0028
    Sec.  250.720(a)(3) will require operators submit a revised permit
with a written statement from an independent third party certifying
that the previous certification remains valid and to request and
receive District Manager approval before resuming operations after
unlatching the BOP or LMRP. This will increase the annual hour burden
by 13 hours (see Discussion of Final Rule Requirements above).
    Sec.  250.720(d) was proposed but had been inadvertently omitted
from the information collection. The requirement is new and will
require operators to identify and make available for BSEE inspection,
specified equipment used solely for intervention operations. This will
increase the annual hour burden by 10 hours (see Discussion of Final
Rule Requirements above).
    Sec.  250.722(a)(2) will require operators to document successful
pressure test in the Well Activity Report (WAR). This will increase the
annual hour burden by 150 hours (see Discussion of Final Rule
Requirements above).
    Sec.  250.730(c)(2) will increase the annual hour burden by 5
hours. Based on comments received BSEE is clarifying how to request an
extension to the failure analysis timeframe. Furthermore, they must
submit an extension request to the Chief, Office of Offshore Regulatory
Programs, detailing how the investigation and analysis will get
completed to BSEE for approval (see Discussion of Final Rule
Requirements above).
    New Sec.  250.732(a) will add Independent Third Party costs,
increasing the non-hour cost burdens by $5,100 per verification (total
increase is $765,000 annual non-hour costs) (see Discussion of Final
Rule Requirements above).
    Old Sec.  250.732(a) will eliminate the requirement to request and
submit for approval all relevant information to become a BAVO. This
will decrease the annual hour burden by 700 hours (see Discussion of
Final Rule Requirements above).
    New Sec.  250.732(d) requires operators to make all documentation
that demonstrates compliance with the requirements of this section
available to BSEE upon request; increasing the annual hour burden by 40
hours (see Discussion of Final Rule Requirements above).
    Old Sec.  250.732(d) will eliminate the submission of Mechanical
Integrity Assessment Reports; decreasing the annual hour burden by 900
hours (see Discussion of Final Rule Requirements above).
    Sec.  250.737(a)(4) and (d)(10) (test frequency for function test
shear rams) will increase the annual hour burden by 75 hours. BSEE is
requiring operators that wish to request approval for a 21-day BOP
testing frequency, demonstrate the development of a BOP health
monitoring plan (including, but not limited to, information/
requirements such as condition monitoring tool; failure propagation
analysis; a failure tracking and resolution system that includes
detailed failure reports and identification of recurring problems). In
addition, this will increase annual hour burdens by 100 hours to submit
quarterly reports of the data collected with the health monitoring plan
to the BSEE Regional Supervisor, District Field Operations (see
Discussion of Final Rule Requirements above).
    Sec.  250.737(d)(5) will allow for alternating tests between two
control stations. This will increase the annual hour burden by 25 hours
(see Discussion of Final Rule Requirements above).
    Sec.  250.751 will include the coiled tubing testing and recording
requirements that were inadvertently removed in the original Well
Control Rule. This will increase the annual hour burden by 3,630 hours
(see Discussion of Final Rule Requirements above).
    Once this rule becomes effective, BSEE will use the current OMB
control numbers for the affected subparts discussed and will have their
information collection burdens adjusted accordingly through the renewal
process.
National Environmental Policy Act of 1969 (NEPA)
    BSEE has prepared a final environmental assessment (EA) that
concludes that this final rule will not have a significant impact on
the quality of the human environment under the National Environmental
Policy Act of 1969 (NEPA) (42 U.S.C. 4321 et seq.). The final EA
supports the issuance of a Finding of No Significant Impact (FONSI) for
the rule, therefore the preparation of an environmental impact
statement pursuant to NEPA is not required. A copy of the final EA and
FONSI can be viewed at www.regulations.gov (use the keyword/ID ``BSEE-
2018-0002'').
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).
Effects on the Nation's Energy Supply (E.O. 13211)
    This final rule is not a significant energy action under the
definition in E.O. 13211. Although the rule is a significant regulatory
action under E.O. 12866, it is not likely to have a significant adverse
effect on the supply, distribution, or use of energy. A Statement of
Energy Effects is not required.
Severability
    If a court holds any provisions of this final rule or their
applicability to any persons or circumstances invalid, the remainder of
the provisions and their applicability to other people or circumstances
will not be affected.
List of Subjects in 30 CFR Part 250
    Administrative practice and procedure, Continental shelf,
Continental Shelf--mineral resources, Continental Shelf--rights-of-way,
Environmental impact statements, Environmental protection, Government
contracts, Incorporation by reference, Investigations, Oil and gas
exploration, Penalties, Pipelines, Reporting and recordkeeping
requirements, Sulfur.
Joseph R. Balash,
Assistant Secretary--Land and Minerals Management, U.S. Department of
the Interior.
    For the reasons stated in the preamble, the Bureau of Safety and
Environmental Enforcement (BSEE) amends 30 CFR part 250 as follows:
PART 250--OIL AND GAS AND SULFUR OPERATIONS IN THE OUTER
CONTINENTAL SHELF
0
1. The authority citation for part 250 continues to read as follows:
    Authority: 30 U.S.C. 1751, 31 U.S.C. 9701, 33 U.S.C.
1321(j)(1)(C), 43 U.S.C. 1334.
Subpart A--General
0
2. Add Sec.  250.115 to read as follows:
[[Page 21969]]
Sec.  250.115  What are the procedures for, and effects of,
incorporation of documents by reference in this part?
    For the documents incorporated by reference in this part:
    (a) Incorporation by reference of a document is limited to the
edition of the document, or the specific edition and supplement or
addendum, that is cited in Sec.  250.198. Future amendments or
revisions of the incorporated document are not included. BSEE will
publish any changes to the incorporation of the document in the Federal
Register and amend Sec.  250.198 as appropriate.
    (b) BSEE may make a rule amending the incorporation of a document
effective without prior opportunity for public comment when BSEE
determines:
    (1) That the revisions to the document result in safety
improvements or represent new industry standard technology and do not
impose undue costs on the affected parties; and
    (2) BSEE meets the requirements for making a rule immediately
effective under 5 U.S.C. 553.
    (c) The effect of incorporation by reference of a document into the
regulations in this part is that the incorporated document is a
requirement. When a section in this part refers to an incorporated
document, you are responsible for complying with the provisions of that
entire document, except to the extent that the section that refers to
the document provides otherwise. When a section in this part refers to
a part of an incorporated document, you are responsible for complying
with that part of the document as provided in that section.
    (d) Under Sec. Sec.  250.141 and 250.142, you may comply with a
later edition of a specific document incorporated by reference,
provided:
    (1) You show that complying with the later edition provides a
degree of protection, safety, or performance equal to or better than
would be achieved by compliance with the listed edition; and
    (2) You obtain prior written approval for alternative compliance
from the authorized BSEE official.
0
3. Revise Sec.  250.198 to read as follows:
Sec.  250.198  Documents incorporated by reference.
    Certain material is incorporated by reference into this part with
the approval of the Director of the Federal Register under 5 U.S.C.
552(a) and 1 CFR part 51. All incorporated material is available for
inspection at the Houston BSEE office at 1919 Smith Street Suite 14042,
Houston, Texas 77002 and is available from the sources indicated in
this section. It is also available for inspection at the National
Archives and Records Administration (NARA). To make an appointment to
inspect incorporated material at the Houston BSEE office, call 1-844-
259-4779. For information on the availability of this material at NARA,
call 202-741-6030 or go to http://www.archives.gov/federal-register/cfr/ibr-locations.html.
    (a) American Concrete Institute (ACI), ACI Standards, 38800 Country
Club Drive, Farmington Hills, MI 48331-3439: http://www.concrete.org;
phone: 248-848-3700:
    (1) ACI Standard 318-95, Building Code Requirements for Reinforced
Concrete, 1995; incorporated by reference at Sec.  250.901.
    (2) ACI 318R-95, Commentary on Building Code Requirements for
Reinforced Concrete, 1995; incorporated by reference at Sec.  250.901.
    (3) ACI 357R-84, Guide for the Design and Construction of Fixed
Offshore Concrete Structures, 1984; reapproved 1997, incorporated by
reference at Sec.  250.901.
    (b) American Gas Association (AGA Reports), 400 North Capitol
Street NW, Suite 450, Washington, DC 20001, http://www.aga.org; phone:
202-824-7000;
    (1) AGA Report No. 7--Measurement of Natural Gas by Turbine Meters;
Revised February 2006; incorporated by reference at Sec.  250.1203(b);
    (2) AGA Report No. 9--Measurement of Gas by Multipath Ultrasonic
Meters; Second Edition, April 2007; incorporated by reference at Sec.
250.1203(b);
    (3) AGA Report No. 10--Speed of Sound in Natural Gas and Other
Related Hydrocarbon Gases; Copyright 2003; incorporated by reference at
Sec.  250.1203(b).
    (c) American Institute of Steel Construction, Inc. (AISC), AISC
Standards, One East Wacker Drive, Suite 700, Chicago, IL 60601-1802;
http://www.aisc.org; phone: 312-670-2400:
    (1) ANSI/AISC 360-05, Specification for Structural Steel Buildings,
incorporated by reference at Sec.  250.901.
    (2) [Reserved]
    (d) American National Standards Institute (ANSI), http.www./
webstore.ansi.org/; phone: 212-642-4900:
    (1) ANSI/ASME B 16.5-2003, Pipe Flanges and Flanged Fittings,
incorporated by reference at Sec.  250.1002;
    (2) ANSI/ASME B 31.8-2003, Gas Transmission and Distribution Piping
Systems, incorporated by reference at Sec.  250.1002;
    (3) ANSI Z88.2-1992, American National Standard for Respiratory
Protection, incorporated by reference at Sec.  250.490.
    (e) American Petroleum Institute (API), API Recommended Practices
(RP), Specs, Standards, Manual of Petroleum Measurement Standards
(MPMS) chapters, 1220 L Street, NW, Washington, DC 20005-4070; http://www.api.org; phone: 202-682-8000:
    (1) API 510, Pressure Vessel Inspection Code: In-Service
Inspection, Rating, Repair, and Alteration, Tenth Edition, May 2014;
Addendum 1, May 2017; incorporated by reference at Sec. Sec.
250.851(a) and 250.1629(b);
    (2) API 570, Piping Inspection Code: In-service Inspection, Rating,
Repair, and Alteration of Piping Systems, Fourth Edition, February
2016; Addendum 1, May 2017; incorporated by reference at Sec.
250.841(b).
    (3) API Bulletin 2INT-DG, Interim Guidance for Design of Offshore
Structures for Hurricane Conditions, May 2007; incorporated by
reference at Sec.  250.901;
    (4) API Bulletin 2INT-EX, Interim Guidance for Assessment of
Existing Offshore Structures for Hurricane Conditions, May 2007;
incorporated by reference at Sec.  250.901;
    (5) API Bulletin 2INT-MET, Interim Guidance on Hurricane Conditions
in the Gulf of Mexico, May 2007; incorporated by reference at Sec.
250.901;
    (6) API Bulletin 92L, Drilling Ahead Safely with Lost Circulation
in the Gulf of Mexico, First Edition, August 2015; incorporated by
reference at Sec.  250.427(b);
    (7) API MPMS Chapter 1--Vocabulary, Second Edition, July 1994;
incorporated by reference at Sec.  250.1201;
    (8) API MPMS Chapter 2--Tank Calibration, Section 2A--Measurement
and Calibration of Upright Cylindrical Tanks by the Manual Tank
Strapping Method, First Edition, February 1995; reaffirmed February
2007; incorporated by reference at Sec.  250.1202;
    (9) API MPMS Chapter 2--Tank Calibration, Section 2B--Calibration
of Upright Cylindrical Tanks Using the Optical Reference Line Method,
First Edition, March 1989; reaffirmed, December 2007; incorporated by
reference at Sec.  250.1202;
    (10) API MPMS Chapter 3--Tank Gauging, Section 1A--Standard
Practice for the Manual Gauging of Petroleum and Petroleum Products,
Second Edition, August 2005; incorporated by reference at Sec.
250.1202;
    (11) API MPMS Chapter 3--Tank Gauging, Section 1B--Standard
Practice for Level Measurement of Liquid Hydrocarbons in Stationary
Tanks by Automatic Tank Gauging, Second Edition, June 2001; reaffirmed,
October
[[Page 21970]]
2006; incorporated by reference at Sec.  250.1202;
    (12) API MPMS Chapter 4--Proving Systems, Section 1--Introduction,
Third Edition, February 2005; incorporated by reference at Sec.
250.1202;
    (13) API MPMS Chapter 4--Proving Systems, Section 2--Displacement
Provers, Third Edition, September 2003; incorporated by reference at
Sec.  250.1202;
    (14) API MPMS Chapter 4--Proving Systems, Section 4--Tank Provers,
Second Edition, May 1998, reaffirmed November 2005; incorporated by
reference at Sec.  250.1202;
    (15) API MPMS Chapter 4--Proving Systems, Section 5--Master-Meter
Provers, Second Edition, May 2000, reaffirmed, August 2005;
incorporated by reference at Sec.  250.1202;
    (16) API MPMS Chapter 4--Proving Systems, Section 6--Pulse
Interpolation, Second Edition, May 1999; reaffirmed 2003; incorporated
by reference at Sec.  250.1202;
    (17) API MPMS Chapter 4--Proving Systems, Section 7--Field Standard
Test Measures, Second Edition, December 1998; reaffirmed 2003;
incorporated by reference at Sec.  250.1202;
    (18) API MPMS Chapter 4--Proving Systems, Section 8--Operation of
Proving Systems; First Edition, reaffirmed March 2007; incorporated by
reference at Sec.  250.1202(a), (f), and (g);
    (19) API MPMS Chapter 5--Metering, Section 1--General
Considerations for Measurement by Meters, Fourth Edition, September
2005; incorporated by reference at Sec.  250.1202;
    (20) API MPMS Chapter 5--Metering, Section 2--Measurement of Liquid
Hydrocarbons by Displacement Meters, Third Edition, September 2005;
incorporated by reference at Sec.  250.1202;
    (21) API MPMS Chapter 5--Metering, Section 3--Measurement of Liquid
Hydrocarbons by Turbine Meters, Fifth Edition, September 2005;
incorporated by reference at Sec.  250.1202;
    (22) API MPMS Chapter 5--Metering, Section 4--Accessory Equipment
for Liquid Meters, Fourth Edition, September 2005; incorporated by
reference at Sec.  250.1202;
    (23) API MPMS Chapter 5--Metering, Section 5--Fidelity and Security
of Flow Measurement Pulsed-Data Transmission Systems, Second Edition,
August 2005; incorporated by reference at Sec.  250.1202;
    (24) API MPMS Chapter 5--Metering, Section 6--Measurement of Liquid
Hydrocarbons by Coriolis Meters; First Edition, reaffirmed, March 2008;
incorporated by reference at Sec.  250.1202(a);
    (25) API MPMS Chapter 5--Metering, Section 8--Measurement of Liquid
Hydrocarbons by Ultrasonic Flow Meters Using Transit Time Technology;
First Edition, February 2005; incorporated by reference at Sec.
250.1202(a);
    (26) API MPMS Chapter 6--Metering Assemblies, Section 1--Lease
Automatic Custody Transfer (LACT) Systems, Second Edition, May 1991;
reaffirmed, April 2007; incorporated by reference at Sec.  250.1202;
    (27) API MPMS Chapter 6--Metering Assemblies, Section 6--Pipeline
Metering Systems, Second Edition, May 1991; reaffirmed, February 2007;
incorporated by reference at Sec.  250.1202;
    (28) API MPMS Chapter 6--Metering Assemblies, Section 7--Metering
Viscous Hydrocarbons, Second Edition, May 1991; reaffirmed, April 2007;
incorporated by reference at Sec.  250.1202;
    (29) API MPMS Chapter 7--Temperature Determination, First Edition,
June 2001; reaffirmed, March 2007; incorporated by reference at Sec.
250.1202;
    (30) API MPMS Chapter 8--Sampling, Section 1--Standard Practice for
Manual Sampling of Petroleum and Petroleum Products, Third Edition,
October 1995; reaffirmed, March 2006; incorporated by reference at
Sec.  250.1202;
    (31) API MPMS Chapter 8--Sampling, Section 2--Standard Practice for
Automatic Sampling of Liquid Petroleum and Petroleum Products, Second
Edition, October 1995; reaffirmed, June 2005; incorporated by reference
at Sec.  250.1202;
    (32) API MPMS Chapter 9--Density Determination, Section 1--Standard
Test Method for Density, Relative Density (Specific Gravity), or API
Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer
Method, Second Edition, December 2002; reaffirmed October 2005;
incorporated by reference at Sec.  250.1202(a) and (l);
    (33) API MPMS Chapter 9--Density Determination, Section 2--Standard
Test Method for Density or Relative Density of Light Hydrocarbons by
Pressure Hydrometer, Second Edition, March 2003; incorporated by
reference at Sec.  250.1202;
    (34) API MPMS Chapter 10--Sediment and Water, Section 1--Standard
Test Method for Sediment in Crude Oils and Fuel Oils by the Extraction
Method, Third Edition, November 2007; incorporated by reference at
Sec.  250.1202;
    (35) API MPMS Chapter 10--Sediment and Water, Section 2--Standard
Test Method for Water in Crude Oil by Distillation, Second Edition,
November 2007; incorporated by reference at Sec.  250.1202;
    (36) API MPMS Chapter 10--Sediment and Water, Section 3--Standard
Test Method for Water and Sediment in Crude Oil by the Centrifuge
Method (Laboratory Procedure), Third Edition, May 2008; incorporated by
reference at Sec.  250.1202;
    (37) API MPMS Chapter 10--Sediment and Water, Section 4--
Determination of Water and/or Sediment in Crude Oil by the Centrifuge
Method (Field Procedure), Third Edition, December 1999; incorporated by
reference at Sec.  250.1202;
    (38) API MPMS Chapter 10--Sediment and Water, Section 9--Standard
Test Method for Water in Crude Oils by Coulometric Karl Fischer
Titration, Second Edition, December 2002; reaffirmed 2005; incorporated
by reference at Sec.  250.1202;
    (39) API MPMS Chapter 11.1--Volume Correction Factors, Volume 1,
Table 5A--Generalized Crude Oils and JP-4 Correction of Observed API
Gravity to API Gravity at 60 [deg]F, and Table 6A--Generalized Crude
Oils and JP-4 Correction of Volume to 60 [deg]F Against API Gravity at
60 [deg]F, API Standard 2540, First Edition, August 1980; reaffirmed
March 1997; incorporated by reference at Sec.  250.1202;
    (40) API MPMS Chapter 11.2.2--Compressibility Factors for
Hydrocarbons: 0.350-0.637 Relative Density (60 [deg]F/60 [deg]F) and -
50 [deg]F to 140 [deg]F Metering Temperature, Second Edition, October
1986; reaffirmed: December 2007; incorporated by reference at Sec.
250.1202;
    (41) API MPMS Chapter 11--Physical Properties Data, Section 1--
Temperature and Pressure Volume Correction Factors for Generalized
Crude Oils, Refined Products, and Lubricating Oils; May 2004
(incorporating Addendum 1, September 2007); incorporated by reference
at Sec.  250.1202(a), (g), and (l);
    (42) API MPMS Chapter 11--Physical Properties Data, Addendum to
Section 2, Part 2--Compressibility Factors for Hydrocarbons,
Correlation of Vapor Pressure for Commercial Natural Gas Liquids, First
Edition, December 1994; reaffirmed, December 2002; incorporated by
reference at Sec.  250.1202;
    (43) API MPMS Chapter 12--Calculation of Petroleum Quantities,
Section 2--Calculation of Petroleum Quantities Using Dynamic
Measurement Methods and Volumetric Correction Factors, Part 1--
Introduction, Second Edition, May 1995; reaffirmed March 2002;
incorporated by reference at Sec.  250.1202;
    (44) API MPMS Chapter 12--Calculation of Petroleum Quantities,
Section 2--Calculation of Petroleum
[[Page 21971]]
Quantities Using Dynamic Measurement Methods and Volumetric Correction
Factors, Part 2--Measurement Tickets, Third Edition, June 2003;
incorporated by reference at Sec.  250.1202;
    (45) API MPMS Chapter 12--Calculation of Petroleum Quantities,
Section 2--Calculation of Petroleum Quantities Using Dynamic
Measurement Methods and Volumetric Correction Factors, Part 3--Proving
Reports; First Edition, reaffirmed 2009; incorporated by reference at
Sec.  250.1202(a) and (g);
    (46) API MPMS Chapter 12--Calculation of Petroleum Quantities,
Section 2--Calculation of Petroleum Quantities Using Dynamic
Measurement Methods and Volumetric Correction Factors, Part 4--
Calculation of Base Prover Volumes by the Waterdraw Method, First
Edition, December 1997; reaffirmed, 2009; incorporated by reference at
Sec.  250.1202(a), (f), and (g);
    (47) API MPMS Chapter 14--Natural Gas Fluids Measurement, Section
3--Concentric, Square-Edged Orifice Meters, Part 1--General Equations
and Uncertainty Guidelines, Third Edition, September 1990; reaffirmed,
January 2003; incorporated by reference at Sec.  250.1203;
    (48) API MPMS Chapter 14--Natural Gas Fluids Measurement, Section
3--Concentric, Square-Edged Orifice Meters, Part 2--Specification and
Installation Requirements, Fourth Edition, April 2000; reaffirmed March
2006; incorporated by reference at Sec.  250.1203;
    (49) API MPMS Chapter 14--Natural Gas Fluids Measurement, Section
3--Concentric, Square-Edged Orifice Meters; Part 3--Natural Gas
Applications; Third Edition, August 1992; Errata March 1994,
reaffirmed, February 2009; incorporated by reference at Sec.  250.1203;
    (50) API MPMS Chapter 14.5/GPA Standard 2172-09; Calculation of
Gross Heating Value, Relative Density, Compressibility and Theoretical
Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody
Transfer; Third Edition, January 2009; incorporated by reference at
Sec.  250.1203;
    (51) API MPMS Chapter 14--Natural Gas Fluids Measurement, Section
6--Continuous Density Measurement, Second Edition, April 1991;
reaffirmed, February 2006; incorporated by reference at Sec.  250.1203;
    (52) API MPMS Chapter 14--Natural Gas Fluids Measurement, Section
8--Liquefied Petroleum Gas Measurement, Second Edition, July 1997;
reaffirmed, March 2006; incorporated by reference at Sec.  250.1203;
    (53) API MPMS Chapter 20--Section 1--Allocation Measurement, First
Edition, September 1993; reaffirmed October 2006; incorporated by
reference at Sec.  250.1202;
    (54) API MPMS Chapter 21--Flow Measurement Using Electronic
Metering Systems, Section 1--Electronic Gas Measurement, First Edition,
August 1993; reaffirmed, July 2005; incorporated by reference at Sec.
250.1203;
    (55) API MPMS Chapter 21--Flow Measurement Using Electronic
Metering Systems, Section 2--Electronic Liquid Volume Measurement Using
Positive Displacement and Turbine Meters; First Edition, June 1998;
incorporated by reference at Sec.  250.1202(a);
    (56) API MPMS Chapter 21--Flow Measurement Using Electronic
Metering Systems, Addendum to Section 2--Flow Measurement Using
Electronic Metering Systems, Inferred Mass; First Edition, reaffirmed
February 2006; incorporated by reference at Sec.  250.1202(a);
    (57) API RP 2A-WSD, Recommended Practice for Planning, Designing
and Constructing Fixed Offshore Platforms--Working Stress Design,
Twenty-first Edition, December 2000; Errata and Supplement 1, December
2002; Errata and Supplement 2, September 2005; Errata and Supplement 3,
October 2007; incorporated by reference at Sec. Sec.  250.901, 250.908,
250.919, and 250.920;
    (58) API RP 2D, Operation and Maintenance of Offshore Cranes, Sixth
Edition, May 2007; incorporated by reference at Sec.  250.108;
    (59) API RP 2FPS, RP for Planning, Designing, and Constructing
Floating Production Systems; First Edition, March 2001; incorporated by
reference at Sec.  250.901;
    (60) API RP 2I, In-Service Inspection of Mooring Hardware for
Floating Structures; Third Edition, April 2008; incorporated by
reference at Sec.  250.901(a) and (d);
    (61) ANSI/API RP 2N, Third Edition, ``Recommended Practice for
Planning, Designing, and Constructing Structures and Pipelines for
Arctic Conditions'', Third Edition, April 2015; incorporated by
reference at Sec.  250.470(g);
    (62) API RP 2RD, Recommended Practice for Design of Risers for
Floating Production Systems (FPSs) and Tension-Leg Platforms (TLPs),
First Edition, June 1998; reaffirmed, May 2006, Errata, June 2009;
incorporated by reference at Sec. Sec.  250.733, 250.800(c),
250.901(a), (d), and 250.1002(b);
    (63) API RP 2SK, Design and Analysis of Stationkeeping Systems for
Floating Structures, Third Edition, October 2005, Addendum, May 2008,
reaffirmed June 2015; incorporated by reference at Sec. Sec.
250.800(c) and 250.901(a) and (d);
    (64) API RP 2SM, Recommended Practice for Design, Manufacture,
Installation, and Maintenance of Synthetic Fiber Ropes for Offshore
Mooring, First Edition, March 2001, Addendum, May 2007; incorporated by
reference at Sec. Sec.  250.800(c) and 250.901(a) and (d);
    (65) API RP 2T, Recommended Practice for Planning, Designing, and
Constructing Tension Leg Platforms, Second Edition, August 1997;
incorporated by reference at Sec.  250.901(a) and (d);
    (66) ANSI/API RP 14B, Design, Installation, Operation, Test, and
Redress of Subsurface Safety Valve Systems, Sixth Edition, September
2015; incorporated by reference at Sec. Sec.  250.802(b), 250.803(a),
250.814(d), 250.828(c), and 250.880(c);
    (67) API RP 14C, Recommended Practice for Analysis, Design,
Installation, and Testing of Basic Surface Safety Systems for Offshore
Production Platforms, Seventh Edition, March 2001, reaffirmed: March
2007; incorporated by reference at Sec. Sec.  250.125(a), 250.292(j),
250.841(a), 250.842(a), 250.850, 250.852(a), 250.855, 250.856(a),
250.858(a), 250.862(e), 250.865(a), 250.867(a), 250.869(a) through (c),
250.872(a), 250.873(a), 250.874(a), 250.880(b) and (c), 250.1002(d),
250.1004(b), 250.1628(c) and (d), 250.1629(b), and 250.1630(a);
    (68) API RP 14E, Recommended Practice for Design and Installation
of Offshore Production Platform Piping Systems, Fifth Edition, October
1991; reaffirmed, January 2013; incorporated by reference at Sec. Sec.
250.841(b), 250.842(a), and 250.1628(b) and (d);
    (69) API RP 14F, Recommended Practice for Design, Installation, and
Maintenance of Electrical Systems for Fixed and Floating Offshore
Petroleum Facilities for Unclassified and Class 1, Division 1 and
Division 2 Locations, Upstream Segment, Fifth Edition, July 2008,
reaffirmed: April 2013; incorporated by reference at Sec. Sec.
250.114(c), 250.842(c), 250.862(e), and 250.1629(b);
    (70) API RP 14FZ, Recommended Practice for Design, Installation,
and Maintenance of Electrical Systems for Fixed and Floating Offshore
Petroleum Facilities for Unclassified and Class I, Zone 0, Zone 1 and
Zone 2 Locations, Second Edition, May 2013; incorporated by reference
at Sec. Sec.  250.114(c), 250.842(c), 250.862(e), and 250.1629(b);
    (71) API RP 14G, Recommended Practice for Fire Prevention and
Control on Fixed Open-type Offshore Production Platforms, Fourth
Edition, April 2007; Reaffirmed, January 2013; incorporated by
reference at
[[Page 21972]]
Sec. Sec.  250.859(a), 250.862(e), 250.880(c), and 250.1629(b);
    (72) API RP 14J, Recommended Practice for Design and Hazards
Analysis for Offshore Production Facilities, Second Edition, May 2001;
reaffirmed: January 2013; incorporated by reference at Sec. Sec.
250.800(b) and (c), 250.842(c), and 250.901(a) and (d);
    (73) API RP 17H, Remotely Operated Tools and Interfaces on Subsea
Production Systems, Second Edition, June 2013; Errata, January 2014;
incorporated by reference at Sec.  250.734(a);
    (74) API RP 65, Recommended Practice for Cementing Shallow Water
Flow Zones in Deepwater Wells, First Edition, September 2002;
incorporated by reference at Sec.  250.415;
    (75) API RP 75, Recommended Practice for Development of a Safety
and Environmental Management Program for Offshore Operations and
Facilities, Third Edition, May 2004, reaffirmed May 2008; incorporated
by reference at Sec. Sec.  250.1900, 250.1902, 250.1903, 250.1909,
250.1920;
    (76) API RP 86, API Recommended Practice for Measurement of
Multiphase Flow; First Edition, September 2005; incorporated by
reference at Sec. Sec.  250.1202(a) and 250.1203(b);
    (77) API RP 90, Annular Casing Pressure Management for Offshore
Wells, First Edition, August 2006; incorporated by reference at Sec.
250.519;
    (78) API RP 500, Recommended Practice for Classification of
Locations for Electrical Installations at Petroleum Facilities
Classified as Class I, Division 1 and Division 2, Third Edition,
December 2012; Errata January 2014, incorporated by reference at
Sec. Sec.  250.114(a), 250.459, 250.842(a), 250.862(a) and (e),
250.872(a), 250.1628(b) and (d), and 250.1629(b);
    (79) API RP 505, Recommended Practice for Classification of
Locations for Electrical Installations at Petroleum Facilities
Classified as Class I, Zone 0, Zone 1, and Zone 2, First Edition,
November 1997; reaffirmed, August 2013; incorporated by reference at
Sec. Sec.  250.114(a), 250.459, 250.842(a), 250.862(a) and (e),
250.872(a), 250.1628(b) and (d), and 250.1629(b);
    (80) API RP 2556, Recommended Practice for Correcting Gauge Tables
for Incrustation, Second Edition, August 1993; reaffirmed November
2003; incorporated by reference at Sec.  250.1202;
    (81) API Spec. 2C, Specification for Offshore Pedestal Mounted
Cranes, Sixth Edition, March 2004, Effective Date: September 2004;
incorporated by reference at Sec.  250.108;
    (82) ANSI/API Spec. 6A, Specification for Wellhead and Christmas
Tree Equipment, Twentieth Edition, October 2010; Addendum 1, November
2011; Errata 2, November 2011; Addendum 2, November 2012; Addendum 3,
March 2013; Errata 3, June 2013; Errata 4, August 2013; Errata 5,
November 2013; Errata 6, March 2014; Errata 7, December 2014; Errata 8,
February 2016; Addendum 4, June 2016; Errata 9, June 2016; Errata 10,
August 2016; incorporated by reference at Sec. Sec.  250.730,
250.802(a), 250.803(a), 250.833, 250.873(b), 250.874(g), and
250.1002(b);
    (83) API Spec. 6AV1, Specification for Verification Test of
Wellhead Surface Safety Valves and Underwater Safety Valves for
Offshore Service, Second Edition, February 2013; incorporated by
reference at Sec. Sec.  250.802(a), 250.833, 250.873(b), and
250.874(g);
    (84) API STD 6AV2, Installation, Maintenance, and Repair of Surface
Safety Valves and Underwater Safety Valves Offshore; First Edition,
March 2014; Errata 1, August 2014; incorporated by reference at
Sec. Sec.  250.820, 250.834, 250.836, and 250.880(c)
    (85) ANSI/API Spec. 6D, Specification for Pipeline Valves, Twenty-
third Edition, April 2008; Effective Date: October 1, 2008, Errata 1,
June 2008; Errata 2, November 2008; Errata 3, February 2009; Addendum
1, October 2009; Contains API Monogram Annex as Part of U.S. National
Adoption; ISO 14313:2007 (Identical), Petroleum and natural gas
industries--Pipeline transportation systems--Pipeline valves;
incorporated by reference at Sec.  250.1002(b);
    (86) ANSI/API Spec. 11D1, Packers and Bridge Plugs, Second Edition,
July 2009; incorporated by reference at Sec. Sec.  250.518, 250.619,
and 250.1703;
    (87) ANSI/API Spec. 14A, Specification for Subsurface Safety Valve
Equipment, Eleventh Edition, October 2005, reaffirmed, June 2012;
incorporated by reference at Sec. Sec.  250.802 and 250.803(a);
    (88) ANSI/API Spec. 16A, Specification for Drill-through Equipment,
Third Edition, June 2004, reaffirmed August 2010; incorporated by
reference at Sec.  250.730;
    (89) ANSI/API Spec. 16C, Specification for Choke and Kill Systems,
First Edition, January 1993, reaffirmed July 2010; incorporated by
reference at Sec.  250.730;
    (90) API Spec. 16D, Specification for Control Systems for Drilling
Well Control Equipment and Control Systems for Diverter Equipment,
Second Edition, July 2004, reaffirmed August 2013; incorporated by
reference at Sec.  250.730;
    (91) ANSI/API Spec. 17D, Design and Operation of Subsea Production
Systems--Subsea Wellhead and Tree Equipment, Second Edition, May 2011;
incorporated by reference at Sec.  250.730;
    (92) ANSI/API Spec. 17J, Specification for Unbonded Flexible Pipe,
Third Edition, July 2008, incorporated by reference at Sec. Sec.
250.852(e), 250.1002(b), and 250.1007(a).
    (93) ANSI/API Spec. Q1, Specification for Quality Management System
Requirements for Manufacturing Organizations for the Petroleum and
Natural Gas Industry, Ninth Edition, June 2013; Errata, February 2014;
Errata 2, March 2014; Addendum 1, June 2016; incorporated by reference
at Sec. Sec.  250.730 and 250.801(b) and (c);
    (94) API Standard 53, Blowout Prevention Equipment Systems for
Drilling Wells, Fourth Edition, November 2012, Addendum 1, July 2016,
incorporated by reference at Sec. Sec.  250.730, 250.734, 250.735,
250.736, 250.737, and 250.739;
    (95) API Standard 65--Part 2, Isolating Potential Flow Zones During
Well Construction; Second Edition, December 2010; incorporated by
reference at Sec. Sec.  250.415(f) and 250.420(a);
    (96) API Standard 2552, USA Standard Method for Measurement and
Calibration of Spheres and Spheroids, First Edition, 1966; reaffirmed,
October 2007; incorporated by reference at Sec.  250.1202;
    (97) API Standard 2555, Method for Liquid Calibration of Tanks,
First Edition, September 1966; reaffirmed March 2002; incorporated by
reference at Sec.  250.1202;
    (f) American Society of Mechanical Engineers (ASME), 22 Law Drive,
P.O. Box 2900, Fairfield, NJ 07007-2900; http://www.asme.org; phone: 1-
800-843-2763.
    (1) 2017 ASME Boiler and Pressure Vessel Code (BPVC), Section I,
Rules for Construction of Power Boilers, 2017 Edition, July 1, 2017,
incorporated by reference at Sec. Sec.  250.851(a) and 250.1629(b).
    (2) 2017 ASME Boiler and Pressure Vessel Code, Section IV, Rules
for Construction of Heating Boilers, 2017 Edition, July 1, 2017,
incorporated by reference at Sec. Sec.  250.851(a) and 250.1629(b).
    (3) 2017 ASME Boiler and Pressure Vessel Code, Section VIII, Rules
for Construction of Pressure Vessels; Division 1, 2017 Edition; July 1,
2017, incorporated by reference at Sec. Sec.  250.851(a) and
250.1629(b).
    (4) 2017 ASME Boiler and Pressure Vessel Code, Section VIII, Rules
for Construction of Pressure Vessels; Division 2: Alternative Rules,
2017 Edition, July 1, 2017, incorporated by
[[Page 21973]]
reference at Sec. Sec.  250.851(a) and 250.1629(b).
    (5) 2017 ASME Boiler and Pressure Vessel Code, Section VIII, Rules
for Construction of Pressure Vessels; Division 3: Alternative Rules for
Construction of High Pressure Vessels, 2017 Edition, July 1, 2017,
incorporated by reference at Sec. Sec.  250.851(a) and 250.1629(b).
    (g) American Society for Testing and Materials (ASTM), ASTM
Standards, 100 Bar Harbor Drive, P.O. Box C700, West Conshohocken, PA
19428-2959; http://www.astm.org; phone: 1-877-909-2786:
    (1) ASTM Standard C 33-07, approved December 15, 2007, Standard
Specification for Concrete Aggregates; incorporated by reference at
Sec.  250.901;
    (2) ASTM Standard C 94/C 94M-07, approved January 1, 2007, Standard
Specification for Ready-Mixed Concrete; incorporated by reference at
Sec.  250.901;
    (3) ASTM Standard C 150-07, approved May 1, 2007, Standard
Specification for Portland Cement; incorporated by reference at Sec.
250.901;
    (4) ASTM Standard C 330-05, approved December 15, 2005, Standard
Specification for Lightweight Aggregates for Structural Concrete;
incorporated by reference at Sec.  250.901;
    (5) ASTM Standard C 595-08, approved January 1, 2008, Standard
Specification for Blended Hydraulic Cements; incorporated by reference
at Sec.  250.901;
    (h) American Welding Society (AWS), AWS Codes, 8669 NW 36 Street,
#130, Miami, FL 33126; http://www.aws.org;phone: 800-443-9353:
    (1) AWS D1.1:2000, Structural Welding Code--Steel, 17th Edition,
October 18, 1999; incorporated by reference at Sec.  250.901;
    (2) AWS D1.4-98, Structural Welding Code--Reinforcing Steel, 1998
Edition; incorporated by reference at Sec.  250.901;
    (3) AWS D3.6M:1999, Specification for Underwater Welding (1999);
incorporated by reference at Sec.  250.901.
    (i) National Association of Corrosion Engineers (NACE)
International, NACE Standards, Park Ten Place, Houston, TX 77084;
http://www.nace.org; phone: 281-228-6200:
    (1) NACE Standard MR0175-2003, Standard Material Requirements,
Metals for Sulfide Stress Cracking and Stress Corrosion Cracking
Resistance in Sour Oilfield Environments, Revised January 17, 2003;
incorporated by reference at Sec. Sec.  250.490 and 250.901;
    (2) NACE Standard RP0176-2003, Standard Recommended Practice,
Corrosion Control of Steel Fixed Offshore Structures Associated with
Petroleum Production; incorporated by reference at Sec.  250.901.
    (j) International Organization for Standardization (ISO), 1, ch. de
la Voie-Creuse, CP 56, CH-1211, Geneva 20, Switzerland; www.iso.org;
phone: 41-22-749-01-11:
    (1) ISO/IEC (International Electrotechnical Commission) 17011,
Conformity assessment--General requirements for accreditation bodies
accrediting conformity assessment bodies, First edition 2004-09-01;
Corrected version 2005-02-15; incorporated by reference at Sec. Sec.
250.1900, 250.1903, 250.1904, and 250.1922.
    (2) ISO/IEC 17021-1, Conformity assessment--Requirements for bodies
providing audit and certification of management systems--Part 1:
Requirements, First Edition, June 2015, incorporated by reference at
Sec.  250.730(d).
    (3) [Reserved]
    (k) Center for Offshore Safety (COS), 1990 Post Oak Blvd., Suite
1370, Houston, TX 77056; www.centerforoffshoresafety.org; phone: 832-
495-4925.
    (1) COS Safety Publication COS-2-01, Qualification and Competence
Requirements for Audit Teams and Auditors Performing Third-party SEMS
Audits of Deepwater Operations, First Edition, Effective Date October
2012; incorporated by reference at Sec. Sec.  250.1900, 250.1903,
250.1904, and 250.1921.
    (2) COS Safety Publication COS-2-03, Requirements for Third-party
SEMS Auditing and Certification of Deepwater Operations, First Edition,
Effective Date October 2012; incorporated by reference at Sec. Sec.
250.1900, 250.1903, 250.1904, and 250.1920.
    (3) COS Safety Publication COS-2-04, Requirements for Accreditation
of Audit Service Providers Performing SEMS Audits and Certification of
Deepwater Operations, First Edition, Effective Date October 2012;
incorporated by reference at Sec. Sec.  250.1900, 250.1903, 250.1904,
and 250.1922.
Subpart B--Plans and Information
0
4. Amend Sec.  250.292 by revising paragraph (p) to read as follows:
Sec.  250.292   What must the DWOP contain?
* * * * *
    (p) If you propose to use a pipeline free standing hybrid riser
(FSHR) on a permanent installation that utilizes a buoyancy air can
suspended from the top of the riser, you must provide the following
information in your DWOP in the discussions required by paragraphs (f)
and (g) of this section:
    (1) A detailed description and drawings of the FSHR, buoy, and the
associated connection system;
    (2) Detailed information regarding the system used to connect the
FSHR to the buoyancy air can, and associated redundancies; and
    (3) Descriptions of your monitoring system and monitoring plan to
monitor the pipeline FSHR and the associated connection system for
fatigue, stress, and any other abnormal condition (e.g., corrosion)
that may negatively impact the riser system's integrity.
* * * * *
Subpart D--Oil and Gas Drilling Operations
0
5. Amend Sec.  250.413 by revising paragraph (g) to read as follows:
Sec.  250.413   What must my description of well drilling design
criteria address?
* * * * *
    (g) A single plot containing curves for estimated pore pressures,
formation fracture gradients, proposed drilling fluid weights (surface
and downhole), planned safe drilling margin, and casing setting depths
in true vertical measurements;
* * * * *
0
6. Amend Sec.  250.414 by revising paragraphs (c)(2) and (c)(3) to read
as follows:
Sec.  250.414   What must my drilling prognosis include?
* * * * *
    (c) * * *
    (2) In lieu of meeting the criteria in paragraph (c)(1)(ii) of this
section, you may use an equivalent downhole mud weight as specified in
your APD, provided that you submit adequate documentation (such as risk
modeling data, off-set well data, analog data, seismic data) to justify
the alternative equivalent downhole mud weight. You may submit such
justification in advance of your full APD, and BSEE may consider such
justification for approval when submitted. Any such approval will be
contingent upon your confirmation in the APD that your plans and the
information underlying your approved justification have not changed.
    (3) When determining the pore pressure and lowest estimated
fracture gradient for a specific interval, you must consider related
off-set and analogous well behavior observations, if available.
* * * * *
0
7. Amend Sec.  250.420 by revising paragraph (a)(6) to read as follows:
[[Page 21974]]
Sec.  250.420   What well casing and cementing requirements must I
meet?
* * * * *
    (a) * * *
    (6) Provide adequate centralization consistent with the guidelines
of API Standard 65--Part 2 (as incorporated by reference in Sec.
250.198); and
* * * * *
0
8. Amend Sec.  250.421 by revising paragraphs (c), (d), (e), and (f) to
read as follows:
Sec.  250.421   What are the casing and cementing requirements by type
of casing string?
* * * * *
------------------------------------------------------------------------
                                                          Cementing
         Casing type           Casing requirements      requirements
------------------------------------------------------------------------

                              * * * * * * *
(c) Surface.................  Design casing and     Use enough cement to
                               select setting        fill the calculated
                               depths based on       annular space to at
                               relevant              least 200 feet
                               engineering and       measured depth (MD)
                               geologic factors.     inside the
                               These factors         conductor casing.
                               include the          When geologic
                               presence or absence   conditions such as
                               of hydrocarbons,      near-surface
                               potential hazards,    fractures and
                               and water depths.     faulting exist, you
                                                     must use enough
                                                     cement to fill the
                                                     calculated annular
                                                     space to the
                                                     mudline.
(d) Intermediate............  Design casing and     Use enough cement to
                               select setting        cover and isolate
                               depth based on        all hydrocarbon-
                               anticipated or        bearing zones and
                               encountered           isolate abnormal
                               geologic              pressure intervals
                               characteristics or    from normal
                               wellbore conditions.  pressure intervals
                                                     in the well.
                                                    As a minimum, you
                                                     must cement the
                                                     annular space 500
                                                     feet MD above the
                                                     casing shoe and 500
                                                     feet MD above each
                                                     zone to be
                                                     isolated.
(e) Production..............  Design casing and     Use enough cement to
                               select setting        cover or isolate
                               depth based on        all hydrocarbon-
                               anticipated or        bearing zones above
                               encountered           the shoe.
                               geologic             As a minimum, you
                               characteristics or    must cement the
                               wellbore conditions.  annular space at
                                                     least 500 feet MD
                                                     above the casing
                                                     shoe and 500 feet
                                                     MD above the
                                                     uppermost
                                                     hydrocarbon-bearing
                                                     zone.
(f) Liners..................  If you use a liner    Same as cementing
                               as surface casing,    requirements for
                               you must set the      specific casing
                               top of the liner at   types. For example,
                               least 200 feet MD     a liner used as
                               above the previous    intermediate casing
                               casing/liner shoe..   must be cemented
                              If you use a liner     according to the
                               as an intermediate    cementing
                               string below a        requirements for
                               surface string or     intermediate
                               production casing     casing.
                               below an
                               intermediate
                               string, you must
                               set the top of the
                               liner at least 100
                               feet MD above the
                               previous casing
                               shoe..
                              You may not use a
                               liner as conductor
                               casing.
                              A subsea well casing
                               string whose top is
                               above the mudline
                               and that has been
                               cemented back to
                               the mudline will
                               not be considered a
                               liner.
------------------------------------------------------------------------
0
9. Amend Sec.  250.423 by revising paragraphs (a) and (b) to read as
follows:
Sec.  250.423   What are the requirements for casing and liner
installation?
* * * * *
    (a) You must ensure that the latching mechanisms or lock down
mechanisms are engaged upon successfully installing the casing string.
    (b) If you run a liner that has a latching mechanism or lock down
mechanism, you must ensure that the latching mechanisms or lock down
mechanisms are engaged upon successfully installing the liner.
* * * * *
0
10. Amend Sec.  250.427 by revising paragraph (b) to read as follows:
Sec.  250.427   What are the requirements for pressure integrity tests?
* * * * *
    (b) While drilling, you must maintain the safe drilling margin
identified in Sec.  250.414. When you cannot maintain the safe drilling
margin, you must:
    (1) Suspend drilling operations and submit proposed remedial
actions to the District Manager. The District Manager must review and
approve your proposed remedial actions, which may include limited
drilling through a lost circulation zone; or
    (2) Notify the District Manager and take further action in
accordance with API Bulletin 92L (as incorporated by reference in Sec.
250.198), if appropriate. You must submit a revised permit documenting
any responsive actions taken.
0
 11. Amend Sec.  250.428 by revising paragraphs (c) and (d) to read as
follows:
Sec.  250.428   What must I do in certain cementing and casing
situations?
* * * * *
[[Page 21975]]
------------------------------------------------------------------------
     If you encounter the following
               situation:                      Then you must . . .
------------------------------------------------------------------------

                              * * * * * * *
(c) Have indication of inadequate        (1) Locate the top of cement
 cement job (such as unplanned lost       by:
 returns, no cement returns to mudline   (i) Running a temperature
 or expected height, cement channeling,   survey;
 or failure of equipment),               (ii) Running a cement
                                          evaluation log;
                                         (iii) Using tracers in the
                                          cement and logging them prior
                                          to drill out; or
                                         (iv) Using a combination of
                                          these techniques.
                                         (2) Determine if your cement
                                          job is inadequate. If your
                                          cement job is determined to be
                                          inadequate, refer to paragraph
                                          (d) of this section.
                                         (3) If your cement job is
                                          determined to be adequate,
                                          report the results to the
                                          District Manager in your
                                          submitted WAR.
(d) Inadequate cement job,.............  Comply with Sec.
                                          250.428(c)(1) and take
                                          remedial actions. The District
                                          Manager must review and
                                          approve all remedial actions
                                          either through a previously
                                          approved contingency plan
                                          within the permit or remedial
                                          actions included in a revised
                                          permit before you may take
                                          them, unless immediate actions
                                          must be taken to ensure the
                                          safety of the crew or to
                                          prevent a well-control event.
                                          If you complete any immediate
                                          action to ensure the safety of
                                          the crew or to prevent a well-
                                          control event, submit a
                                          description of the action to
                                          the District Manager when that
                                          action is complete. Any
                                          changes to the well program,
                                          that are not included in the
                                          approved permit, will require
                                          submittal of a certification
                                          by a professional engineer
                                          (PE) certifying that they have
                                          reviewed and approved the
                                          proposed changes. You must
                                          also meet any other
                                          requirements of the District
                                          Manager for remedial actions.

                              * * * * * * *
------------------------------------------------------------------------
0
12. Amend Sec.  250.433 by revising paragraph (b) to read as follows:
Sec.  250.433   What are the diverter actuation and testing
requirements?
* * * * *
    (b) For floating drilling operations with a subsea BOP stack, you
must actuate the diverter system within 7 days after the previous
actuation. For subsequent testing, you may partially actuate the
diverter element and a flow test is not required.
* * * * *
0
13. Amend Sec.  250.461 by revising paragraph (b) to read as follows:
Sec.  250.461   What are the requirements for directional and
inclination surveys?
* * * * *
    (b) Survey requirements for a directional well. You must conduct
directional surveys on each directional well and digitally record the
results. Surveys must give both inclination and azimuth at intervals
not to exceed 500 feet during the normal course of drilling. Intervals
during angle-changing portions of the hole may not exceed 180 feet.
* * * * *
0
14. Amend Sec.  250.462 by revising paragraphs (b) introductory text,
(e)(1)(ii), (e)(2)(i), (e)(3), and (e)(4) to read as follows:
Sec.  250.462   What are the source control, containment, and
collocated equipment requirements?
* * * * *
    (b) You must have access to and the ability to deploy Source
Control and Containment Equipment (SCCE) and all other necessary
supporting and collocated equipment to regain control of the well. SCCE
means the capping stack, cap-and-flow system, containment dome, and/or
other subsea and surface devices, equipment, and vessels, which have
the collective purpose to control a spill source and stop the flow of
fluids into the environment or to contain fluids escaping into the
environment based on the determinations outlined in paragraph (a) of
this section. This SCCE, supporting equipment, and collocated equipment
may include, but is not limited to, the following:
* * * * *
    (e) * * *
------------------------------------------------------------------------
                                Requirements, you        Additional
          Equipment                   must:              information
------------------------------------------------------------------------
(1) * * *
                              (ii) Pressure test    Pressure containing
                               pressure containing   critical components
                               critical components   are those
                               on a bi-annual        components that
                               basis, but not        will experience
                               later than 210 days   wellbore pressure
                               from the last         during a shut-in.
                               pressure test. All    These components
                               pressure testing      include, but are
                               must be witnessed     not limited to: All
                               by BSEE (if           blind rams,
                               available) and an     wellhead
                               independent third     connectors, and
                               party.                outlet valves.

                              * * * * * * *
(2) Production safety         (i) Meet or exceed    ....................
 systems used for flow and     the requirements
 capture operations.           set forth in
                               Subpart H,
                               excluding required
                               equipment that
                               would be installed
                               below the wellhead
                               or that is not
                               applicable to the
                               cap and flow
                               system.

                              * * * * * * *
(3) Subsea utility            Have all equipment    Subsea utility
 equipment,.                   utilized solely for   equipment includes,
                               containment           but is not limited
                               operations            to: Hydraulic power
                               available for         sources, debris
                               inspection at all     removal, and
                               times.                hydrate control
                                                     equipment.
[[Page 21976]]

(4) Collocated equipment      Have equipment        Collocated equipment
 designated by the operator    available for         includes, but is
 in the Regional Containment   inspection at all     not limited to,
 Demonstration (RCD) or Well   times.                dispersant
 Containment Plan (WCP),                             injection equipment
                                                     and other subsea
                                                     control equipment.
------------------------------------------------------------------------
Subpart E--Oil and Gas Well-Completion Operations
0
15. Amend Sec.  250.518 by revising paragraph (e)(1) and adding new
paragraph (g) to read as follows:
Sec.  250.518   Tubing and wellhead equipment.
* * * * *
    (e) * * *
    (1) The uppermost permanently installed packer and all permanently
installed bridge plugs qualified as mechanical barriers must comply
with ANSI/API Spec. 11D1 (as incorporated by reference in Sec.
250.198);
* * * * *
    (g) You must have two independent barriers, one being mechanical,
in the exposed center wellbore prior to removing the tree and/or well
control equipment.
0
16. Revise Sec.  250.519 to read as follows:
Sec.  250.519   What are the requirements for casing pressure
management?
    Once you install your wellhead, you must meet the casing pressure
management requirements of API RP 90 (as incorporated by reference in
Sec.  250.198) and the requirements of Sec. Sec.  250.519 through
250.531. If there is a conflict between API RP 90 and the casing
pressure requirements of this subpart, you must follow the requirements
of this subpart.
0
17. Revise Sec.  250.522 to read as follows:
Sec.  250.522   How do I manage the thermal effects caused by initial
production on a newly completed or recompleted well?
    A newly completed or recompleted well often has thermal casing
pressure during initial startup. Bleeding casing pressure during the
startup process is considered a normal and necessary operation to
manage thermal casing pressure; therefore, you do not need to evaluate
these operations as a casing diagnostic test. After 30 days of
continuous production, the initial production startup operation is
complete and you must perform casing diagnostic testing as required in
Sec. Sec.  250.521 and 250.523.
0
18. Amend Sec.  250.525 by revising paragraph (d) to read as follows:
Sec.  250.525   When am I required to take action from my casing
diagnostic test?
* * * * *
    (d) Any well that has sustained casing pressure (SCP) and is bled
down to prevent it from exceeding its MAWOP, except during initial
startup operations described in Sec.  250.522;
* * * * *
0
19. Revise Sec.  250.526 to read as follows:
Sec.  250.526   What do I submit if my casing diagnostic test requires
action?
    Within 14 days after you perform a casing diagnostic test requiring
action under Sec.  250.525:
----------------------------------------------------------------------------------------------------------------
You must submit either . .                              and it must include . . .
             .               to the appropriate . . .                                   You must also . . .
----------------------------------------------------------------------------------------------------------------
(a) a notification of       District Manager and copy   requirements under Sec.    submit an Application for
 corrective action; or,      the Regional Supervisor,    250.527,                   Permit to Modify or
                             Field Operations,                                      Corrective Action Plan
                                                                                    within 30 days of the
                                                                                    diagnostic test.
(b) a casing pressure       Regional Supervisor, Field  requirements under Sec.    .............................
 request,                    Operations,                 250.528.
----------------------------------------------------------------------------------------------------------------
0
20. Amend Sec.  250.530 by revising paragraph (b) to read as follows:
Sec.  250.530   What if my casing pressure request is denied?
* * * * *
    (b) You must submit the casing diagnostic test data to the
appropriate Regional Supervisor, Field Operations, within 14 days of
completion of the diagnostic test required under Sec.  250.523(e).
Subpart F--Oil and Gas Well-Workover Operations
0
21. Amend Sec.  250.601 by adding paragraph (m) to the definition of
``routine operations'' to read as follows:
Sec.  250.601   Definitions.
* * * * *
    (m) Acid treatments.
* * * * *
0
22. Remove and reserve Sec.  250.616
Sec.  250.616   [Reserved]
0
23. Amend Sec.  250.619 by revising paragraph (e)(1) and adding new
paragraph (g) to read as follows:
Sec.  250.619   Tubing and wellhead equipment.
* * * * *
    (e) * * *
    (1) The uppermost permanently installed packer and all permanently
installed bridge plugs qualified as mechanical barriers must comply
with ANSI/API Spec. 11D1 (as incorporated by reference in Sec.
250.198).
* * * * *
    (g) You must have two independent barriers, one being mechanical,
in the exposed center wellbore prior to removing the tree and/or well
control equipment.
Subpart G--Well Operations and Equipment
0
24. Amend Sec.  250.712 by adding paragraphs (g) and (h) to read as
follows:
Sec.  250.712   What rig unit movements must I report?
* * * * *
    (g) You are not required to report rig unit movements to and from
the safe zone during the course of permitted operations.
    (h) If a rig unit is already on a well, you are not required to
report any additional rig unit movements on that well.
0
25. Amend Sec.  250.720 by revising paragraph (a)(1) and adding
paragraphs (a)(3) and (d) to read as follows:
Sec.  250.720   When and how must I secure a well?
    (a) * * *
    (1) The events that would cause you to interrupt operations and
notify the District Manager include, but are not limited to, the
following:
    (i) Evacuation of the rig crew;
    (ii) Inability to keep the rig on location;
[[Page 21977]]
    (iii) Repair to major rig or well-control equipment;
    (iv) Observed flow outside the well's casing (e.g., shallow water
flow or bubbling); or
    (v) Impending National Weather Service-named tropical storm or
hurricane.
* * * * *
    (3) If you unlatch the BOP or LMRP:
    (i) Upon relatch of the BOP, you must test according to Sec.
250.734(b)(2), or
    (ii) Upon relatch of the LMRP, you must test according to Sec.
250.734(b)(3); and
    (iii) You must submit a revised permit with a written statement
from an independent third party certifying that the previous
certification under Sec.  250.731(c) remains valid and receive District
Manager approval before resuming operations.
* * * * *
    (d) You must have the equipment used solely for intervention
operations (e.g., tree interface tools) identified, readily available,
properly maintained, and available for BSEE inspection upon request.
This equipment is required for subsea completed wells with a tree
installed, that meet the following conditions:
    (1) Have a shut-in tubing pressure that is greater than the
hydrostatic pressure of the water column, or
    (2) Are not capable of having the annulus monitored.
0
26. Amend Sec.  250.722 by revising paragraph (a)(2) to read as
follows:
Sec.  250.722  What are the requirements for prolonged operations in a
well?
* * * * *
    (a) * * *
    (2) Report the results of your evaluation to the District Manager
and obtain approval of those results before resuming operations. Your
report must include calculations that indicate the well's integrity is
above the minimum safety factors, if an imaging tool or caliper is
used. District Manager approval is not required to resume operations if
you conducted a successful pressure test as approved in your permit.
You must document the successful pressure test in the WAR.
* * * * *
0
27. Amend Sec.  250.723 by revising the introductory text and paragraph
(c)(3) to read as follows:
Sec.  250.723   What additional safety measures must I take when I
conduct operations on a platform that has producing wells or has other
hydrocarbon flow?
    You must take the following safety measures when you conduct
operations with a rig unit on or jacked-up over a platform with
producing wells or that has other hydrocarbon flow:
* * * * *
    (c) * * *
    (3) A MODU moves within 500 feet of a platform. You may resume
production once the MODU is in place, secured, and ready to begin
operations.
* * * * *
0
28. Revise Sec.  250.724 to read as follows:
Sec.  250.724   What are the real-time monitoring requirements?
    (a) When conducting well operations with a subsea BOP or with a
surface BOP on a floating facility, or when operating in an high
pressure high temperature (HPHT) environment, you must gather and
monitor real-time well data using an independent, automatic, and
continuous monitoring system capable of recording, storing, and
transmitting data regarding the following:
    (1) The BOP control system;
    (2) The well's active fluid circulating system; and
    (3) The well's downhole conditions with the bottom hole assembly
tools (if any tools are installed).
    (b) You must transmit these data as they are gathered, barring
unforeseeable or unpreventable interruptions in transmission, and have
the capability to monitor the data, using qualified personnel in
accordance with a real-time monitoring plan, as provided in paragraph
(c) of this section.
    (c) You must develop and implement a real-time monitoring plan.
Your real-time monitoring plan, and all real-time monitoring data, must
be made available to BSEE upon request. Your real-time monitoring plan
must include the following:
    (1) A description of your real-time monitoring capabilities,
including the types of the data collected;
    (2) A description of how your real-time monitoring data will be
transmitted during operations, how the data will be labeled and
monitored by qualified personnel, and how the data will be stored as
required in Sec. Sec.  250.740 and 250.741;
    (3) A description of your procedures for providing BSEE access,
upon request, to your real-time monitoring data;
    (4) The qualifications of the personnel monitoring the data;
    (5) Your procedures for, and methods of, communication between rig
personnel and the monitoring personnel; and
    (6) Actions to be taken if you lose any real-time monitoring
capabilities or communications between rig personnel and monitoring
personnel, and a protocol for how you will respond to any significant
and/or prolonged interruption of monitoring capabilities or
communications, including your protocol for notifying BSEE of any
significant and/or prolonged interruptions.
0
29. Revise Sec.  250.730 to read as follows:
Sec.  250.730   What are the general requirements for BOP systems and
system components?
    (a) You must ensure that the BOP system and system components are
designed, installed, maintained, inspected, tested, and used properly
to ensure well control. The working-pressure rating of each BOP
component (excluding annular(s)) must exceed MASP as defined for the
operation. For a subsea BOP, the MASP must be determined at the
mudline. The BOP system includes the BOP stack, control system, and any
other associated system(s) and equipment. The BOP system and individual
components must be able to perform their expected functions and be
compatible with each other. Your BOP system must be capable of closing
and sealing the wellbore in the event of flow due to a kick, including
under anticipated flowing conditions for the specific well conditions,
without losing ram closure time and sealing integrity due to the
corrosiveness, volume, and abrasiveness of any fluids in the wellbore
that the BOP system may encounter. Your BOP system must meet the
following requirements:
    (1) The BOP requirements of API Standard 53 (incorporated by
reference in Sec.  250.198) and the requirements of Sec. Sec.  250.733
through 250.739. If there is a conflict between API Standard 53 and the
requirements of this subpart, you must follow the requirements of this
subpart.
    (2) The provisions of the following industry standards (all
incorporated by reference in Sec.  250.198) that apply to BOP systems:
    (i) ANSI/API Spec. 6A;
    (ii) ANSI/API Spec. 16A;
    (iii) ANSI/API Spec. 16C;
    (iv) API Spec. 16D; and
    (v) ANSI/API Spec. 17D.
    (3) For surface and subsea BOPs, the pipe and variable bore rams
installed in the BOP stack must be capable of effectively closing and
sealing on the tubular body of any drill pipe, workstring, and tubing
(excluding tubing with exterior control lines and flat packs) in the
hole under MASP, as defined for the operation, at the
[[Page 21978]]
proposed regulator settings of the BOP control system.
    (4) The current set of approved schematic drawings must be
available on the rig and at an onshore location. If you make any
modifications to the BOP or control system that will require changes to
your BSEE-approved schematic drawings, you must suspend operations
until you obtain approval from the District Manager.
    (b) You must ensure that the design, fabrication, maintenance, and
repair of your BOP system is in accordance with the requirements
contained in this part, applicable Original Equipment Manufacturer's
(OEM) recommendations unless otherwise directed by BSEE, and recognized
engineering practices. The training and qualification of repair and
maintenance personnel must meet or exceed applicable OEM training
recommendations unless otherwise directed by BSEE.
    (c) You must follow the failure reporting procedures contained in
API Standard 53, (incorporated by reference in Sec.  250.198), and:
    (1) You must provide a written notice of equipment failure to the
Chief, Office of Offshore Regulatory Programs (OORP), unless BSEE has
designated a third party as provided in paragraph (c)(4) of this
section, and the manufacturer of such equipment within 30 days after
the discovery and identification of the failure. A failure is any
condition that prevents the equipment from meeting the functional
specification.
    (2) You must ensure that an investigation and a failure analysis
are started within 120 days of the failure to determine the cause of
the failure, and are completed within 120 days upon starting the
investigation and failure analysis. You must also ensure that the
results and any corrective action are documented. You must ensure that
the analysis report is submitted to the Chief OORP, unless BSEE has
designated a third party as provided in paragraph (c)(4) of this
section, as well as the manufacturer. If you cannot complete the
investigation and analysis within the specified time, you must submit
an extension request detailing how you will complete the investigation
and analysis to BSEE for approval. You must submit the extension
request to the Chief, OORP.
    (3) If the equipment manufacturer notifies you that it has changed
the design of the equipment that failed or if you have changed
operating or repair procedures as a result of a failure, then you must,
within 30 days of such changes, report the design change or modified
procedures in writing to the Chief OORP, unless BSEE has designated a
third party as provided in paragraph (c)(4) of this section.
    (4) Submit notices and reports to the Chief, Office of Offshore
Regulatory Programs; Bureau of Safety and Environmental Enforcement;
45600 Woodland Road, Sterling, Virginia 20166. BSEE may designate a
third party to receive the data and reports on behalf of BSEE. If BSEE
designates a third party, you must submit the data and reports to the
designated third party.
    (d) If you plan to use a BOP stack manufactured after the effective
date of this regulation, you must use one manufactured pursuant to an
ANSI/API Spec. Q1 (as incorporated by reference in Sec.  250.198)
quality management system. Such quality management system must be
certified by an entity that meets the requirements of ISO/IEC 17021-1
(as incorporated by reference in Sec.  250.198).
    (1) BSEE may consider accepting equipment manufactured under
quality assurance programs other than ANSI/API Spec. Q1, provided you
submit a request to the Chief, OORP for approval, containing relevant
information about the alternative program.
    (2) You must submit this request to the Chief, OORP; Bureau of
Safety and Environmental Enforcement; 45600 Woodland Road, Sterling,
Virginia 20166.
0
30. Amend Sec.  250.731 by:
0
a. Removing paragraphs (d) and (f);
0
b. Redesignating paragraph (e) as (d); and
0
c. Revising paragraphs (a)(5) and (c) to read as follows:
Sec.  250.731   What information must I submit for BOP systems and
system components?
* * * * *
------------------------------------------------------------------------
         You must submit:                        Including:
------------------------------------------------------------------------
(a) * * *.........................  (5) Control system pressure and
                                     regulator settings needed to close
                                     each ram BOP under MASP as defined
                                     for the operation;

                              * * * * * * *
(c) Certification by an             Verification that:
 independent third party,           (1) Test data demonstrate the shear
                                     ram(s) will shear the drill pipe at
                                     the water depth as required in Sec.
                                       250.732;
                                    (2) The BOP was designed, tested,
                                     and maintained to perform under the
                                     maximum environmental and
                                     operational conditions anticipated
                                     to occur at the well;
                                    (3) The accumulator system has
                                     sufficient fluid to operate the BOP
                                     system without assistance from the
                                     charging system; and
                                    (4) If using a subsea BOP, a BOP in
                                     an HPHT environment as defined in
                                     Sec.   250.804(b), or a surface BOP
                                     on a floating facility, the BOP has
                                     not been compromised or damaged
                                     from previous service.

                              * * * * * * *
------------------------------------------------------------------------
0
31. Revise Sec.  250.732 to read as follows:
Sec.  250.732   What are the independent third party requirements for
BOP systems and system components?
    (a) Prior to beginning any operation requiring the use of any BOP,
you must submit verification by an independent third party and
supporting documentation as required by this paragraph to the
appropriate District Manager and Regional Supervisor.
[[Page 21979]]
------------------------------------------------------------------------
 You must submit verification and
     documentation related to:                      That:
------------------------------------------------------------------------
(1) Shear testing,................  (i) Demonstrates that the BOP will
                                     shear the tubular body of any drill
                                     pipe (excluding tool joints, bottom-
                                     hole tools, and bottom hole
                                     assemblies such as heavy-weight
                                     pipe or collars), workstring,
                                     tubing and associated exterior
                                     control lines and any electric-,
                                     wire-, and slick-line to be used in
                                     the well;
                                    (ii) Demonstrates the use of test
                                     protocols and analysis that
                                     represent recognized engineering
                                     practices for ensuring the
                                     repeatability and reproducibility
                                     of the tests, and that the testing
                                     was performed by a facility that
                                     meets generally accepted quality
                                     assurance standards;
                                    (iii) Provides a reasonable
                                     representation of field
                                     applications, taking into
                                     consideration the physical and
                                     mechanical properties of the
                                     tubular body of any drill pipe
                                     (excluding tool joints, bottom-hole
                                     tools, and bottom hole assemblies
                                     such as heavy-weight pipe or
                                     collars), workstring, tubing and
                                     associated exterior control lines
                                     and any electric-, wire-, and slick-
                                     line to be used in the well;
                                    (iv) Ensures testing was performed
                                     on the outermost edges of the
                                     shearing blades of the shear ram;
                                    (v) Demonstrates the shearing
                                     capacity of the BOP equipment to
                                     the physical and mechanical
                                     properties of the tubular body of
                                     any drill pipe (excluding tool
                                     joints, bottom-hole tools, and
                                     bottom hole assemblies such as
                                     heavy-weight pipe or collars),
                                     workstring, tubing and associated
                                     exterior control lines and any
                                     electric-, wire-, and slick-line to
                                     be used in the well; and
                                    (vi) Includes relevant testing
                                     results.
(2) Pressure integrity testing for  (i) Shows that testing is conducted
 sealing components, and             after the shearing is completed and
                                     prior to opening the component;
                                    (ii) Demonstrates that the equipment
                                     will seal at the rated working
                                     pressures (RWP) of the BOP for 5
                                     minutes; and
                                    (iii) Includes all relevant test
                                     results.
(3) Calculations                    Include shearing and sealing
                                     pressures for all pipe to be used
                                     in the well including corrections
                                     for MASP.
------------------------------------------------------------------------
    (b) The independent third-party must be a technical classification
society, a licensed professional engineering firm, or a registered
professional engineer capable of providing the required certifications
and verifications.
    (c) For wells in an HPHT environment, as defined by Sec.
250.804(b), you must submit verification by an independent third party
that it conducted a comprehensive review of the BOP system and related
equipment you propose to use. You must provide the independent third
party access to any facility associated with the BOP system or related
equipment during the review process. You must submit the verifications
required by this paragraph (c) to the appropriate District Manager and
Regional Supervisor before you begin any operations in an HPHT
environment with the proposed equipment.
------------------------------------------------------------------------
            You must submit:                        Including:
------------------------------------------------------------------------
(1) Verification that the independent
 third party conducted a detailed
 review of the design package to ensure
 that all critical components and
 systems meet recognized engineering
 practices,
(2) Verification that the designs of     (i) Identification of all
 individual components and the overall    reasonable potential modes of
 system have been proven in a testing     failure; and
 process that demonstrates the           (ii) Evaluation of the design
 performance and reliability of the       verification tests. The design
 equipment in a manner that is            verification tests must assess
 repeatable and reproducible,             the equipment for the
                                          identified potential modes of
                                          failure.
(3) Verification that the BOP equipment
 will perform as designed in the
 temperature, pressure, and environment
 that will be encountered, and
(4) Verification that the fabrication,   For the quality control and
 manufacture, and assembly of             assurance mechanisms, complete
 individual components and the overall    material and quality controls
 system uses recognized engineering       over all contractors,
 practices and quality control and        subcontractors, distributors,
 assurance mechanisms.                    and suppliers at every stage
                                          in the fabrication,
                                          manufacture, and assembly
                                          process.
------------------------------------------------------------------------
    (d) You must make all documentation that demonstrates compliance
with the requirements of this section available to BSEE upon request.
0
32. Amend Sec.  250.733 by:
0
a. Revising paragraphs (a)(1) and (b)(1); and
0
b. Adding paragraph (e) to read as follows:
Sec.  250.733   What are the requirements for a surface BOP stack?
    (a) * * *
    (1) The blind shear rams must be capable of shearing at any point
along the tubular body of any drill pipe (excluding tool joints,
bottom-hole tools, and bottom hole assemblies that include heavy-weight
pipe or collars), workstring, tubing and associated exterior control
lines, and any electric-, wire-, and slick-line that is in the hole and
sealing the wellbore after shearing. Prior to April 29, 2021, if your
blind shear rams are unable to cut any electric-, wire-, or slick-line
under MASP as defined for the operation and seal the wellbore, you must
use an alternative cutting device capable of shearing the lines before
closing the BOP. This device must be available on the rig floor during
operations that require their use.
* * * * *
    (b) * * *
    (1) On new floating production facilities installed after April 29,
2021, that include a surface BOP, follow the BOP requirements in Sec.
250.734(a)(1).
* * * * *
    (e) Additional requirements for surface BOP systems used in well-
completion, workover, and decommissioning operations. The minimum BOP
system for well-completion, workover, and decommissioning operations
must meet the appropriate standards from the following table:
[[Page 21980]]
------------------------------------------------------------------------
                                    The minimum BOP stack must include .
            When . . .                               . .
------------------------------------------------------------------------
(1) The expected pressure is less   Three BOPs consisting of an annular,
 than 5,000 psi,                     one set of pipe rams, and one set
                                     of blind-shear rams.
(2) The expected pressure is 5,000  Four BOPs consisting of an annular,
 psi or greater or you use           two sets of pipe rams, and one set
 multiple tubing strings,            of blind-shear rams.
(3) You handle multiple tubing      Four BOPs consisting of an annular,
 strings simultaneously,             one set of pipe rams, one set of
                                     dual pipe rams, and one set of
                                     blind-shear rams.
(4) You use a tapered drill pipe,   At least one set of pipe rams that
 work string, or tubing,             are capable of sealing around each
                                     size of drill pipe, work string, or
                                     tubing. If the expected pressure is
                                     greater than 5,000 psi, then you
                                     must have at least two sets of pipe
                                     rams that are capable of sealing
                                     around the larger size drill pipe,
                                     work string, or tubing. You may
                                     substitute one set of variable bore
                                     rams for two sets of pipe rams.
(5) You use a surface BOP on a      The elements required by Sec.
 floating facility,                  250.733(b)(1) of this part.
------------------------------------------------------------------------
0
33. Amend Sec.  250.734 by:
0
a. Removing paragraph (a)(6)(vi); and
0
b. Revising paragraphs (a)(1)(ii), (a)(3), (a)(4), (a)(6)(iv),
(a)(6)(v), (a)(16), and (b) to read as follows:
Sec.  250.734   What are the requirements for a subsea BOP system?
    (a) * * *
------------------------------------------------------------------------
 When operating with a subsea
    BOP system, you must:               Additional requirements
------------------------------------------------------------------------
(1) * * *....................  (ii) Both shear rams must be capable of
                                shearing at any point along the tubular
                                body of any drill pipe (excluding tool
                                joints, bottom-hole tools, and bottom
                                hole assemblies such as heavy-weight
                                pipe or collars), workstring, tubing and
                                associated exterior control lines,
                                appropriate area for the liner or casing
                                landing string, shear sub on subsea test
                                tree, and any electric-, wire-, slick-
                                line in the hole; under MASP. At least
                                one shear ram must be capable of sealing
                                the wellbore after shearing under MASP
                                conditions as defined for the operation.
                                Any non-sealing shear ram(s) must be
                                installed below a sealing shear ram(s).

                              * * * * * * *
(3) Have the accumulator       The accumulator capacity must:
 capacity, to provide fast     (i) Close each required shear ram, ram
 closure of the BOP             locks, one pipe ram, and disconnect the
 components and to operate      LMRP.
 all critical functions;       (ii) Have the capability to perform ROV
                                functions within the required times
                                outlined in API Standard 53 with ROV or
                                flying leads.
                               (iii) Have bottles located subsea for the
                                autoshear and deadman (which may be
                                shared between those two systems) to
                                secure the wellbore. These bottles may
                                also be utilized to perform the
                                secondary control system functions
                                (e.g., ROV or acoustic functions).
                               (iv) Perform under MASP conditions as
                                defined for the operation.
(4) * * *....................  You must have the ROV intervention
                                capability to close each shear ram, ram
                                locks, one pipe ram, and disconnect the
                                LMRP under MASP conditions as defined
                                for the operation. You must be capable
                                of performing these functions in the
                                response times outlined in API Standard
                                53 (as incorporated by reference in Sec.
                                  250.198). The ROV panels on the BOP
                                and LMRP must be compliant with API RP
                                17H (as incorporated by reference in
                                Sec.   250.198).

                              * * * * * * *
(6) * * *....................  (iv) Autoshear/deadman functions and an
                                EDS mode must close, at a minimum, two
                                shear rams in sequence and be capable of
                                performing their expected shearing and
                                sealing action under MASP conditions as
                                defined for the operation.
                               (v) Your sequencing must allow a
                                sufficient delay when closing your two
                                shear rams in order to provide maximum
                                sealing efficiency.

                              * * * * * * *
(16) Use a BOP system that     (i) No later than May 1, 2023, you must
 has the following mechanisms   have the capability to position the
 and capabilities;              entire pipe completely within the area
                                of the shearing blade. This capability
                                cannot be a separate ram BOP or annular
                                preventer, but you may use those during
                                a planned shear.
                               (ii) If your control pods contain a
                                subsea electronic module with batteries,
                                a mechanism for personnel on the rig to
                                monitor the state of charge of the
                                subsea electronic module batteries in
                                the BOP control pods.
------------------------------------------------------------------------
    (b) If you suspend operations to make repairs to any part of the
subsea BOP system, you must stop operations at a safe downhole
location. Before resuming operations you must:
    (1) Submit a revised permit with a written statement from an
independent third party documenting the repairs and certifying that the
previous certification in Sec.  250.731(c) remains valid;
    (2) Upon relatch of the BOP, perform an initial subsea BOP test in
accordance with Sec.  250.737(d)(4), including deadman in accordance
with Sec.  250.737(d)(12)(vi). If repairs take longer than 30 days,
once the BOP is on deck, you must test in accordance with the
requirements of Sec.  250.737;
    (3) Upon relatch of the LMRP, you must test according to the
following:
    (i) Pressure test riser connector/gasket in accordance with Sec.
250.737(b) and (c);
    (ii) Pressure test choke and kill stabs at LMRP/BOP interface in
accordance with Sec.  250.737(b) and (c);
    (iii) Full function test of both pods and both control panels;
    (iv) Verify acoustic pod communication (if equipped); and
    (v) Deadman test with pressure test in accordance with Sec.
250.737(d)(12)(vi).
[[Page 21981]]
    (4) Receive approval from the District Manager.
* * * * *
0
34. Amend Sec.  250.735 by revising paragraph (a) to read as follows:
Sec.  250.735   What associated systems and related equipment must all
BOP systems include?
* * * * *
    (a) An accumulator system (as specified in API Standard 53,
incorporated by reference in Sec.  250.198). Your accumulator system
must have the fluid volume capacity and appropriate pre-charge
pressures in accordance with API Standard 53. If you supply the
accumulator regulators by rig air and do not have a secondary source of
pneumatic supply, you must equip the regulators with manual overrides
or other devices to ensure capability of hydraulic operations if rig
air is lost;
* * * * *
0
35. Amend Sec.  250.736 by revising paragraph (d)(5) to read as
follows:
Sec.  250.736   What are the requirements for choke manifolds, kelly-
type valves inside BOPs, and drill string safety valves?
* * * * *
    (d) * * *
    (5) When running casing, a safety valve in the open position
available on the rig floor to fit the casing string being run in the
hole. For subsea BOPs, the safety valve must be available on the rig
floor if the length of casing being run exceeds the water depth, which
would result in the casing being across the BOP stack and the rig floor
prior to crossing over to the drill pipe running string;
* * * * *
0
36. Amend Sec.  250.737 by:
0
a. Redesignating paragraph (a)(4) as (a)(5),
0
b. Adding new paragraph (a)(4),
0
c. Revising paragraphs (b) introductory text, (b)(2), (b)(3), (c),
(d)(2)(ii), (d)(3)(iii), (d)(3)(iv), (d)(3)(v), (d)(4)(i), (d)(4)(iii),
(d)(4)(v);
0
d. Removing paragraph (d)(4)(vi),
0
e. Revising paragraphs (d)(5), (d)(10), (d)(12)(iv), and (d)(12)(vi);
and
0
f. Adding paragraph (d)(13).
    The additions and revisions read as follows:
Sec.  250.737   What are the BOP system testing requirements?
* * * * *
    (a) * * *
    (4) In lieu of meeting the schedule established in paragraph (a)(2)
of this section, you may request that BSEE approve a 21-day BOP testing
frequency. To obtain BSEE approval, you must submit a request to the
appropriate BSEE Regional Supervisor, District Field Operations. Your
request must demonstrate that you have developed a BOP health
monitoring plan that includes certain system capabilities. As long as
your plan is consistent with recognized engineering and industry
practice, BSEE will approve your request if it includes the following:
    (i) Condition monitoring tools, including continuous surveillance
of sensor readings from the BOP control system, real-time condition
analysis and displays, functional pressure signal analysis, historical
sensor data;
    (ii) Failure propagation analysis;
    (iii) A failure tracking and resolution system that includes
detailed failure reports and identification of recurring problems; and
    (iv) Submission of quarterly reports of the data collected pursuant
to paragraphs (a)(4)(i)(iii) to the BSEE Regional Supervisor, District
Field Operations.
* * * * *
    (b) Pressure test procedures. When you pressure test the BOP
system, you must conduct a low-pressure test and a high-pressure test
for each BOP component (excluding test rams and non-sealing shear
rams). You must begin each test by conducting the low-pressure test
then transition to the high-pressure test. Each individual pressure
test must hold pressure long enough to demonstrate the tested
component(s) holds the required pressure. The table in this paragraph
(b) outlines your pressure test requirements.
------------------------------------------------------------------------
                                            According to the following
        You must conduct a . . .                 procedures . . .
------------------------------------------------------------------------

                              * * * * * * *
(2) High-pressure test for blind shear   (i) The high-pressure test must
 ram-type BOPs, ram-type BOPs, the        equal the RWP of the equipment
 choke manifold, outside of all choke     or be 500 psi greater than
 and kill side outlet valves (and         your calculated MASP, as
 annular gas bleed valves for subsea      defined for the operation for
 BOP), inside of all choke and kill       the applicable section of
 side outlet valves below uppermost       hole. Before you may test BOP
 ram, and other BOP components.           equipment to the MASP plus 500
                                          psi, the District Manager must
                                          have approved those test
                                          pressures in your permit.
                                         (ii) The blind shear ram (BSR)
                                          must be tested to:
                                            (A) MASP plus 500 psi for
                                             the hole section to which
                                             it is exposed; or
                                            (B) Full well MASP plus 500
                                             psi on initial latch up and
                                             all subsequent BSR pressure
                                             tests can be done to the
                                             casing/liner test pressure
                                             for the applicable hole
                                             section.
                                         (iii) The choke and kill side
                                          outlet valves must be tested
                                          to, except as provided in
                                          paragraph (d)(13) of this
                                          section:
                                            (A) MASP plus 500 psi for
                                             the hole section to which
                                             it is exposed; or
                                            (B) Full well MASP plus 500
                                             psi on initial latch up and
                                             all subsequent pressure
                                             tests can be done to the
                                             casing/liner test pressure
                                             for the applicable hole
                                             section.
(3) High-pressure test for annular-type  The high pressure test must
 BOPs, inside of choke or kill valves     equal 70 percent of the RWP of
 (and annular gas bleed valves for        the equipment or be 500 psi
 subsea BOP) above the uppermost ram      greater than your calculated
 BOP.                                     MASP, as defined for the
                                          operation for the applicable
                                          section of hole. Before you
                                          may test BOP equipment to the
                                          MASP plus 500 psi, the
                                          District Manager must have
                                          approved those test pressures
                                          in your APD or APM.

                              * * * * * * *
------------------------------------------------------------------------
[[Page 21982]]
    (c) Duration of pressure test. Each test must hold the required
pressure for 5 minutes, which must be recorded on a chart not exceeding
4 hours, or on a digital recorder. However, for surface BOP systems and
surface equipment of a subsea BOP system, a 3-minute test duration is
acceptable if recorded on a chart not exceeding 4 hours, or on a
digital recorder. The recorded test pressures must be within the middle
half of the chart range, i.e., cannot be within the lower or upper one-
fourth of the chart range. If the equipment does not hold the required
pressure during a test, you must correct the problem and retest the
affected component(s).
* * * * *
    (d) * * *
------------------------------------------------------------------------
             You must . . .               Additional requirements . . .
------------------------------------------------------------------------

                              * * * * * * *
(2) * * *..............................  (ii) Contact the District
                                          Manager at least 72 hours
                                          prior to beginning the initial
                                          test to allow BSEE
                                          representative(s) to witness
                                          testing.
(3) * * *..............................  (iii) Contact the District
                                          Manager at least 72 hours
                                          prior to beginning the stump
                                          test to allow BSEE
                                          representative(s) to witness
                                          testing.
                                         (iv) You must verify closure of
                                          all ROV intervention functions
                                          on your subsea BOP stack
                                          during the stump test.
                                         (v) You must follow paragraphs
                                          (b) and (c) of this section.
                                          Pressure testing of each ram
                                          and annular component is only
                                          required once.
(4) * * *..............................  (i) You must begin the initial
                                          subsea BOP test on the
                                          seafloor within 30 days of the
                                          stump test.

                              * * * * * * *
                                         (iii) You must pressure test
                                          well-control rams and annulars
                                          according to paragraphs (b)
                                          and (c) of this section.

                              * * * * * * *
                                         (v) You must test and verify
                                          closure of at least one set of
                                          rams during the initial subsea
                                          test through a ROV hot stab.
                                          You must confirm closure of
                                          the selected ram through the
                                          ROV hot stab with a 1,000 psi
                                          pressure test for 5 minutes.
(5) Alternate tests between control      (i) For two complete BOP
 stations.                                control stations you must:
                                         (A) Designate a primary and
                                          secondary station;
                                         (B) Alternate testing between
                                          the primary and secondary
                                          control stations on a weekly
                                          basis; and
                                         (C) For a subsea BOP, develop
                                          an alternating testing
                                          schedule to ensure the primary
                                          and secondary control stations
                                          will function each pod.
                                         (ii) Remote panels where all
                                          BOP functions are not included
                                          (e.g., life boat panels) must
                                          be function-tested upon the
                                          initial BOP tests.

                              * * * * * * *
(10) * * *.............................  If BSEE approves your request
                                          to utilize a 21-day BOP test
                                          frequency pursuant to Sec.
                                          250.737(a)(4), you may
                                          function test shear ram(s)
                                          BOPs every 21 days in
                                          accordance with the terms of
                                          that approval.

                              * * * * * * *
(12) * * *.............................  (iv) Following the deadman
                                          system test on the seafloor
                                          you must document the final
                                          remaining pressure of the
                                          subsea accumulator system.

                              * * * * * * *
                                         (vi) You must confirm closure
                                          of the BSR(s) with a 1,000 psi
                                          pressure test for 5 minutes.

                              * * * * * * *
(13) Pressure test the choke and kill    According to paragraph (b) of
 side outlet valves.                      this section, except as
                                          follows:
                                         (i) Test the wellbore side of
                                          the choke and kill side outlet
                                          valves above the uppermost
                                          pipe ram to the approved
                                          annular test pressure. Choke
                                          and kill side outlet valves
                                          below the uppermost pipe ram
                                          must be tested to MASP plus
                                          500 psi for the applicable
                                          hole section.
                                         (ii) For the 30 day BSR
                                          testing, test the wellbore
                                          side of the choke and kill
                                          side outlet valves between the
                                          upper most pipe ram and the
                                          upper most ram, to the casing/
                                          liner test pressure or annular
                                          test pressure, whichever is
                                          greater.
                                         (iii) For BOPs with only one
                                          choke and kill side outlet
                                          valve, you are only required
                                          to pressure test the choke and
                                          kill side outlet valves from
                                          the wellbore side.
------------------------------------------------------------------------
[[Page 21983]]
* * * * *
0
37. Amend Sec.  250.738 by revising paragraphs (b) introductory text,
(b)(3), (b)(4), (f), (i), (m), and (o) to read as follows:
Sec.  250.738  What must I do in certain situations involving BOP
equipment or systems?
* * * * *
------------------------------------------------------------------------
     If you encounter the following
               situation:                      Then you must . . .
------------------------------------------------------------------------
(b) Need to repair, replace, or
 reconfigure a surface BOP or subsea
 BOP system;

                              * * * * * * *
                                         (3) Submit a revised permit
                                          with a written statement from
                                          an independent third party
                                          documenting the repairs,
                                          replacement, or
                                          reconfiguration and certifying
                                          that the previous
                                          certification under Sec.
                                          250.731(c) remains valid.
                                         (4) You must receive approval
                                          from the District Manager
                                          prior to resuming operations.

                              * * * * * * *
(f) Plan to install casing rams or       Before running casing, perform
 casing shear rams in a surface BOP       a shell test to the permit
 stack;                                   approved test pressure of the
                                          BOP component above the casing
                                          ram/casing shear. If this
                                          installation was not included
                                          in your approved permit, and
                                          changes the BOP configuration
                                          approved in the APD or APM,
                                          you must notify and receive
                                          approval from the District
                                          Manager.

                              * * * * * * *
(i) You activate any shear ram and pipe  Retrieve, physically inspect,
 or casing is sheared;.                   and conduct a full pressure
                                          test of the BOP stack after
                                          the situation is fully
                                          controlled. You must submit to
                                          the District Manager a report
                                          from an independent third
                                          party certifying that the BOP
                                          is fit to return to service.

                              * * * * * * *
(m) Plan to utilize any other            Contact the District Manager
 circulating or ancillary equipment       and request approval in your
 (e.g., but not limited to, subsea        APD or APM. Your request must
 isolation device, subsea accumulator     include a report from an
 module, or gas handler) that is in       independent third party on the
 addition to the equipment required in    equipment's design and
 this subpart;                            suitability for its intended
                                          use as well as any other
                                          information required by the
                                          District Manager. The District
                                          Manager may impose any
                                          conditions regarding the
                                          equipment's capabilities,
                                          operation, and testing.

                              * * * * * * *
(o) You install redundant components     Comply with all testing,
 for well control in your BOP system      maintenance, and inspection
 that are in addition to the required     requirements in this subpart
 components of this subpart (e.g., pipe/  that are applicable to those
 variable bore rams, shear rams,          well-control components. If
 annular preventers, gas bleed lines,     any redundant component fails
 and choke/kill side outlets or lines);   a test, you must submit a
                                          report from an independent
                                          third party that describes the
                                          failure and confirms that
                                          there is no impact on the BOP
                                          that will make it unfit for
                                          well-control purposes. You
                                          must submit this report to the
                                          District Manager and receive
                                          approval before resuming
                                          operations. The District
                                          Manager may require you to
                                          provide additional information
                                          as needed to clarify or
                                          evaluate your report.

                              * * * * * * *
------------------------------------------------------------------------
0
38. Amend Sec.  250.739 by revising paragraph (b) introductory text to
read as follows:
Sec.  250.739   What are the BOP maintenance and inspection
requirements?
* * * * *
    (b) A major, detailed inspection of the well control system
components (including but not limited to riser, BOP, LMRP, and control
pods) must be performed every 5 years. This major inspection may be
performed in phased intervals. You must track and document all system
and component inspection dates. These records must be available on the
rig. An independent third party is required to review the inspection
results and must compile a detailed report of the inspection results,
including descriptions of any problems and how they were corrected. You
must make these reports available to BSEE upon request. This major
inspection must be performed every 5 years from the following
applicable dates, whichever is later:
* * * * *
0
39. Add an undesignated center and Sec.  250.750 to read as follows:
Coiled Tubing Operations
Sec.  250.750   What are the coiled tubing requirements?
    (a) For coiled tubing operations, you must follow the applicable
requirements of this subpart and you must meet the following minimum
requirements for the BOP system:
    (1) BOP system components must be in the following order from the
top down:
[[Page 21984]]
------------------------------------------------------------------------
                                 BOP system when
   BOP system when expected      expected surface   BOP system for wells
  surface pressures are less      pressures are      with returns taken
  than or equal to 3,500 psi       greater than     through an outlet on
                                    3,500 psi          the BOP stack
------------------------------------------------------------------------
(i) Stripper or annular-type    Stripper or        Stripper or annular-
 well control component.         annular-type       type well control
                                 well control       component.
                                 component.
(ii) Hydraulically-operated     Hydraulically-     Hydraulically-
 blind rams.                     operated blind     operated blind rams.
                                 rams.
(iii) Hydraulically-operated    Hydraulically-     Hydraulically-
 shear rams.                     operated shear     operated shear rams.
                                 rams.
(iv) Kill line inlet..........  Kill line inlet..  Kill line inlet.
(v) Hydraulically-operated two- Hydraulically-     Hydraulically-
 way slip rams.                  operated two-way   operated two-way
                                 slip rams.         slip rams.
                                                   Hydraulically-
                                                    operated pipe rams.
(vi) Hydraulically-operated     Hydraulically-     A flow tee or cross.
 pipe rams.                      operated pipe     Hydraulically-
                                 rams.              operated pipe rams.
                                Hydraulically-     Hydraulically-
                                 operated blind-    operated blind-shear
                                 shear rams.        rams on wells with
                                 These rams         surface pressures
                                 should be          >3,500 psi. As an
                                 located as close   option, the pipe
                                 to the tree as     rams can be placed
                                 practical.         below the blind-
                                                    shear rams. The
                                                    blind-shear rams
                                                    should be located as
                                                    close to the tree as
                                                    practical.
------------------------------------------------------------------------
    (2) You may use a set of hydraulically-operated combination rams
for the blind rams and shear rams.
    (3) You may use a set of hydraulically-operated combination rams
for the hydraulic two-way slip rams and the hydraulically-operated pipe
rams.
    (4) You must attach a dual check valve assembly to the coiled
tubing connector at the downhole end of the coiled tubing string for
all coiled tubing operations. If you plan to conduct operations without
downhole check valves, you must describe alternate procedures and
equipment in Form BSEE-0124, Application for Permit to Modify and have
it approved by the District Manager.
    (5) You must have a kill line and a separate choke line. You must
equip each line with two full-opening valves and at least one of the
valves must be remotely controlled. You may use a manual valve instead
of the remotely controlled valve on the kill line if you install a
check valve between the two full-opening manual valves and the pump or
manifold. The valves must have a working pressure rating equal to or
greater than the working pressure rating of the connection to which
they are attached, and you must install them between the well control
stack and the choke or kill line. For operations with expected surface
pressures greater than 3,500 psi, the kill line must be connected to a
pump or manifold. You must not use the kill line inlet on the BOP stack
for taking fluid returns from the wellbore.
    (6) You must have a hydraulic-actuating system that provides
sufficient accumulator capacity to close-open-close each component in
the BOP stack. This cycle must be completed with at least 200 psi above
the pre-charge pressure, without assistance from a charging system.
    (7) All connections used in the surface BOP system from the tree to
the uppermost required ram must be flanged, including the connections
between the well control stack and the first full-opening valve on the
choke line and the kill line.
    (b) BSEE considers all coiled tubing operations to be non-routine.
0
40. Add Sec.  250.751 to read as follows:
Sec.  250.751   Coiled tubing testing requirements.
    You must test the coiled tubing unit in accordance with Sec.
250.737(a), (b), (c), (d)(9), and (d)(10). You must successfully
pressure test the dual check valves to the rated working pressure of
the connector, the rated working pressure of the dual check valve,
expected surface pressure, or the collapse pressure of the coiled
tubing, whichever is less. The test interval for coiled tubing
operations must include a 10 minute high-pressure test for the coiled
tubing string.
0
41. Add an undesignated center heading and Sec.  250.760 to read as
follows:
Snubbing Operations
Sec.  250.760   What are the snubbing requirements?
    (a) For snubbing operations, you must follow the applicable
requirements of this subpart and have the following minimum BOP-system
components:
    (1) One set of pipe rams hydraulically operated,
    (2) Two sets of stripper-type pipe rams hydraulically operated with
spacer spool,
    (3) An inside BOP or a spring-loaded, back-pressure safety valve in
the open position located on the rig floor, and
    (4) An essentially full-opening, work-string safety valve in the
open position must be maintained on the rig floor at all times and a
wrench to fit the work-string safety valve must be readily available.
    (5) Proper connections must be readily available for inserting
valves in the work string.
    (b) Test the snubbing unit in accordance with Sec.  250.737(a),
(b), and (c).
Subpart Q--Decommissioning Activities
0
42. Amend Sec.  250.1703 by revising paragraph (b) to read as follows:
Sec.  250.1703   What are the general requirements for decommissioning?
* * * * *
    (b) Permanently plug all wells. Packers and bridge plugs used as
qualified mechanical barriers must comply with ANSI/API Spec. 11D1 (as
incorporated by reference in Sec.  250.198). You must have two
independent barriers, one being an ANSI/API Spec. 11D1 qualified
mechanical barrier, in the exposed center wellbore prior to removing
the tree and/or well control equipment;
* * * * *
0
43. Amend Sec.  250.1704 by adding paragraph (g)(4) and revising
paragraph (h)(2) to read as follows:
Sec.  250.1704   What decommissioning applications and reports must I
submit and when must I submit them?
* * * * *
[[Page 21985]]
------------------------------------------------------------------------
  Decommissioning applications
           and reports              When to submit       Instructions
------------------------------------------------------------------------

                              * * * * * * *
(g) * * *.......................  (4) Within 30 days  Include
                                   after you           information
                                   complete site       required under
                                   clearance           Sec.
                                   verification        250.1743(a).
                                   activities,
(h) * * *.......................  (2) Within 30 days  Include
                                   after completion    information
                                   of                  required under
                                   decommissioning     Sec.  Sec.
                                   activity,           250.1712 and
                                                       250.1721.

                              * * * * * * *
------------------------------------------------------------------------
Sec.  250.1706  [Reserved]
0
44. Remove and reserve Sec.  250.1706:
Sec.  250.1713  [Reserved]
0
45. Remove and reserve Sec.  250.1713:
0
46. Amend Sec.  250.1716 by revising paragraph (b)(3) to read as
follows:
Sec.  250.1716   To what depth must I remove wellheads and casings?
* * * * *
    (b) * * *
    (3) The water depth is greater than 1,000 feet.
0
47. Amend Sec.  250.1722 by revising paragraph (d) introductory text to
read as follows:
Sec.  250.1722   If I install a subsea protective device, what
requirements must I meet?
* * * * *
    (d) Within 30 days after you complete the trawling test described
in paragraph (c) of this section, submit a report to the appropriate
District Manager using form BSEE-0125, End of Operations Report (EOR)
that includes the following:
* * * * *
[FR Doc. 2019-09362 Filed 5-14-19; 8:45 am]
 BILLING CODE 4310-VH-P