Oil and Gas and Sulfur Operations in the Outer Continental Shelf-Blowout Preventer Systems and Well Control, 25887-26038 [2016-08921]

Agencies

• DEPARTMENT OF THE INTERIOR
• Bureau of Safety and Environmental Enforcement

[Federal Register Volume 81, Number 83 (Friday, April 29, 2016)]
[Rules and Regulations]
[Pages 25887-26038]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2016-08921]



[[Page 25887]]

Vol. 81

Friday,

No. 83

April 29, 2016

Part III





 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; Final Rule

Federal Register / Vol. 81 , No. 83 / Friday, April 29, 2016 / Rules 
and Regulations

[[Page 25888]]


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DEPARTMENT OF THE INTERIOR

Bureau of Safety and Environmental Enforcement

30 CFR Part 250

[Docket ID: BSEE-2015-0002; 15XE1700DX EEEE500000 EX1SF0000.DAQ000]
RIN 1014-AA11


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

AGENCY: Bureau of Safety and Environmental Enforcement, Interior.

ACTION: Final rule.

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SUMMARY: Bureau of Safety and Environmental Enforcement (BSEE) is 
finalizing new regulations to consolidate into one part the equipment 
and operational requirements that are found in various subparts of 
BSEE's regulations pertaining to offshore oil and gas drilling, 
completions, workovers, and decommissioning. This final rule focuses on 
blowout preventer (BOP) and well-control requirements, including 
incorporation of industry standards and revision of existing 
regulations, and adopts reforms in the areas of well design, well 
control, casing, cementing, real-time well monitoring, and subsea 
containment. The final rule also addresses and implements multiple 
recommendations resulting from various investigations of the Deepwater 
Horizon incident. This final rule will also incorporate guidance from 
several Notices to Lessees and Operators (NTLs) and revise provisions 
related to drilling, workover, completion, and decommissioning 
operations to enhance safety and environmental protection.

DATES: This final rule becomes effective on July 28, 2016. Compliance 
with certain provisions of the final rule, however, will be deferred 
until the times specified in those provisions and as described in Part 
III of the preamble.
    The incorporation by reference of certain publications listed in 
the rule is approved by the Director of the Federal Register as of July 
28, 2016.

FOR FURTHER INFORMATION CONTACT: Kirk Malstrom, Regulations and 
Standards Branch, (202) 258-1518, or by email: regs@bsee.gov.

SUPPLEMENTARY INFORMATION: 

List of Acronyms and References

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
BAST Best Available and Safest Technologies
BAVO BSEE-Approved Verification Organization
BOP Blowout Preventer
BOEM Bureau of Ocean Energy Management
BSEE Bureau of Safety and Environmental Enforcement
BSR Blind Shear Ram
CFR Code of Federal Regulations
CVA Certified Verification Agent
DHS Department of Homeland Security
DOCD Development Operations Coordination Document
DOI Department of the Interior
DPP Development and Production Plan
DWOPs Deepwater Operations Plans
ECD Equivalent Circulating Density
EDS Emergency Disconnect Sequence
E.O. Executive Order
EOR End of Operations Report
EP Exploration Plan
F Fahrenheit
FOIA Freedom of Information Act
FPSs Floating Production Systems
FPSO Floating Production, Storage, and Offloading Unit
FSHR Free Standing Hybrid Risers
GOM Gulf of Mexico
GOMR Gulf of Mexico region
GPS Global Positioning Systems
HPHT High Pressure High Temperature
IC Information Collection
IEC International Electrotechnical Commission
ISO International Organization for Standardization
JIT Joint Investigation Team
LMRP Lower Marine Riser Package
LWC Loss of Well Control
MASP Maximum Anticipated Surface Pressure
MAWHP Maximum Anticipated Wellhead Pressure
MIA Mechanical Integrity Assessment
MMS Minerals Management Service
MODUs Mobile Offshore Drilling Units
NAE National Academy of Engineering
NAICS North American Industry Classification System
NARA National Archives and Records Administration
NAS National Academy of Sciences
National Commission National Commission on the BP Deepwater Horizon 
Oil Spill and Offshore Drilling
NIST National Institute of Standards and Technology
NTLs Notices to Lessees and Operators
NTTAA National Technology Transfer and Advancement Act
OCS Outer Continental Shelf
OCSLA Outer Continental Shelf Lands Act
OEM Original Equipment Manufacturer
OFR Office of Federal Register
OIRA Office of Information and Regulatory Affairs
OMB Office of Management and Budget
PEs Professional Engineers
ppg Pounds per gallon
psi Pounds per square inch
QA/QC Quality Assurance/Quality Control
RCD Regional Containment Demonstration
RFA Regulatory Flexibility Act
RIA Regulatory Impact Analysis
RIN Regulation Identifier Number
ROT Remotely Operated Tools
ROV Remotely-Operated Vehicle
RP Recommended Practice
RTM Real-Time Monitoring
SBA Small Business Administration
SBREFA Small Business Regulatory Enforcement Fairness Act of 1996
SCCE Source Control and Containment Equipment
Secretary Secretary of the Interior
SEM Subsea Electronic Module
SEMS Safety and Environmental Management Systems
SIMOPS Simultaneous Operations
Spec. Specification
TAR Technical Assessment and Research
TBT Agreement Technical Barriers to Trade Agreement
TIA Takings Implication Analysis
TLPs Tension Leg Platforms
TVD True Vertical Depth
USCG United States Coast Guard
VBR Variable Bore Ram
VSL Value of a Statistical Life
WAR Well Activity Report
WTO World Trade Organization

Executive Summary

    Following the devastating impacts of the April 20, 2010, Deepwater 
Horizon incident on the Gulf of Mexico (GOM) and the surrounding states 
and local communities, multiple investigations were conducted to 
determine the causes of the incident and to make recommendations to 
reduce the likelihood of a similar incident in the future. The 
investigative groups included:

--Department of the Interior (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; and
--National Academy of Engineering.

    Each investigation outlined several recommendations to improve 
offshore safety. BSEE evaluated the recommendations and acted on a 
number of them quickly to improve offshore operations, while BSEE's 
decision making with respect to other recommendations followed 
additional input from industry and other stakeholders.
    In April 2015, BSEE proposed regulations to, among other things, 
incorporate industry standards and NTL guidance; consolidate into one 
part the existing equipment and operational requirements that are found 
in various parts of BSEE's regulations; to revise and improve existing 
requirements for well design and control, casing and cementing; and to 
add new requirements for real-time monitoring

[[Page 25889]]

(RTM) and subsea containment. The proposed regulations also addressed 
many of the recommendations made by the previously listed investigative 
bodies, which found a need to incorporate well-control best practices 
to advance safety and protection of the environment. BSEE received over 
176 public comments on the proposed rule, and considered those comments 
in developing these final regulations.
    The requirements in this final rule, including the revisions made 
to the proposed regulations, reflect BSEE's consideration of the 
comments and BSEE's commitment to address the recommendations made in 
the Deepwater Horizon reports. This final rulemaking:
    (1) Incorporates all or designated portions of the following 
industry standards:

--American Petroleum Institute (API) Standard 53, Blowout Prevention 
Equipment Systems for Drilling Wells, Fourth Edition, November 2012;
--API Recommended Practice (RP) 2RD--Design of Risers for Floating 
Production Systems and Tension-Leg Platforms, First Edition, June 1998; 
Reaffirmed May 2006, Errata June 2009;
--API Specification (Spec.) Q1--Specification for Quality Management 
System Requirements for Manufacturing Organizations for the Petroleum 
and Natural Gas Industry, Eighth Edition, December 2007, Effective 
Date: June 15, 2008;
--American National Standards Institute (ANSI)/API Specification 
(Spec.) 11D1, Packers and Bridge Plugs Second Edition, Effective Date: 
January 1, 2010;
--API RP 17H, Remotely Operated Tools and Interfaces on Subsea 
Production Systems, First Edition, July 2004, Reaffirmed: January 2009;
--ANSI/API Spec. 6A, Specification for Wellhead and Christmas Tree 
Equipment, Nineteenth Edition, July 2004; Effective Date: February 1, 
2005;
--ANSI/API Spec. 16A, Specification for Drill-through Equipment, Third 
Edition, June 2004;
--API Spec. 16C, Specification for Choke and Kill Systems First 
Edition, January 1993;
--API Spec. 16D, Specification for Control Systems for Drilling Well 
Control Equipment and Control Systems for Diverter Equipment, Second 
Edition, July 2004; and
--ANSI/API Spec. 17D, Design and Operation of Subsea Production 
Systems--Subsea Wellhead and Tree Equipment, Second Edition; May 2011.

    (2) Revises the requirements for Deepwater Operations Plans 
(DWOPs), which are required to be submitted to BSEE under specific 
circumstances, to add requirements on free standing hybrid risers 
(FSHR) for use with floating production, storage, and offloading units 
(FPSO).
    (3) Revises 30 CFR part 250, subpart D, Oil and Gas Drilling 
Operations, to include requirements for:

--Safe drilling margins;
--Wellhead descriptions;
--Casing or liner centralization during cementing; and
--Source control and containment.

    (4) Revises subparts E, Oil and Gas Well-Completion Operations, and 
F, Oil and Gas Well-Workover Operations, to include requirements for:

--Packer and bridge plug design; and
--Production packer setting depth.

    (5) Revises Subpart Q, Decommissioning Activities, to include 
requirements for:

--Packer and bridge plug design;
--Casing bridge plugs; and
--Decommissioning applications and reports.

    (6) Adds new subpart G, Well Operations and Equipment, and moves 
existing requirements that were duplicated in subparts D, E, F, and Q 
into new subpart G including:

--Rig and equipment movement reports;
--RTM; and
--Revised BOP requirements; including:
--Design and manufacture/quality assurance;
--Accumulator system capabilities and calculations;
--BOP and remotely operated vehicle (ROV) capabilities;
--BOP functions (e.g., shearing);
--Improved and consistent testing frequencies;
--Maintenance;
--Inspections;
--Failure reporting;
--Third-party verification; and
--Additional submittals to BSEE, including up-to-date schematics.

    (7) Incorporates the guidance from several NTLs into subpart G for:

--Global Positioning Systems (GPS) for Mobile Offshore Drilling Units 
(MODUs);
--Ocean Current Monitoring;
--Using Alternate Compliance in Safety Systems for Subsea Production 
Operations;
--Standard Reporting Period for the Well Activity Report (WAR); and
--Information to include in the WARs and End of Operations Reports 
(EOR).

    Based on BSEE's economic analysis of available data, this final 
rule will be cost-beneficial. The estimated overall cost of the rule 
(outside those costs that are part of the economic baseline) over 10 
years will be exceeded by the time-savings benefits to the industry 
resulting from the revisions to the former requirements for BOP 
pressure testing frequency for workovers and decommissionings. In 
addition, the final rule will also produce benefits to society, both 
quantifiable and unquantifiable, by reducing the probability of well 
control incidents involving oil spills.

Table of Contents

I. Background
    A. BSEE
    B. BSEE Statutory and Regulatory Authority and Responsibilities
    C. Purpose and Summary of the Rulemaking
    D. Availability of Incorporated Documents for Public Viewing
    E. Summary of Documents Incorporated by Reference
II. Organization of Subpart G
III. Discussion of Compliance Dates for the Final Rule
IV. Issues Not Considered in this Rulemaking
V. 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
    2. Accumulator systems
    3. BOP 5-year major inspection
    4. Real-time monitoring (RTM)
    5. Potential increased severing capability
    6. BOP pressure testing interval
    C. Other Differences Between the Proposed and Final Rules
VI. Discussion of Public Comments on the Proposed Rule
    A. Requests for Extension of the Proposed Rule Comment Period
    B. Summary of General Comments on the Proposed Rule
    1. Comments supporting the proposed rule
    2. Legal comments
    3. Arctic-related comments
    4. General comments
    5. Contractor/Operator/Manufacturer responsibilities
    6. Economic analysis comments
    7. Clarification of maximum anticipated surface pressure (MASP)
    C. Section-By-Section Summary and Responses to Significant 
Comments on the Proposed Rule
VII. Derivation Tables
VIII. Procedural Matters
    Regulatory Planning and Review (Executive Orders (E.O.) 12866 
and 13563))
    Regulatory Flexibility Act
    Small Business Regulatory Enforcement Fairness Act
    Unfunded Mandates Reform Act of 1995
    Takings Implication Assessment (E.O. 12630)
    Federalism (E.O. 13132)
    Civil Justice Reform (E.O. 12988)
    Consultation With Indian Tribes (E.O. 13175)

[[Page 25890]]

    Paperwork Reduction Act (PRA) of 1995
    National Environmental Policy Act of 1969 (NEPA)
    Data Quality Act
    Effects on the Nation's Energy Supply (E.O. 13211)

I. Background

A. BSEE

    BSEE was established on October 1, 2011, as part of a major 
restructuring of DOI's offshore oil and gas regulatory programs to 
improve the management and oversight of, and accountability for, 
activities on the Outer Continental Shelf (OCS). The Secretary of the 
Interior (Secretary) announced the division of responsibilities of the 
former Minerals Management Service (MMS) among two new bureaus and one 
office within DOI in Secretarial Order No. 3299, issued on May 19, 
2010. BSEE, one of the two new bureaus, assumed responsibility for 
``safety and environmental enforcement functions including, but not 
limited to, the authority to permit activities, inspect, investigate, 
summon witnesses and [require production of] evidence[;] levy 
penalties; cancel or suspend activities; and oversee safety, response 
and removal preparedness.'' (See 76 FR 64431, October 18, 2011).

B. BSEE Statutory and Regulatory Authority and Responsibilities

    BSEE derives its authority primarily from the Outer Continental 
Shelf Lands Act (OCSLA), 43 U.S.C. 1331-1356a. Congress enacted OCSLA 
in 1953, authorizing the Secretary of Interior to lease the OCS for 
mineral development, and to regulate oil and gas exploration, 
development, and production operations on the OCS. The Secretary has 
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 offshore exploration and 
development of oil and gas on the OCS and to ensure that those 
operations protect the environment and implement advancements in 
technology. BSEE also conducts onsite inspections to assure compliance 
with regulations, lease terms, and approved plans. 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/Regulations-and-Guidance/index.
    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 \1\ perform throughout the OCS. These well 
operations are the primary focus of this rulemaking.
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    \1\ BSEE's regulations at 30 CFR part 20 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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C. Purpose and Summary of the Rulemaking

    A primary purpose of this rulemaking is to prevent future well-
control incidents, including major incidents like the 2010 Deepwater 
Horizon catastrophe. In addition to the loss of 11 lives, that single 
event resulted in the release of 134 million gallons of oil, which 
spread over 43,300 square miles of the GOM and 1,300 miles of shoreline 
in several states. The environmental and other damages caused by the 
Deepwater Horizon incident were immense and have had long-lasting and 
widespread impacts on the Gulf and the affected states. For example, as 
part of a settlement agreement between BP and Federal and state 
governments, BP has agreed to pay over $8 billion for natural resources 
damages caused by the spill and for the restoration of natural 
resources in the Gulf of Mexico region (GOMR).\2\ Those damages include 
severe adverse effects on wildlife, wetlands and other wildlife 
habitat, recreation and tourism, and commercial fishing. The Deepwater 
Horizon Natural Resource Damage Assessment (NRDA) Trustees have 
determined that ``the ecological scope of impacts from the Deepwater 
Horizon incident was unprecedented, with injuries affecting a wide 
array of linked resources across the northern Gulf ecosystem.'' The 
released oil ``was toxic to a wide range of organisms, including fish, 
invertebrates, plankton, birds, turtles, and mammals . . . [and] caused 
a wide array of toxic effects, including death, disease, reduced 
growth, impaired reproduction, and physiological impairments that made 
it more difficult for organisms to survive and reproduce.'' \3\ In 
addition, state and local government economic damage claims arising 
from the Deepwater Horizon incident were significant and have been 
settled for another $5.9 billion.\4\
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    \2\ A summary and details of the recently approved natural 
resources damages settlement between BP and Federal and state 
governments are available at www.doi.gov/deepwaterhorizon and at 
https://www.justice.gov/enrd/deepwater-horizon.
    \3\ Deepwater Horizon NRDA Trustees, Final Programmatic Damage 
Assessment and Restoration Plan and Final Programmatic Environmental 
Impact Statement, at p. 1-14-1-15. On March 22, 2016, the NRDA 
Trustees issued a Record of Decision setting forth the basis for the 
Trustees' decision to select the comprehensive, integrated ecosystem 
restoration alternative (described in Final PDARP/PEIS Sections 5.5 
and 5.10). More details regarding the findings of the Federal and 
state Deepwater Horizon NRDA Trustees as to natural resources 
impacts from the Deepwater Horizon incident may be found at: https://www.gulfspillrestoration.noaa.gov/restoration-planning/gulf-plan/.
    \4\ https://www.justice.gov/enrd/deepwater-horizon.
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    In addition, despite new regulations and improvements in industry 
standards and practices since the Deepwater Horizon incident, which 
have resulted in progress in certain areas of safety and environmental 
protection, loss of well control (LWC) incidents are happening at about 
the same rate five years after that incident as they were before. In 
2013 and 2014, there were 8 and 7 LWC incidents per year, 
respectively--a rate on par with pre-Deepwater Horizon LWCs.\5\ Some of 
these LWC incidents have resulted in blowouts, such as the 2013 Walter 
Oil and Gas incident that resulted in an explosion and fire on the rig. 
All 44 workers were safely evacuated, but the fire lasted over 72 hours 
and the rig was completely destroyed, resulting in a financial loss 
approaching $60 million. This incident occurred in part due to the 
crew's inability to identify critical well control indicators and to 
the failure of critical well control equipment.\6\ Blowouts such as 
these can lead to much larger incidents that pose a significant risk to 
human life and can cause serious environmental damage.
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    \5\ See https://www.bsee.gov/uploadedFiles/BSEE/BSEE_Newsroom/Publications_Library/Annual_Report/BSEE%202014%20Annual%20Report.pdf.
    \6\ See BSEE, DOI, Investigation of Loss of Well Control and 
Fire South Timbalier Area Block 220, Well. No. A-3 OCS-G24980--23 
July 2013 (July 2015), at https://www.bsee.gov/uploadedFiles/BSEE/Enforcement/Accidents_and_Incidents/Panel_Investigation_Reports/ST%20220%20Panel%20Report9_8_2015.pdf.
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    Ensuring the integrity of the wellbore and maintaining control over 
the pressure and fluids during well operations are critical aspects of 
protecting worker safety and the environment. The investigations that 
followed the Deepwater Horizon incident, in particular, documented gaps 
or deficiencies in the OCS regulatory programs and made numerous 
recommendations for improvements. Accordingly, on April 17, 2015, BSEE 
proposed to consolidate its existing well-control rules into one 
subpart of the regulations, and to adopt new and revised regulatory 
requirements that address many of those recommendations, including 
those related to BOP system design, performance, and reliability. (See 
80 FR 21504.)

[[Page 25891]]

    Because BOP equipment and systems are critical components of many 
well operations, BSEE recognized that it was important to collect the 
best ideas on the prevention of well-control incidents and blowouts to 
assist in the development of the proposed rule. This included the 
knowledge, skillset, and experience possessed by the offshore oil and 
gas industry. Accordingly, BSEE participated in meetings, training, and 
workshops with industry, standards setting organizations, and other 
stakeholders in developing the proposed rule. (See 80 FR 21508-21509.)
    The proposed rule discussed in detail topics such as:
     Implementing many of the recommendations related to well-
control equipment.
     Increasing the performance and reliability of well-control 
equipment, especially BOPs.
     Improving regulatory oversight over the design, 
fabrication, maintenance, inspection, and repair of critical equipment.
     Gaining information on leading and lagging indicators of 
BOP component failures, identifying trends in those failures, and using 
that information to help prevent incidents.
     Ensuring that the industry uses recognized engineering 
practices, as well as innovative technology and techniques to increase 
overall safety.
    To help ensure the development of effective regulations, the 
proposed rule used a hybrid regulatory approach incorporating 
prescriptive requirements, where necessary, as well as many 
performance-based requirements. BSEE recognizes the advantages and 
disadvantages of both approaches and understands that each approach 
could be effective and appropriate for specific circumstances.
    A full discussion of these topics, along with other background and 
regulatory history, is contained in the notice of proposed rulemaking 
(see 80 FR 21504), which may be found on BSEE's website at https://www.bsee.gov/Regulations-and-Guidance/Regulations-In-Development/, and 
in the public docket for this rulemaking at: https://www.regulations.gov 
(in the Search box, enter BSEE-2015-0002, then click ``search'').

D. Availability of Incorporated Documents for Public Viewing

    BSEE frequently uses standards (e.g., codes, specifications, RPs) 
developed through a consensus process, facilitated by standards 
development organizations and with input from the oil and gas industry, 
as a means of establishing requirements for activities on the OCS. BSEE 
may incorporate these standards into its regulations without 
republishing the standards in their entirety in the Code of Federal 
Regulations (CFR), a practice known as incorporation by reference. The 
legal effect of incorporation by reference is that the incorporated 
standards become regulatory requirements. This incorporated material, 
like any other properly issued regulation, has the force and effect of 
law, and BSEE holds operators, lessees and other regulated parties 
accountable for complying with the documents incorporated by reference 
in our regulations. We currently incorporate by reference over 100 
consensus standards in BSEE's regulations governing offshore oil and 
gas operations (see 30 CFR 250.198).
    Federal regulations, at 1 CFR part 51, govern how BSEE and other 
Federal agencies incorporate various documents by reference. Agencies 
may only incorporate a document by reference by publishing in the 
Federal Register the document title, edition, date, author, publisher, 
identification number, and other specified information. The Director of 
the Federal Register must approve each publication incorporated by 
reference in a final rule. Incorporation by reference of a document or 
publication is limited to the specific edition cited by the agency in 
the final rule and approved by the Director of the Federal Register.
    BSEE incorporates by reference in its regulations many oil and gas 
industry standards in order to require compliance with those standards 
in offshore operations. When a copyrighted publication is incorporated 
by reference into BSEE regulations, BSEE is obligated to observe and 
protect that copyright. BSEE provides members of the public with 
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 review its key industry 
standards, including a broad range of technical standards. These 
standards represent almost one-third of all API standards and include 
all that are safety-related or are incorporated into Federal 
regulations. Several of those standards are incorporated by reference 
in this final rule. In addition to the free online availability of 
these standards for viewing on API's website, hardcopies and printable 
versions are available for purchase from API. The API website address 
is: https://www.api.org/publications-standards-and-statistics/publications/government-cited-safety-documents.\7\
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    \7\ To review these standards online, go to the API publications 
website at: https://publications.api.org. You must then log-in or 
create a new account, accept API's ``Terms and Conditions,'' click 
on the ``Browse Documents'' button, and then select the applicable 
category (e.g., ``Exploration and Production'') for the standard(s) 
you wish to review.
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    For the convenience of members of the viewing public who may not 
wish to purchase or view these incorporated documents online, they may 
be inspected at BSEE's offices, 45600 Woodland Road, Sterling, Virginia 
20166; phone: 703-787-1665; or at the National Archives and Records 
Administration (NARA). For information on the availability of this 
material at NARA, call 202-741-6030, or go to: https://www.archives.gov/federal-register/cfr/ibr-locations.html.

E. Summary of Documents Incorporated by Reference

    This rulemaking is substantive in terms of the content that is 
explicitly stated in the rule text itself, and it also incorporates by 
reference certain technical standards and specifications concerning 
BOPs and well control. A brief summary of each standard or 
specification follows.
API Standard 53--Blowout Prevention Equipment Systems for Drilling 
Wells
    This standard provides 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 
various components that are covered by this document. Equipment 
arrangements are also addressed. The components covered include: BOPs 
including installations for surface and subsea BOPs; choke and kill 
lines; choke manifolds; control systems; and auxiliary equipment.
    This standard also provides new industry best practices related to 
the use of dual shear rams, maintenance and testing requirements, and 
failure reporting.
    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 are not addressed. 
Procedures and techniques for well control and extreme temperature 
operations are also not included in this standard.

[[Page 25892]]

API RP 2RD--Design of Risers for Floating Production Systems and 
Tension-Leg Platforms
    This standard addresses structural analysis procedures, design 
guidelines, component selection criteria, and typical designs for all 
new riser systems used on Floating Production Systems (FPSs) and 
Tension-Leg Platforms (TLPs). The presence of riser systems within an 
FPS has a direct and often significant effect on the design of all 
other major equipment subsystems. This RP includes recommendations on: 
(1) Configurations and components; (2) general design considerations 
based on environmental and functional requirements; and (3) materials 
considerations in riser design.
API Spec. Q1--Specification for Quality Management System Requirements 
for Manufacturing Organizations for the Petroleum and Natural Gas 
Industry
    This specification establishes the minimum quality management 
system requirements for organizations that manufacture products or 
provide manufacturing-related processes under a product specification 
for use in the petroleum and natural gas industry. This standard 
requires that equipment be fabricated under a quality management system 
that provides for continual improvement, emphasizing defect prevention 
and the reduction of variation and waste in the supply chain and from 
service providers. The goal of this specification is to increase 
equipment reliability through better manufacturing controls.
API Spec. 6A--Specification for Wellhead and Christmas Tree Equipment
    This specification defines minimal requirements for the design of 
valves, wellheads and Christmas tree equipment that is used during 
drilling and production operations. This specification includes 
requirements related to dimensional and functional interchangeability, 
design, materials, testing, inspection, welding, marking, handling, 
storing, shipment, purchasing, repair and remanufacture.
ANSI/API Spec. 11D1--Packers and Bridge Plugs
    This specification provides minimum requirements and guidelines for 
packers and bridge plugs used downhole in oil and gas operations. The 
performance of this equipment is often critical to maintaining control 
of a well during drilling or production operations. This specification 
provides requirements for the functional specification and technical 
specification, including design, design verification and validation, 
materials, documentation and data control, repair, shipment, and 
storage.
ANSI/API Spec. 16A--Specification for Drill-through Equipment
    This specification defines requirements for performance, design, 
materials, testing and inspection, welding, marking, handling, storing 
and shipping of BOPs and drill-through equipment used for drilling for 
oil and gas. It also defines service conditions in terms of pressure, 
temperature and wellbore fluids for which the equipment will be 
designed. This standard is applicable to, and establishes requirements 
for, the following specific equipment: Ram BOPs; ram blocks, packers 
and top seals; annular BOPs; annular packing units; hydraulic 
connectors; drilling spools; adapters; loose connections; and clamps. 
Conformance to this standard is necessary to ensure that this critical 
safety equipment has been designed and fabricated in a manner that 
ensures reliable performance.
API Spec. 16C--Specification for Choke and Kill Systems
    This specification was formulated to provide for safe and 
functionally interchangeable surface and subsea choke and kill systems 
equipment utilized for drilling oil and gas wells. This equipment is 
used during emergencies to circulate out a ``kick'' and, therefore, the 
design and fabrication of the components is extremely important. This 
document provides the minimum requirements for performance, design, 
materials, welding, testing, inspection, storing and shipping. 
Equipment specific to and covered by this specification includes: 
Actuated valve control lines; articulated choke and kill lines; 
drilling choke actuators; drilling choke control lines, exclusive of 
BOP control lines; subsurface safety valve control lines; drilling 
choke controls; drilling chokes; flexible choke and kill lines; union 
connections; rigid choke and kill lines; and swivel unions.
API Spec. 16D--Specification for Control Systems for Drilling Well 
Control Equipment and Control Systems for Diverter Equipment
    This specification establishes design standards for systems that 
are used to control BOPs and associated valves that control well 
pressure during drilling operations. Although diverters are not 
considered well-control devices, their controls are often incorporated 
as part of the BOP control system. Thus, control systems for diverter 
equipment are included in the specification. Control systems for 
drilling well-control equipment typically employ stored energy in the 
form of pressurized hydraulic fluid (power fluid) to operate (open and 
close) the BOP stack components. For deepwater operations, subsea 
transmission of electric/optical (rather than hydraulic) signals may be 
used to shorten response times. The failure of these controls to 
perform as designed can result in a major well-control event. As a 
result, conformance to this specification is critical to ensuring that 
the BOPs and related equipment will operate in an emergency.
ANSI/API Spec. 17D--Design and Operation of Subsea Production Systems--
Subsea Wellhead and Tree Equipment
    This standard provides specifications for subsea wellheads, mudline 
wellheads, drill-through mudline wellheads, and both vertical and 
horizontal subsea trees. These devices are located on the seafloor, 
and, therefore, ensuring the safe and reliable performance of this 
equipment is extremely important. This document specifies the 
associated tooling necessary to handle, test and install the equipment. 
It also specifies the areas of design, material, welding, quality 
control (including factory acceptance testing), marking, storing and 
shipping for both individual sub-assemblies (used to build complete 
subsea tree assemblies) and complete subsea tree assemblies.
API RP 17H--Remotely Operated Tools and Interfaces on Subsea Production 
Systems
    This RP provides general recommendations and overall guidance for 
the design and operation of remotely operated tools (ROT) comprising 
ROT and 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 the equipment.

II. Organization of Subpart G

    BSEE's former regulations repeated similar BOP requirements in 
multiple locations throughout 30 CFR part 250. In this final rule, BSEE 
is consolidating these requirements into subpart G (which previously 
had been reserved). The final rule will structure subpart G--Well 
Operations and Equipment, under the following undesignated headings:

--GENERAL REQUIREMENTS

[[Page 25893]]

--RIG REQUIREMENTS
--WELL OPERATIONS
--BLOWOUT PREVENTER (BOP) SYSTEM REQUIREMENTS
--RECORDS AND REPORTING

    The sections contained within this new subpart will apply to all 
drilling, completion, workover, and decommissioning activities on the 
OCS, unless explicitly stated otherwise.

III. Discussion of Compliance Dates for the Final Rule

    BSEE understands that operators may need time to comply with 
certain new requirements in this final rule. Based on information 
provided by industry, drilling rigs are now being built, or were built, 
pursuant to the same industry standards BSEE is now incorporating by 
reference (including API Standard 53), and many have already been 
retrofitted to comply with these industry standards. Furthermore, most 
drilling rigs already comply with recognized engineering practices and 
original equipment manufacturer (OEM) requirements related to repair 
and training.
    BSEE has considered the public comments on the proposed compliance 
dates, 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. Accordingly, BSEE is setting an effective date of 90 days 
following publication of the final rule, by which time operators will 
be required to demonstrate compliance with most of the final rule's 
provisions. BSEE has determined, however, that it is appropriate to 
extend the compliance dates for the following new requirements. 
Detailed explanations for these extended compliance dates are provided 
in parts V and VI of this document.

--As required in Sec.  250.734(a)(15), operators must install a gas 
bleed line with two valves for the annular preventer no later than 2 
years from publication of the final rule. BSEE is extending the 
timeframe for this requirement based on the current level of 
availability of the required equipment and the time needed to install 
the equipment. This timeframe was selected to avoid any rig downtime.
--As required by Sec. Sec.  250.733(a)(1) and 250.734(a)(1), operators 
must have the capability to shear and seal tubing with exterior control 
lines no later than 2 years from the publication of the final rule. 
BSEE is aware that some current technology is available to shear tubing 
with exterior control lines; however, the effective date has been 
extended to allow operators to acquire and install (and, if necessary, 
to develop new or alternative) equipment to meet the requirements.
--As required by Sec. Sec.  250.731, 250.732, 250.734, 250.738, and 
250.739, operators must begin using a BSEE-approved verification 
organization (BAVO) for certain submittals, certifications, and 
verifications.\8\ BSEE will develop and make available on its public 
website a list of BAVOs, consisting of qualified third-party 
organizations that BSEE determines are capable of performing the 
functions specified in this final rule, and that will help BSEE ensure 
that BOP systems are designed and maintained during their service life 
to minimize risk. Industry currently uses independent third-parties to 
perform verifications similar to the certifications and verifications 
that a BAVO will be required to perform under this final rule. BSEE is 
extending the compliance date for the use of BAVOs to no later than 1 
year from the date when BSEE publishes the list of BAVOs. BSEE 
anticipates that most of the independent third-parties currently used 
by industry under the former regulations will become BAVOs, 
significantly facilitating compliance with the requirements to use 
BAVOs within the one-year timeframe.
---------------------------------------------------------------------------

    \8\ For example, Sec.  250.731(c)(2) requires certification and 
verifacation that all BOPs are designed and tested to maximun 
anticipated condictions.

    In the interim, however, final Sec.  250.732(a) requires that 
operators use independent third-parties to perform the certifications, 
verifications and reports that BAVOs must perform no later than 1 year 
after BSEE publishes a BAVO list. This transitional measure is 
necessary to ensure that there is no diminution of the safety and 
environmental protection currently afforded by the use of independent 
third-parties under the existing regulations or of the safety and 
environmental improvements anticipated under the new BAVO requirements, 
during the time required for BSEE to identify and for operators to use 
---------------------------------------------------------------------------
the BAVOs.

--As required in Sec.  250.724, operators must comply with the RTM 
requirements no later than 3 years from the publication of the final 
rule.
--As required in Sec.  250.734(a)(3), operators are required to have 
dedicated subsea accumulator capacity for autoshear and deadman 
functions on subsea BOPs within 5 years from the publication of the 
final rule. As explained in more detail in part VI.C, changing the 
compliance date for these new accumulator requirements--from the 
proposed 3 months to the final 5 years from the date of publication--
will allow sufficient lead time for industry to acquire and install 
additional accumulator equipment as necessary and will correspond with 
the timeframe for compliance with the final dual shear ram 
requirements, which is when the additional accumulator capacity will 
most likely be needed.
--As required in Sec.  250.734(a)(1), operators must install dual shear 
rams on subsea BOPs no later than 5 years from the publication of the 
final rule.
--As required in Sec.  250.733(b)(1), surface BOPs installed on 
floating facilities 3 years after publication of the final rule must 
comply with the BOP requirements of Sec.  250.734(a)(1).
--As required in Sec.  250.734(a)(16), operators must install shear 
rams that center drill pipe during shearing operations no later than 7 
years from the publication of the final rule.
--As required in Sec.  250.735(g), operators must install remotely-
controlled locks on surface BOP sealing rams no later than 3 years from 
publication of the final rule.
--As required in Sec.  250.733(b)(2), for any risers installed 90 days 
after the date of the publication of the final rule or later, operators 
must use dual bore risers for surface BOPs on floating production 
facilities. The final rule does not require that operators change the 
riser configuration for risers that were installed on floating 
facilities before 90 days after the publication date of the final rule.
--As required in Sec. Sec.  250.732(b)(1)(i) and 250.734(a)(1)(ii), the 
BOP must be able to shear electric-, wire-, and slick-line no later 
than 2 years after publication of the final rule.

IV. Issues Not Considered in This Rulemaking

    BSEE is continuing to review and evaluate additional operational 
and equipment issues that are not included in this final rulemaking, 
such as:

--Well-control planning, procedures, training, and certification;
--Major rig equipment;
--Certification requirements for personnel servicing critical 
equipment;
--Choke and kill systems;
--Mud gas separators;
--Wellbore fluid safety practices, testing, and monitoring;

[[Page 25894]]

--Diverter systems with subsea BOPs; and
--Additional severing requirements.

V. Discussion of Final Rule Requirements

    Part V.A, which follows, summarizes and highlights some important 
requirements of the final rule that were described in more detail in 
the proposed rule. Some of these provisions received no comments during 
the public comment period, while other provisions were supported or 
criticized by certain commenters. Part V.B addresses significant 
relevant comments on certain proposed provisions and summarizes changes 
to those provisions that BSEE has made in the final rule based on 
consideration of those comments. Part V.C summarizes other changes to 
the proposed rule that BSEE has made in the final rule to avoid 
ambiguity or confusion, eliminate redundancies, correct minor drafting 
errors, or otherwise clarify the meaning of the new requirements.

A. Summary of Key Regulatory Provisions

    After review of all the relevant public comments received on the 
proposed rule, BSEE determined that the following proposed revisions 
will be included in this final rule. Most of the proposed provisions 
are included without change, while several of the proposed provisions 
have been revised in the final rule in response to comments, as 
explained in parts V.B and VI of this document.
Shearing Requirements--
     Requires BOP shearing performance testing and results 
reporting to a BAVO. This will ensure that shearing capability for 
existing equipment complies with BSEE requirements.
     Requires compliance with the latest industry standards 
contained in API Standard 53.
     Requires that operators use two shear rams in subsea BOP 
stacks.
     Requires the use of BOP technology that provides for 
better shearing performance through the centering of the drill pipe in 
the shear rams.
Equipment Reliability and Performance--
     Requires compliance with industry standards, such as 
relevant provisions of API Standard 53, ANSI/API Spec. 6A, ANSI/API 
Spec. 16A, API Spec. 16C, API Spec. 16D, ANSI/API Spec. 17D, and API 
Spec. Q1. BOP operability will be improved by establishing minimum 
design, manufacture, and performance baselines that are essential to 
ensure the reliability and performance of this equipment.
     Requires inspection, maintenance, and repair of BOP-
related equipment by appropriately trained personnel; this will also 
increase the reliability of BOP-related equipment.
Equipment Failure Reporting/Near-Miss Reporting--
     Requires that operators share information with Original 
Equipment Manufacturers (OEMs) related to the performance of their BOP 
system equipment. This sharing of information makes it possible for the 
OEMs to notify all users of any safety issues that arise with BOP 
system equipment.
     Requires that operators report any significant problems 
with BOP or well-control equipment to BSEE, so BSEE can determine 
whether information should be provided, in a timely manner, to OCS 
operators and, if appropriate, to international offshore regulators and 
operators.
Safe Drilling Practices--
     Requires maintaining safe drilling margins and other 
requirements related to liners and other downhole equipment to help 
reduce the likelihood of a major well-control event and ensure the 
overall integrity of the well design.
     Requires monitoring of deepwater and High Pressure High 
Temperature (HPHT) drilling operations from the shore and in real-time. 
This will allow operators to anticipate and identify issues in a timely 
manner and to utilize onshore resources to assist in addressing 
critical issues.
     Requires daily reports to BSEE concerning any leaks 
associated with BOP control systems. This will ensure that the bureau 
is made aware of any leaks so it can determine if further action is 
appropriate.
     Requires compliance with API RP 17H to standardize ROV hot 
stab activities. This will allow certain functions of the BOP to be 
activated remotely.
BOP Testing--
     Requires same pressure testing frequency (at least once 
every 14 days) for workover and decommissioning operations as for 
drilling and completion operations. Pressure test results will aid in 
predicting future performance of a BOP, and harmonizing testing 
frequencies for all well operations will also help streamline the BOP 
function-testing criteria and reduce the unnecessary repetition every 7 
days of testing in workover and decommissioning operations that could 
pose operational safety issues.
     Requires additional measures (e.g., RTM and increased 
maintenance) to help ensure the functionality and operability of the 
BOP system that will help reduce the safety and environmental risks.

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 in the final rule. We 
are highlighting several of these changes here because they are 
significant, and because numerous comments addressed these topics. A 
discussion of the relevant and significant comments and BSEE's 
responses are found in part VI of this document. The significant 
revisions made in response to comments include:
1. Safe Drilling Margin--Sec.  250.414(c)
    In response to one of the Deepwater Horizon investigation 
recommendations--i.e., to better define safe drilling margins--BSEE 
proposed to revise the safe drilling margin portion of the drilling 
prognosis (i.e., well drilling procedures) required in an Application 
for Permit to Drill (APD). Among other things, BSEE proposed that the 
``static downhole mud weight must be a minimum of 0.5 pound per gallon 
(ppg) below the lesser of the casing shoe pressure integrity test or 
the lowest estimated fracture gradient'' (``the 0.5 ppg drilling 
margin''). This proposed requirement was typically part of BSEE's 
approval parameters during the permitting process. However, many 
commenters expressed concerns that strict enforcement of a 0.5 ppg 
drilling margin in all circumstances could cause adverse economic 
consequences because it could effectively require setting additional 
casing strings and smaller hole sizes and thus, in some cases, could 
make it impossible to reach target depths. The commenters suggested 
various alternatives to the 0.5 ppg requirement, including allowing 
operators to use a risk-based approach to setting safe drilling margins 
on a case-by-case basis.
    Typically, 0.5 ppg is an appropriate safe drilling margin for 
normal drilling scenarios and has been approved by BSEE (and thus made 
a requirement) in numerous APDs. However, BSEE understands that there 
are some well-specific circumstances where a lower drilling margin may 
be acceptable to drill a well safely, and BSEE has approved appropriate 
alternative downhole mud weights as part of a safe drilling margin in 
many APDs. Accordingly, in this final rule, BSEE is keeping the 0.5 ppg 
drilling margin as

[[Page 25895]]

proposed to be the default requirement, but is adding a new paragraph 
(c)(2) to Sec.  250.414 that expressly allows the use of an alternative 
to the 0.5 ppg drilling margin if the operator submits adequate 
justification and documentation, including supplemental data (e.g., 
offset well data, analog data, seismic data, risk modeling), in the 
APD. This addition is consistent with current BSEE GOMR practice to 
allow alternative drilling margins when justified and documented. This 
change will also provide operators some assurance that an alternative 
drilling margin, other than the 0.5 ppg margin, may be used when 
appropriate, while helping BSEE ensure the use of drilling mud with 
properties (e.g., density, viscosity, additives) best suited for a 
specific well interval and based on well-specific drilling and 
geological parameters.\9\ This addition to the safe drilling margin 
section will provide increased planning flexibility when drilling into 
areas that could require lower safe drilling margins, such as depleted 
sands or below salt (both common occurrences in the GOMR), and help 
avoid the potential negative consequences of requiring a 0.5 ppg margin 
in all cases.
---------------------------------------------------------------------------

    \9\ Alternatives to compliance with the 0.5 ppg safe drilling 
margin requirement could also be requested under existing Sec.  
250.141, and approved by BSEE if the criteria of that section are 
satisfied; but such separate requests would not be necessary if an 
operator requests an alternative in its APD under new Sec.  
250.414(c)(2).
---------------------------------------------------------------------------

    BSEE is also making other minor changes to the proposed Sec.  
250.414(c). Specifically, as suggested by several commenters, we are 
replacing the term ``static downhole mud weight'' with ``equivalent 
downhole mud weight,'' and removing the references to Equivalent 
Circulating Density (ECD). Several commenters suggested replacing 
static downhole mud weight with a more appropriate term to better 
define and assess the mud weight because of the difficulty of achieving 
and verifying static downhole mud weight during operations. BSEE agrees 
with this observation. To verify a static downhole mud weight, the well 
would need to be placed in a static situation. This would be done by 
turning off the pumps and letting the well sit until it is static; 
however, that process can result in complications, such as cuttings and 
debris settling out in the bottom of the well and thermal gradients 
affecting mud properties. Some of these complications may create 
additional issues, such as stuck pipe or loss of wellbore integrity. 
The change from ``static'' to ``equivalent'' allows the downhole mud 
weight to be based on the mud properties that can be tested at the 
surface and then calculated to downhole conditions. Thus, equivalent 
downhole mud weight can be verified on the rig as operations are being 
conducted.
    BSEE also removed the references to ECD from this section based on 
comments. For the reasons discussed elsewhere in this preamble (with 
regard to Sec.  250.413), BSEE determined that operators do not need to 
submit the estimated ECD in the APD permitting process; however, BSEE 
expects operators to continue their normal practice of considering ECD 
while drilling.
2. Accumulator Systems
    In the proposed rule, BSEE proposed a number of significant changes 
to existing BOP requirements as well as new requirements for BOPs and 
associated systems, including new requirements for subsea and surface 
BOP accumulator systems. (See proposed Sec. Sec.  250.734 and 250.735.) 
The purpose of the accumulator system and these new 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. Among other 
things, we proposed increasing accumulator capacity to operate all BOP 
functions; i.e., requiring all surface accumulator systems, whether 
associated with surface or subsea BOPs, to meet the requirements for 
accumulators servicing surface BOPS under the prior regulations 
(including the requirement that the accumulator system provide 1.5 
times the volume of fluid capacity necessary to hold closed all BOP 
components). We also proposed requiring surface accumulator systems to 
operate under MASP conditions, with the blind shear ram being last in 
the BOP sequence, and still have enough accumulated pressure to allow 
the BOP to shear pipe and seal the well. In addition, we proposed 
defining critical functions for BOP operation, and requiring dedicated, 
independent accumulator bottles for emergency functions (autoshear/
deadman/emergency disconnect sequence (EDS)).
    BSEE received multiple comments on these proposed provisions. 
Industry stakeholders raised concerns with (and in some cases suggested 
revisions to) the proposed requirements, including the following 
concerns:
     That the proposed surface and subsea accumulator capacity 
requirements are in conflict with API Standard 53 and API Spec. 16D;
     That the terminology in the proposed rule and the current 
industry standard (API Standard 53) are inconsistent, and that the 
different terminology could cause ambiguity and confusion in efforts to 
comply with a final rule. Industry commenters recommended using the 
terminology used in the API standard; and
     That the proposed requirement that accumulator systems be 
able to supply pressure to operate all BOP components and shear pipe as 
the last step in the BOP sequence, without assistance from a charging 
unit, would increase the number of accumulator bottles needed and would 
require upgraded accumulator system controls.
    The commenters also stated that costs associated with the 
additional bottles would be significant and that the extra weight from 
additional bottles, given limited deck space availability, could cause 
structural issues with the rig.
     That the proposed requirements that the subsea accumulator 
system be able to supply pressure to operate all critical BOP 
components, and that the system have dedicated bottles for each EDS/
autoshear/deadman system(s), would greatly increase the number of 
accumulator bottles on the subsea BOP. The commenters stated that the 
increased number and weight of accumulator bottles could also cause 
structural concerns for the BOP frame and the rig and that costs 
associated with the additional bottles would also be significant.
    BSEE reviewed all of the relevant comments and has made changes to 
the proposed surface and subsea accumulator requirements in the final 
rule. In this final rule, BSEE is deleting the ``1.5 times volume 
capacity'' requirement for all surface accumulators, and instead 
requiring that all accumulator systems (including those servicing 
subsea BOPs) meet the sizing specifications of API Standard 53. The 
final rule also extends the effective date to comply with the new 
accumulator requirements (both surface and subsea) to 5 years; removes 
the proposed requirement that the surface accumulator be able to 
operate the blind shear ram as the last function in the BOP sequence; 
defines ``critical functions;'' and requires dedicated subsea 
accumulator bottles for autoshear and deadman (but not EDS) functions 
and allows those dedicated bottles to be shared between the autoshear 
and deadman functions.
    BSEE reevaluated the relevant industry standards and determined 
that API Standard 53 and API Spec. 16D provide reasonable and 
appropriate methods to ensure proper volumes and pressures of 
appropriate BOP components. Changing the proposed

[[Page 25896]]

volume requirements for surface accumulators to meet the specifications 
of API Standard 53 will allow for more specific assessments of the 
capacity necessary to address unique operating conditions, while still 
ensuring that there is enough capacity to operate all specified BOP 
components in an emergency. This will significantly reduce the 
additional costs identified in industry comments, since it eliminates 
the ``1.5 times volume'' requirement that the proposed rule would have 
extended to surface accumulators servicing a subsea BOP, and since most 
accumulator equipment has been designed to meet the API Standard 53 
specifications since that standard was adopted in 2012.
    Removing the ``1.5 times volume'' requirement and replacing it with 
the volume requirements of API Standard 53 also will not decrease 
safety or environmental protection as compared to the proposed 
requirement. BSEE determined that the methods for calculating the 
necessary fluid volumes and pressures in the API standard provide an 
acceptable amount of usable fluid and pressure to operate the required 
components, while still ensuring the required 200 pounds per square 
inch (psi) above the pre-charge pressure. API Standard 53 also 
discusses the need to have 200 psi remaining on the bottles above the 
pre-charge pressure after operating the BOP components, which would 
provide a sufficient margin of error to promote safety and help prevent 
environmental harm from failure of pressure to the BOP.
    Removing the proposed language regarding the blind shear ram being 
the last in sequence will eliminate industry's misimpression that the 
proposed language would have mandated that the blind shear ram always 
be the last step in the BOP sequence. In addition, BSEE agrees with the 
commenters that the proposed language regarding sequencing of the blind 
shear ram is not necessary, as long as the accumulator is able to 
provide sufficient volume of fluid to operate all the required BOP 
functions under MASP.
    BSEE is also making changes in the final rule to the subsea 
accumulator requirements in response to comments. BSEE is requiring 
subsea accumulators to have enough capacity to provide pressure for 
critical functions, as defined in API Standard 53, and to have 
accumulator bottles that are dedicated to autoshear and deadman 
functions (but not EDS), and that may be shared between those 
functions.
    Subsea accumulator charge normally comes from the surface, but in 
an emergency the connections to the surface may be lost and/or the 
accumulator may have already operated multiple BOP components, which 
may have reduced the accumulator fluid pressure needed to successfully 
shear and seal. Dedicated bottles for autoshear and deadman functions 
would ensure that the subsea accumulator has enough pressure available 
to operate those emergency systems even if all surface connections are 
lost or the volume or pressure in the accumulator system are depleted. 
BSEE determined, however, that permitting those functions to share the 
dedicated accumulator bottles would not result in a reduction to safety 
or environmental protection so long as the shared bottles are capable 
of providing enough pressure to operate the emergency functions. By 
contrast, dedicated capacity in a subsea accumulator for the EDS is not 
necessary, since the EDS is serviced through the main (surface) 
accumulator system by rig personnel.
3. BOP 5-Year Major Inspection
    In the proposed rule, BSEE included a provision to require a 
complete breakdown and inspection of the BOP and every associated 
component every 5 years, as documented by a BAVO, which, as proposed, 
could not be performed in phased intervals. BSEE received multiple 
comments on the 5-year inspection interval. Most industry commenters 
did not object to a 5-year inspection requirement for each BOP 
component, provided that the inspections could be staggered, or phased, 
over time. Commenters expressed concern that requiring all components 
to be inspected at one time would put too many rigs out of service, 
potentially for long periods of time, with substantial economic 
impacts.
    Based on consideration of the issues raised in the comments, BSEE 
has revised the final rule in order to allow a phased approach for 5-
year inspections (e.g., staggered inspection for each component), as 
long as there is proper documentation and tracking to ensure that BSEE 
can verify that each applicable BOP component has had the major 
inspection within 5 years. BSEE is also adding, for clarification, the 
applicable dates for the starting point of the 5-year cycle. BSEE is 
confident that these inspection requirements maintain the necessary 
level of safety and environmental protection without resulting in 
unnecessary interference with scheduling or complications for 
operations. Requiring operator documentation of the component 
inspection dates, and requiring those records to be available on the 
rig, will help BSEE to verify that the components were inspected within 
the required timeframe and will also assist BSEE's review of the 
documentation, when requested. The final rule requires that all of the 
appropriate components be inspected during the 5-year cycle. Proper 
documentation of phased inspections will improve BSEE oversight, as 
compared to current practice, while a phased approach will avoid the 
possibility of long rig shut downs.
4. Real-Time Monitoring
    In Sec.  250.724 of the proposed rule, BSEE proposed to require RTM 
of certain data for well operations that use either a subsea BOP or a 
BOP on a floating facility, or are conducted in an HPHT environment. 
Under the proposed rule, the RTM system would have been required to 
gather and ``immediately transmit'' data on the BOP control system, the 
well's fluid handling systems on the rig, and the well's downhole 
conditions with the bottom hole assembly tools (if any) to an onshore 
facility to be monitored by qualified personnel in ``continuous 
contact'' with rig personnel during operations. In addition, BSEE 
proposed that, after transmission, the RTM data must be preserved and 
stored at a designated location, identified in an APD or APM, and that 
the location and RTM data be made available to BSEE upon request. 
Finally, the proposed rule would have required immediate notification 
to the appropriate BSEE District Manager of any loss of RTM capability 
during operations and would have authorized the District Manager to 
require other measures pending restoration of RTM capabilities.
    BSEE intends for industry to use RTM as a tool (i.e., as an 
``additional pair of eyes'') to improve safety and environmental 
protection during ongoing well operations, as recommended by several 
reports on the Deepwater Horizon incident. See 80 FR 21520. BSEE does 
not intend that onshore personnel monitoring the RTM data would have 
operational control over the rig based on the data; rather, BSEE 
intends that onshore personnel could use RTM data to help rig personnel 
conduct their operations safely and to assist rig personnel in 
identifying and evaluating abnormalities and unusual conditions before 
they become critical issues. In addition, BSEE expects operators to 
review stored RTM data after operations are complete in order to 
improve well-control efficiency, training, and incident

[[Page 25897]]

investigation. Reviewing past data can help improve operations (e.g., 
understanding well conditions in certain geological formations assists 
in the collection and use of offset well data to make drilling in 
similar formations more efficient).
    There are many other aspects of RTM that were not addressed in the 
proposed rule, and that are not addressed in this final rule. In this 
rulemaking, BSEE is laying the groundwork for further development and 
use of RTM to help industry to continue improving offshore safety and 
environmental protection. Industry, academia, BSEE and others are 
studying and developing new RTM technology and processes, which 
continues to evolve. BSEE may consider additional guidance or 
regulatory requirements for use of RTM, as appropriate, in later 
rulemakings.
    BSEE received multiple comments on these issues, expressing 
concerns with these proposed provisions and suggesting alternatives. A 
more detailed discussion of the RTM comments is found in section part 
VI.C of this document. However, some of the industry concerns with the 
proposed requirements include:
     The meaning of proposed requirements to ``immediately 
transmit'' these RTM data and to maintain ``continuous contact'' 
between onshore personnel and rig personnel;
     The proposed requirement that loss of ``any real-time 
monitoring capability during operations'' requires immediate 
notification of, and possible action by, the District Manager; and
     The potential for an increase in rig personnel response 
time and a decrease in the accountability of the offshore personnel.
    In addition, several commenters suggested that BSEE require 
operators to develop specific RTM plans in lieu of some or all of the 
proposed requirements, or that the existence of such plans would 
justify BSEE eliminating some or all of the proposed RTM requirements, 
even if an RTM plan were not expressly required.
    BSEE considered all of the relevant comments and made several 
revisions and clarifications to the proposed RTM requirements in final 
Sec.  250.724. The final rule removes or replaces several provisions 
that were perceived by commenters as overly prescriptive with more 
flexible, performance-based measures that better reflect BSEE's 
intention that operators use RTM as a tool to improve their own ability 
to prevent well control incidents while providing BSEE with sufficient 
access to RTM information to evaluate system improvements. For example, 
instead of requiring an operator to notify the District Manager 
immediately of any loss of RTM capabilities, as proposed, the final 
rule requires an operator to have an RTM plan that specifies how the 
operator will notify BSEE of any significant interruption in monitoring 
or RTM communications. The revisions to the final rule also clarify 
that BSEE did not intend to require that direct operational 
responsibility for well control be shifted from rig personnel to 
onshore RTM personnel.
    Specifically, the revisions to the proposed requirements, as 
reflected in the final rule include the following:
     The phrase ``all aspects of'' was deleted from paragraphs 
(a)(1), (2), and (3).
    The deletion of that phrase provides for a more performance-based 
rule, pursuant to which the operator, based upon the particular rig 
configuration and situation, would determine the data to be collected. 
Further, the deletion of ``all aspects of'' provides more operator 
flexibility so as to reduce the probability of an increase in response 
time while maintaining the accountability of the offshore personnel. 
This revision also clarifies that RTM is intended to be used as a 
support tool for the existing rig-based chain of command and is not a 
substitute for the competency or well-control responsibilities of the 
rig personnel.
     The word ``data'' was added to clarify the systems and 
tools from which real-time data must be gathered and monitored.
    BSEE also made the following revisions and clarifications in final 
Sec.  250.724(b):
     The phrase ``barring unforeseeable or unpreventable 
interruptions in transmission'' was added to address concerns about the 
interruption of the transmission of the data.
     The word ``immediately'' was deleted with respect to 
transferring data to shore, and the phrase ``during operations where 
they must be monitored [by qualified personnel] who must be in 
continuous contact with rig personnel during operations'' was deleted. 
These revisions were made to address concern that mandatory onshore 
monitoring would result in an erosion of authority of, or shifting 
operational decision making away from, the rig-site personnel. These 
revisions also address concerns that mandatory onshore monitoring and 
continuous rig-to-shore contact might result in an increase in response 
time and a decrease in the accountability of the offshore personnel. 
They also clarify BSEE's intent that RTM involving onshore personnel 
serve as a support tool for the existing rig-based chain of command.
    BSEE also revised and clarified final Sec.  250.724(c) by deleting 
the sentences that proposed that operators who lose any RTM capability 
during operations covered by the section, you must immediately notify 
the District Manager, and that the District Manager may require other 
measures until RTM capability is restored.
    BSEE replaced the deleted sentences with a performance-based 
requirement for operators to have an RTM plan, as suggested by several 
industry commenters, that addresses several of the issues that the 
proposed rule would have addressed through prescriptive language. For 
example, most of the commenters' concerns with proposed paragraph (c) 
appear to be based on the assumption that the proposed language would 
have required every interruption in RTM capabilities--no matter how 
brief or inconsequential--to be reported to the District Manager, and 
would have resulted in orders to suspend operations in every case. 
However, BSEE did not intend that proposed requirement to apply to 
minor or routine interruptions in RTM capabilities that pose no 
significant risk to safety or of a LWC. Accordingly, the final rule now 
requires operators to have RTM plans that include procedures for 
responding to and notifying BSEE of ``significant and/or prolonged 
interruptions.'' Thus, BSEE anticipates that the final rule will result 
in essentially the same results regarding interruptions that the 
proposed rule was intended to achieve, with no loss of safety or 
environmental protection as compared to the proposal.
    Specifically, the final rule requires that the RTM plan be made 
available to BSEE upon request and that the plan include descriptions 
of:
     RTM technical and operational capabilities;
     How the RTM data will be transmitted onshore, how the data 
will be labeled and monitored by qualified onshore personnel, and how 
the data will be stored onshore;
     A description of procedures for providing BSEE access, 
upon request, to the RTM data including, if applicable, the location of 
any onshore data monitoring or data storage facilities;
     Onshore monitoring personnel qualifications;
     Methods and procedures for communications between rig and 
onshore personnel;
     Actions that will be taken in case of loss of RTM 
capabilities or rig-to-shore communications; and
     A protocol for responding to significant or prolonged 
interruptions of

[[Page 25898]]

RTM capabilities or communications, including procedures for notifying 
the District Manager of such interruptions.
5. Potential Increased Severing Capability
    As discussed in the notice of proposed rulemaking, BSEE proposed a 
variety of requirements that would increase the likelihood that a BOP 
would be able to sever a drill string in an emergency situation in 
order to shut-in the well and prevent a catastrophic blowout. (See 80 
FR 21509-21510, 21529.) However, there are a variety of components in 
the drill string (e.g., drill collars) that cannot be severed using 
currently available technology. (See id. at 21509.) Accordingly, the 
notice of proposed rulemaking expressly stated that BSEE was 
considering including an additional provision in the final rule that 
would require operators to ``install technology that is capable of 
severing any components of the drill string (excluding drill bits) . . 
. within 10 years from publication of the final rule.'' (See id. at 
21529.) BSEE explained that this performance-based requirement would 
provide additional protection against potential LWC in an emergency by 
requiring installation of new technology that could sever components of 
a drill string (e.g., drill collars) that cannot be severed using 
current shear rams.
    BSEE also explained that it was considering a 10-year timeframe for 
compliance with this potential requirement in order to provide time for 
manufacturers or operators to develop or select innovative or improved 
technologies or equipment to meet the requirement. BSEE then invited 
public comments and supporting data on a variety of key technical and 
economic questions and issues that would help BSEE decide whether to 
include such a requirement in the final rule. (See id. at 21529-21530.)
    Only a small number of comments addressed this severing issue. 
Several industry commenters opposed the idea or stated that it would be 
extremely difficult and expensive to meet, and that even 10 years might 
not be long enough to come into compliance. One commenter suggested 
that BSEE require that shearable sections be designed into the drill 
string (instead of requiring that everything be shearable), and that a 
shearable section of the drill string must be across one of the 
shearing rams at all times. The same commenter asserted that shearable 
drill collars currently exist, but did not provide any additional 
technical or economic information supporting that assertion. Another 
commenter supported the requirement in general, but suggested that it 
should be implemented in less than 10 years. None of the comments, 
however, provided adequate relevant technical or economic data or other 
information to help BSEE determine whether to include the requirement 
in the final rule.
    Accordingly, although BSEE still believes that such a severing 
requirement could provide important additional controls to prevent 
future well-control events and catastrophic blowouts, such as the 
Deepwater Horizon incident, BSEE has decided that it needs more time 
and more information to make a final decision about whether to adopt 
such a severing requirement. Therefore, BSEE will review severing 
technology on a periodic basis, with the intention of concluding the 
review no later than seven years from the publication of this final 
rule. BSEE will conduct a retrospective review of this rule under E.O. 
13563, according to DOI's regulatory review plan. If, after obtaining 
and considering additional information, BSEE decides to proceed with 
adoption of such a regulation, BSEE will propose to do so in a separate 
rulemaking document.
6. BOP Pressure Testing Interval
    BSEE received a number of comments on proposed Sec.  250.737(a)(2), 
which proposed to harmonize the pressure testing interval for BOPs used 
in workovers and decommissioning operations (currently 7 days) with the 
existing 14-day interval for pressure testing BOPs used in drilling and 
completion operations.
    In the proposed rule, BSEE explained that increasing the test 
interval for workover and decommissioning BOPs from 7 days to 14 days 
could decrease wear and tear on those BOPs, and thus increase their 
durability and reliability in the long-term and otherwise potentially 
improve safety. (See 80 FR 21511.) BSEE also explained that it expected 
that BOP equipment meeting the other proposed new requirements would 
perform more reliably than previous equipment, thus making 7-day 
testing for workover and decommissioning BOPs less crucial. (See id. at 
21524.)
    In addition, BSEE requested comments on whether the pressure 
testing interval for BOPs used in all types of operations should be 7 
days, 14 days (as proposed), or 21 days. BSEE also requested comments 
on the potential cost implications of each of those intervals. (See id. 
at 21511.) In its initial economic analysis for the proposed rule, BSEE 
estimated the potential savings from increasing the pressure testing 
interval from 7 to 14 days for workover and decommissioning BOPs to be 
about $150 million per year, and the potential cost savings that would 
result from increasing the testing interval for all BOPs from 14 to 21 
days to be approximately $400 million per year.
    In response, one commenter suggested that BSEE require more 
frequent BOP pressure tests (i.e., every 7 days for all BOPs used in 
Arctic OCS operations), and claimed that BSEE had not justified 
changing the 7-day testing requirement for workover and decommissioning 
BOPs to 14 days. However, most commenters, primarily from industry, 
supported increasing the pressure testing interval for workovers and 
decommissioning and recommended increasing the testing interval for all 
BOPs to 21 days. Commenters cited API Standard 53, which recommends a 
21-day BOP test cycle for shear ram BOPs, as well as international 
industry best practices, in support of longer pressure test intervals. 
Multiple commenters also pointed out that less frequent testing would 
mitigate wear and tear on the equipment from the testing itself, and 
that wear and tear adversely affects long-term reliability of the 
equipment and thus increases the risks of equipment failure. Some 
commenters also referred to past joint industry research projects and 
studies, which they suggested support test intervals longer than 14 
days.
    BSEE has long been involved with joint industry projects and 
studies on BOP reliability and, after reviewing the comments on the 
proposed rule, has concluded that increasing the test interval for 
workover and decommissioning BOPs from 7 to 14 days is appropriate in 
terms of decreasing wear and tear and increasing long-term reliability 
of those BOPs. BSEE and the industry now have substantial experience 
with the efficacy of the longstanding 14-day testing requirement for 
BOPs used in drilling and completion operations, and BSEE believes that 
testing decommissioning and workover BOPs every 14 days will avoid the 
extra wear and tear and safety risks inherent in 7-day testing and will 
not result in any diminution of safety and environmental protection as 
compared to 7-day testing.
    BSEE is not aware, however, of any new data that justifies 
increasing the BOP pressure testing interval for all BOPs from 14 days 
to 21 days. The previous studies and data on BOP testing frequency that 
were submitted to MMS prior to the Deepwater Horizon incident, as 
mentioned by some

[[Page 25899]]

commenters, were not deemed by MMS sufficient to justify increasing the 
pressure testing interval from 14 to 21 days. In the proposed rule, 
BSEE explained that it was reevaluating this issue and requested 
additional data and technical analysis regarding the proposed pressure 
testing frequency requirements to determine if a uniform 21-day testing 
interval should be included in the final rule. Given the operational 
issues that had previously been brought to BSEE's attention by the 
industry, and the potential costs savings ($400 million dollars per 
year) that BSEE estimated could result from moving from 14-day to 21-
day testing, BSEE anticipated that significant technical and economic 
comments would be submitted on this issue. Comments in support of such 
a change were submitted; however, these comments did not provide 
adequate data and information to reasonably support a 21-day testing 
interval at this time.
    BSEE is aware of concerns that the more frequently BOPs are tested, 
the more likely the equipment is to wear out prematurely; however, it 
does not automatically follow that every extension of test intervals 
always increases reliability, and thus safety and environmental 
protection, in the long-term. The industry commenters do not dispute 
that testing must occur at appropriate intervals to provide assurance 
that BOPs will function as intended when needed to prevent a blowout. 
BSEE's experience with 14-day pressure testing for drilling and 
completion BOPs indicates that it is effective for its purpose and 
that, in the absence of significant new information on longer test 
intervals, it is appropriate to retain that interval for such BOPs and 
to apply the same requirement to workover and decommissioning BOPs.
    BSEE believes that the provisions in the final rule that increase 
the exchange of data on equipment reliability, that improve the design, 
manufacturing, maintenance and repair of BOP equipment, and that 
require the use of BAVOs or other independent third-parties to verify 
and document BOP testing, repairs and maintenance will result in 
improved performance and reliability of BOPs in the future. However, in 
the absence of new data demonstrating that 21-day testing would be as 
protective as 14-day testing, BSEE has decided to finalize the proposed 
14-day pressure testing requirement for BOPs used in all types of 
operations. In response to the Deepwater Horizon incident, industry 
attempted to voluntarily improve the overall reliability of well 
control equipment through better designs, improved manufacturing 
processes, better maintenance and repair procedures, and increased data 
sharing. BSEE will consider the possibility of adopting 21-day BOP 
testing when it receives adequate new (post-Deepwater Horizon) data and 
analyses demonstrating that BOP reliability and capability, and 
personnel safety, are not adversely affected (or are actually improved) 
by pressure testing at 21-day intervals. This could include, for 
example, data from BOP testing and usage in OCS or other waters. BSEE 
will consider relevant data, along with any data indicating that the 
other requirements contained in this rule (such as BAVO verification), 
have increased overall BOP performance and reliability and decreased 
the risk of failure of the systems and components. In the meantime, any 
operator that believes its specific circumstances warrant a longer 
pressure test interval may seek approval from the District Manager to 
use alternate procedures or equipment under Sec.  250.141.

C. Other Differences Between the Proposed and Final Rules

    In addition to the significant changes discussed in the preceding 
section, BSEE has also made changes to the rule in response to comments 
suggesting that BSEE eliminate redundancy, clarify some potentially 
confusing language, streamline the regulatory text, and align certain 
provisions in the proposed regulatory text more closely with relevant 
terminology in API Standard 53 (where BSEE intended the proposed 
provisions to be consistent with that standard). In some cases, we 
agreed with and accepted specific wording changes suggested by the 
commenters, and in some cases we made changes based on our agreement 
with the commenters' basic suggestion, even though the commenter 
provided no specific alternative language or we did not agree with the 
specific wording suggested by the commenter. In still other cases, we 
made minor revisions to proposed provisions in order to correct 
grammatical errors, eliminate potential ambiguity, or to avoid 
confusion by further clarifying the intent of the proposed language. 
The revisions include the following:
     In final Sec.  250.292, we clarified the proposed language 
about pipeline free standing hybrid risers ``on a permanent 
installation.''
     In final Sec.  250.421, we clarified the proposed language 
regarding cementing the liner lap and what actions are necessary when 
an operator is unable to meet the cementing requirements of the liner 
lap section.
     In final Sec.  250.462, we revised the language from 
``pressure holding'' to ``pressure containing'' critical components. We 
also clarified language on excluding downhole safety valves. And we 
clarified the equipment that operators must make available to BSEE for 
inspection. We revised this section to clarify the differences between 
collocated equipment and SCCE (e.g., collocated equipment includes 
dispersant injection equipment.)
     In final Sec. Sec.  250.518, 250.619, and 250.1703, we 
clarified that, for the purposes of those sections, permanently 
installed packers and bridge plugs must comply with the referenced 
industry standard.
     In final Sec.  250.703, we replaced ``the most extreme 
service conditions'' with ``the maximum environmental and operational 
conditions'' to which equipment may be exposed at a given well.
     In final Sec.  250.711, we clarified that the same well-
control drill cannot be repeated consecutively with the same crew, in 
order to avoid overly narrow training for certain personnel and to 
improve proficiency in well-control procedures by a broader set of rig 
personnel without unduly limiting the operator's discretion to schedule 
important drills.
     In final Sec.  250.712, we changed the timeframe for 
informing BSEE of the rig movement from 72 hours to 24 hours' notice 
before movement. BSEE agreed with commenters that requiring 72 hour 
notice may have necessitated additional revisions to the submitted form 
due to the constant changes of operations affecting rig movements. 
Requiring a 24 hour notification provides a better indication of when a 
rig will move.
     In final Sec.  250.713, we deleted the reference to ``lift 
boats'' and made other minor changes to improve consistency in rig-
related terminology.
     In final Sec.  250.715, we also revised the language to 
provide more consistency in rig-related terminology and to clarify the 
requirements for access to GPS data.
     In final Sec.  250.721, we clarified that operators must 
test the liner-top, instead of the liner-lap, and that the pressure 
testing of the entire well should not exceed 70 percent of the burst 
rating limit of the weakest component.
     In final Sec.  250.722, we clarified that calculations 
must be included if an imaging tool or caliper is used.
     In final Sec.  250.730, we:
    [cir] Clarified that the lessee or operator must ensure that the 
BOP systems are designed, installed, maintained, inspected, tested and 
used properly (instead of the lessee or operator

[[Page 25900]]

actually performing these actions themselves), since these actions are 
usually performed by contractors.
    [cir] Clarified that the working pressure rating for annulars does 
not need to exceed MASP.
    [cir] Clarified that the BOP system (instead of each ram) must be 
capable of closing and sealing the wellbore at all times and provide 
reliable means to handle well-control events.
    [cir] Clarified paragraph (a)(2) to provide that the BOP systems 
must meet the provisions of the specified industry standards that apply 
to BOP systems.
    [cir] Revised the failure reporting procedures in paragraph (c) to 
include submitting such reports to BSEE.
    [cir] Clarified paragraph (d)(1) to remove the reference to the 
alternative compliance regulations at Sec.  250.141.
     In final Sec.  250.732, we:
    [cir] Revised paragraph (a) by extending the compliance date for 
BAVO-related requirements to 1 year from the date BSEE publishes a BAVO 
list and adding new paragraphs (a)(1) and (2). Final paragraph (a)(1) 
provides that, until the requirements to use BAVOs become effective, 
operators must use an independent third-party to provide the 
certifications, verifications, and reports that a BAVO must provide 
after the BAVO requirements become effective. Final paragraph (a)(2) 
clarifies the criteria for independent third-parties, based on the 
longstanding criteria in use under current regulations.
    [cir] Revised paragraph (b)(1)(vi), by replacing ``all testing 
results'' with ``relevant testing results.''
    [cir] Revised paragraph (d)(6) to clarify that training for 
personnel who service, repair or maintain BOPs must cover ``any 
applicable'' OEM requirements.
     In final Sec.  250.733, we removed redundant requirements 
that are covered in other sections.
     In final Sec.  250.734, we:
    [cir] Revised the ROV provisions to require opening and closing of 
ram locks, one pipe ram, and the Lower Marine Riser Package (LMRP) 
disconnect.
    [cir] Clarified that the ROV crew must be capable of carrying out 
appropriate tasks during emergency operations.
    [cir] Simplified paragraph (a)(6)(vi) by deleting a phrase that 
would have required a failsafe system to use ``logic'' that makes every 
step independent from the previous step, and inserting instead the 
words ``once activated.''
    [cir] Clarified in paragraph (a)(7), that if an operator chooses to 
``use'' an acoustic control system there are applicable requirements to 
demonstrate that it will function in the proposed environment and 
conditions.
    [cir] Clarified that control panels must have ``enable'' buttons or 
similar features to ensure two-handed operation.
    [cir] Clarified that there must be a side outlet installed below 
the lowest sealing shear ram.
    [cir] Clarified that, if there are dual annulars, a gas bleed line 
must be installed below the upper annular.
    [cir] Revised the language regarding testing of the equipment after 
making repairs, and clarified the testing requirements under certain 
circumstances.
     In final Sec.  250.735, we revised paragraph (e), to 
clarify the required location of the kill line, and paragraph (g) to 
eliminate the proposed requirement for hydraulically operated locks for 
pipe rams on surface BOPs and to replace the proposed requirement for 
hydraulic locks on surface BOP blind shear rams with a requirement for 
remotely-operated locks.
     In final Sec.  250.736, we revised the kelly valve 
requirements to better reflect current practice and technology.
     In final Sec.  250.737, we:
    [cir] Clarified, in paragraph (d)(2), that water must be used to do 
the initial test for surface BOP systems, but that drilling/completion/
workover fluids may be used to conduct subsequent tests.
    [cir] Clarified the requirements for testing pods between control 
stations.
    [cir] Removed redundant provisions covered under other sections.
     In final Sec.  250.738, we:
    [cir] Revised paragraph (a) by removing the requirement to notify 
the District Manager of problems or irregularities ``including leaks''; 
however, these problems or irregularities must be recorded on the daily 
report, which must be made available to BSEE upon request.
    [cir] Revised paragraph (e) to clarify that one set of pipe rams 
(instead of two) must be capable of sealing around the smaller size 
pipe.
    [cir] Revised paragraph (f) to clarify the required testing of the 
connections if casing rams or casing shear rams are installed in a 
surface BOP stack.
    [cir] Revised paragraph (l) to clarify the required testing of the 
wellhead/BOP connection if a test ram is to be used.
    [cir] Revised paragraph (p) to clarify the requirements that apply 
if the bottom hole assembly needs to be positioned across the BOP.
     In final Sec.  250.739, we clarified personnel training 
and records requirements.
     In final Sec.  250.746, we added a reference to digital 
recorders, clarified the actions required when there are leaks 
associated with a BOP control system, and made minor changes to provide 
consistency in rig-related terminology.
     In final Sec. Sec.  250.414(k), 250.713(e), 250.714(e), 
250.721(d) and (g)(3), 250.722(a)(1), 250.734(a)(7), 250.738(o), 
250.740(g), 250.743(c), and 250.744(a), we clarified the purposes for 
which District Managers may require additional information, testing, or 
other procedures consistent with the purposes of those sections.

VI. Discussion of Public Comments on the Proposed Rule

    In response to the proposed rule, BSEE received over 172 sets of 
comments from individual entities (e.g., companies, industry 
organizations, non-governmental organizations, and private citizens). 
Some entities submitted comments multiple times. All relevant comments 
are posted at the Federal eRulemaking portal: https://www.regulations.gov. (To access the comments at that website, enter 
BSEE-2012-0002 in the Search box.) BSEE reviewed all comments 
submitted. Each of the following sections contains a brief summary of 
the relevant and significant comments as well as BSEE's responses.

A. Requests for Extension of the Proposed Rule Comment Period

    Summary of comments: BSEE received requests from various 
stakeholders asking BSEE to extend the comment period on the proposed 
rule. The majority of those requests sought extensions of 120 days, 
which would have tripled the length of the original 60-day comment 
period. BSEE also received a written comment from another stakeholder 
urging BSEE not to extend the comment period because the proposed rule 
has been in development since the Deepwater Horizon incident, is based 
on recommendations resulting from that incident, and represents a 
critical regulatory improvement that should be finalized without delay.
     Response: BSEE considered those requests and determined 
that extending the original 60-day comment period by an additional 30 
days provided sufficient additional time for review of and comment on 
the proposal without unduly delaying a final rulemaking decision. The 
comment extension to the notice of proposed rulemaking was published in 
the Federal Register on June 3, 2015. (See 80 FR 31560.)
    Summary of comments: Various commenters asserted that even the 90-
day public comment period was inadequate for a rule of this technical 
complexity, and that additional time (e.g., 120 days) was needed to 
properly

[[Page 25901]]

address the substantial amount of technical content and complexity in 
this draft. They suggested that the comment period should be reopened 
and/or that BSEE publish a revised proposed rule for comment.
     Response: BSEE believes that the 90-day comment period, 
which includes the 30-day extension granted by BSEE, was reasonable and 
sufficient under the Administrative Procedure Act (APA). The APA 
requires that agencies give ``interested persons an opportunity to 
participate'' in the rule making process through submission of written 
data, views or arguments. (See 5 U.S.C. 553(c).) The APA does not 
prescribe the number of days that an agency must allow for written 
comments, and an agency's decision on comment period length is 
generally deferred to unless it is arbitrary and capricious. (See 5 
U.S.C. 706(2).)

B. Summary of General Comments on the Proposed Rule

1. Comments Supporting the Proposed Rule
    Summary of comments: Multiple commenters commended the efforts by 
BSEE to improve safety and environmental protection and expressed their 
support for many of the changes in the proposed rule.
     Response: It is BSEE's continued mission to promote 
safety, protect the environment, and conserve resources offshore 
through vigorous regulatory oversight and enforcement. This final rule 
is an important step toward better well control and improved safety and 
environmental protection.
2. Legal Comments
    Summary of comments: Several commenters claimed that BSEE failed to 
incorporate the principles of best available and safest technologies 
(BAST) reflected in OCSLA, resulting in requirements that are 
arbitrary, not reasonable or practicable, not economically or 
technically feasible, less safe, and more obstructive to OCS oil and 
gas development, in violation of the OCSLA-mandated balance between 
safety and environmental protection and expeditious and orderly 
development of OCS resources.
     Response: BAST requirements, as set out in OCSLA and its 
implementing regulations (see 30 CFR 250.107) are the product of 
specific BSEE analyses and determinations. Existing BSEE regulations 
and this final rule contain numerous technology requirements, all of 
which were adopted through notice and comment rulemaking. The proposed 
rule explained the justifications for codifying the technological 
requirements in the final rule, many of which were derived from 
recommendations based on exhaustive investigations and reports on the 
Deepwater Horizon incident, and on input from experts representing 
equipment manufacturers, the offshore oil and gas industry, government, 
academia, and environmental organizations focused on identifying 
appropriate technological standards. BSEE believes that the 
requirements in this regulation provide an appropriate level of safety. 
BSEE may make a separate determination in the future related to the use 
of BAST, pursuant to OCSLA, if supplemental requirements are necessary.
    Summary of comments: Several industry commenters claimed that 
certain provisions in the rule could render leases uneconomical to 
operate, thereby requiring a Takings Implication Analysis (TIA) by BSEE 
under Executive Order (E.O) 12360, and potentially amounting to a 
breach of contract by DOI.
     Response: By their own terms, OCS oil and gas leases 
expressly state that they are subject to regulations promulgated after 
lease issuance, including the types of regulatory action reflected in 
this final rule. Accordingly, the adoption of this final rule is 
consistent with lessees' rights to conduct operations on the OCS--which 
are derived entirely from their lease interests--and thus do not amount 
to a breach of contract or a taking under the Fifth Amendment. As a 
result, a TIA is not necessary.
    E.O. 12630 requires executive agencies to review agency actions, 
including rulemakings, that have takings implications (i.e., actions 
that, if implemented, could effect a taking) to prevent unnecessary 
takings and to identify and discuss any significant takings 
implications and the agency's conclusions on the takings issues. In 
this case, the terms of all OCS oil and gas leases allow BSEE to 
promulgate new rules, pursuant to OCSLA, without violating the rights 
created by the lease contracts. Specifically, leases issued prior to 
2010 state:

    This lease is issued pursuant to the Outer Continental Shelf 
Lands Act. . . . The lease is issued subject to the Act; all 
regulations issued pursuant to the Act and in existence upon the 
Effective Date of this lease; all regulations issued pursuant to the 
statute in the future which provide for the prevention of waste and 
conservation of the natural resources of the Outer Continental Shelf 
and the protection of correlative rights therein, and all other 
applicable statutes and regulations.

    Leases issued since 2010 likewise provide that:

    This lease is subject to [OCSLA], regulations promulgated 
pursuant thereto, . . . and those . . . regulations promulgated 
thereafter, except to the extent they explicitly conflict with an 
express provision of this lease. It is expressly understood that 
amendments to existing . . . regulations . . . as well as the . . . 
promulgation of new regulations, which do not explicitly conflict 
with an express provision of this lease may be made and that the 
Lessee bears the risk that such may increase or decrease the 
Lessee's obligations under the Lease.

    None of the provisions of this rule explicitly conflict with any 
express provisions of OCS oil and gas leases.
    The Supreme Court and other Federal courts have interpreted the 
relevant lease language to mean that ``[a] change to an OCSLA 
regulation does not breach the express terms of the lease language.'' 
Century Exploration New Orleans, LLC v. United States, 745 F.3d 1168, 
1178 (Fed. Cir. 2014), citing Mobil Oil Exploration & Production 
Southeast, Inc. v. United States, 530 U.S. 604, 616 (2000); Century 
Exploration New Orleans, LLC v. United States, 110 Fed. Cl. 148, 164-66 
(2013) (the lease language ``allocates the risk of certain legal 
changes--future regulations issued pursuant to OCSLA--to [lessees]''). 
This conclusion is in no way dependent upon the impacts of such a 
rulemaking on the economics of lease development.
    The express language of the leases (in sections 10 and 12) likewise 
requires that the lessee comply with all applicable regulations, and 
OCSLA expressly provides that regulations promulgated pursuant to the 
statute apply to both new and existing leases as of their effective 
date. 43 U.S.C. 1334(a). Because all changes to the regulatory language 
implemented through this rule are made pursuant to OCSLA, they are 
expressly incorporated into the terms of the leases and thus consistent 
with lessees' rights thereunder. In light of the fact that the entirety 
of lessees' rights to conduct the impacted operations on the OCS are 
derived from their leases, regulation that is consistent with those 
lease rights likewise cannot amount to an unconstitutional taking of 
those lease rights. Accordingly, promulgation of this rule does not 
amount to a breach of any lease terms or a taking of any rights derived 
from OCS leases.
    Summary of comments: Some commenters raised issues concerning the 
World Trade Organization's (WTO's) Technical Barriers to Trade 
Agreement (TBT Agreement). In particular, the commenters asserted that 
purported inconsistencies between the proposed rules and API Standard 
53 require

[[Page 25902]]

compliance with notification procedures under the TBT Agreement.
     Response: 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.
    The proposed 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 will 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.
3. Arctic-Related Comments
    Summary of comments: Multiple commenters recommended extending 
certain equipment, testing and monitoring requirements in the proposed 
rule to all operations on the Arctic OCS, where some of those 
operations would not have been covered under the terms of the proposed 
requirements. For example, some commenters recommended that BSEE 
require a second set of blind shear rams to be installed in the BOP 
stack for all operations in the Arctic, including surface BOPs on 
gravel and ice islands and bottom-founded structures in the Arctic, 
even though the proposed requirement was only intended to apply to 
surface BOPs on floating facilities (See Sec.  250.733(b)(1)).
    Commenters also suggested that all BOPs used on the Arctic OCS 
undergo independent verification by a qualified third-party 
organization, and that Arctic operators submit to BSEE an annual 
Mechanical Integrity Assessment (MIA) Report prepared by a BAVO, even 
though BSEE proposed that the MIA Report requirement apply only to 
subsea BOPs, BOPs in HPHT environments, and surface BOPs on floating 
facilities. The commenters asserted that extending these requirements 
would ensure that each BOP used on the Arctic OCS is fit for Arctic OCS 
service. Commenters also suggested extending to all Arctic OCS 
facilities: the proposed requirements in Sec.  250.724 for RTM for 
subsea BOPs, BOPs in HPHT environments, and surface BOPs on floating 
facilities; and the proposed Source Control and Containment 
requirements in proposed Sec.  250.462 for subsea BOPs or surface BOPs 
on floating facilities.
    Some commenters also requested that BSEE revise the existing 
regulations to strengthen equipment and operational requirements for 
equipment used on the Arctic OCS. These suggestions included: Requiring 
Arctic operators to submit a cementing protocol and quality assurance 
plan, prepared by an experienced Arctic drilling engineer, as part of 
their APD; daily well activity reporting requirements for the Arctic 
OCS; and mandatory use of cement evaluation tools and temperature logs.
    Some of the comments were expressly related to provisions in BSEE's 
proposed rule, ``Requirements for Exploratory Drilling on the Arctic 
Outer Continental Shelf.'' (See 80 FR 9916 (Feb. 24, 2015).) The 
commenters stated that they submitted the same comments to BSEE in 
response to that proposed rule.
     Response: The requirements in this final rule apply to any 
OCS facility in any BSEE region (GOM, Pacific, Alaska), including an 
Arctic OCS facility, that meets the general conditions for 
applicability stated in the specific regulatory provisions. For 
example, some provisions (such as Sec.  250.730--What are the general 
requirements for BOP systems and system components?) apply nationwide 
to all BOPs on all OCS facilities, including any facility with a BOP on 
the Arctic OCS. Other requirements apply only to specific types of 
facilities or equipment or BOP systems (such as the requirements in 
Sec.  250.733, which apply only to surface BOP stacks, and the 
requirements in Sec.  250.734, which apply only to subsea BOPs). And 
some provisions apply to any facility or BOP that meets specific 
conditions, such as Sec.  250.732(d), which requires an operator to 
submit an annual MIA report for any subsea BOP, BOP in an HPHT 
environment, or surface BOP on a floating facility. In any case, all of 
the provisions in this final rule apply without regard to the OCS 
region in which the facility or BOP is operating.
    BSEE recognizes that the Arctic OCS presents a uniquely challenging 
operating environment, characterized by extreme environmental 
conditions, geographic remoteness, and a relative lack of fixed 
infrastructure and existing operations. However, many of the comments 
submitted on the Arctic OCS issues are outside the scope of this well-
control rulemaking. BSEE has decided to address Arctic-specific issues 
in separate rulemakings, guidance documents, or on a case-by-case basis 
as needed. Most of the comments related to the Arctic that were 
submitted under this rulemaking were also submitted in response to the 
proposed Arctic OCS exploratory drilling rule proposed in February 2015 
and will be considered by BSEE in that rulemaking.
4. General Comments
a. ``Grandfathering'' of Certain Equipment Requirements
    Summary of comment: Multiple commenters asserted that it is not 
clear whether existing facilities will be ``grandfathered in,'' (i.e., 
that the final requirements would apply only to new facilities or 
equipment installed after the final rule's effective date), or whether 
existing facilities will have to comply with all provisions of the 
final rule, even if that requires, for example, installing new 
equipment or retrofitting existing equipment, which the commenters 
claimed would be very expensive and burdensome.
    Similarly, some commenters asserted that it is not clear whether 
existing equipment already under construction or in fabrication will 
have to comply with the new regulations in the event that the new 
regulations are published or become effective during or after 
fabrication, but prior to startup of new facilities or actual 
installation of the equipment. The commenters asserted that, under this 
interpretation, compliance may not be possible to achieve without 
significant delay and associated costs.
    A commenter stressed that application of manufacturing 
specifications (e.g., API Spec. 16A, Spec. 16C, and Spec. 16D), 
incorporated by reference in certain provisions of this rule, to 
existing equipment would effectively preclude the use of such 
equipment. The commenter also claimed that BSEE had not considered the 
cost of application of those standards in the initial economic analysis 
for the proposed rule.
     Response: During the rulemaking process, BSEE makes a 
determination about how or whether new and revised regulations will 
apply to existing operations, equipment, and facilities during the 
rulemaking process. As a general matter, OCSLA provides that all 
regulations promulgated thereunder (including this rule) ``shall, as of 
their effective date, apply to all operations conducted under a lease 
issued or maintained under'' OCSLA. (43 U.S.C. 1334(a).)
    When BSEE decides to exempt existing operations, equipment, or 
facilities from a specific provision, BSEE makes that clear in the 
regulatory text or relevant preamble discussions for the rule. In this 
rulemaking, each of the specific requirements for equipment or 
facilities will apply to the equipment or facilities that are described 
in that

[[Page 25903]]

provision, without regard to whether the facility or equipment already 
exists, unless specifically stated otherwise. For example, (as 
discussed elsewhere in this document), Sec.  250.733(b)(2) of the final 
rule requires use of a dual bore riser configuration on facilities that 
plan to use surface BOPs on floating production facilities, if risers 
are installed 90 or more days after publication of the final rule 
(e.g., at the effective date of the rule). This means that existing 
surface BOPS on floating facilities using single bore risers installed 
less than 90 days after the publication of the final rule (e.g., before 
the effective date of the rule) are not required to be retrofitted with 
dual bore risers.
    BSEE notes that many of the requirements in this final rule are not 
new, but are the same as or very similar to longstanding requirements 
in the existing regulations. Thus, those requirements will simply 
continue to apply to existing facilities or equipment. In addition, 
several of the most significant new requirements in this rule do not 
require compliance for several years--or longer in some cases (see part 
III of this document)--so the impact of those requirements on existing 
facilities or equipment will be substantially mitigated by those 
extended compliance periods (e.g., some equipment potentially affected 
by some new requirements may already be due for replacement or major 
updates by the time such new requirements take effect). If there are 
unique circumstances that indicate that use of some equipment or 
procedures, other than as specified in this final rule, may be 
warranted, an operator may seek approval to use alternate equipment or 
procedures under existing Sec.  250.141, if the operator can 
demonstrate that such equipment or procedures will provide a level of 
safety and environmental protection that equals or surpasses these 
requirements.
b. Requests for Additional Workshops
    Summary of Comments: Numerous commenters recommended that BSEE hold 
additional workshops related to this rulemaking. Most of those 
commenters recommended that BSEE postpone finalizing the proposed rule, 
reopen the public comment period, and hold workshops during the new 
comment period before adopting a final rule. Some commenters, however, 
suggested that BSEE hold workshops after adopting the final rule, in 
order to further the industry's understanding of the provisions of this 
rulemaking. Commenters discussed a number of issues that they asserted 
warranted such workshops. One commenter stated that industry concerns 
over perceived technical flaws in, and potentially significant impacts 
from, the proposed rule, and the limited time provided to comment on 
the proposal, warranted workshops or some other form of engagement 
between BSEE and industry to make sure that the regulations are 
technically viable, provide optimum risk management, and are in the 
best interest of America's economy and domestic energy security.
    A commenter expressed concerns that the proposed rule, as written, 
would not achieve BSEE's actual goals. This commenter suggested that 
BSEE should arrange workshops with industry to discuss the meanings of 
the proposed rules and revise the rules to improve safety while 
reducing unintended consequences.
     Response: As previously discussed in this document, BSEE 
actively engaged--in meetings, training, workshops and other forums--
with many stakeholders, including industry, for several years prior to 
and during development of the proposed rule. In particular, BSEE 
convened Federal decision-makers and stakeholders from the OCS 
industry, academia, and other entities at a public forum on offshore 
energy safety on May 22, 2012, to discuss ways to address well-control 
concerns arising from the Deepwater Horizon incident investigations. 
Those investigations and the May 2012 forum resulted in numerous 
recommendations to enhance safety and environmental protection of 
offshore operations by improving well control and BOP performance. BSEE 
recognized the importance of collecting the best ideas, from all 
perspectives, on the prevention of well-control incidents and blowouts 
to assist BSEE in developing this rule. This included industry's 
valuable knowledge and skillsets.
    BSEE received significant input and specific recommendations from 
many industry groups, operators, equipment manufacturers, academics and 
environmental organizations as a result of the 2012 forum. 
Subsequently, BSEE sought and received additional input on potential 
means to improve well control through BSEE attendance at industry and 
public conferences, industry standards committee meetings, and BSEE's 
own standards workshops. BSEE also invited industry assessments of 
BSEE-funded technology research projects related to well control. BSEE 
conducted at least 50 meetings with various companies, trade 
associations, regulators, and other stakeholders interested in well 
control as part of this process.
    BSEE considered all of this input in developing the proposed rule 
published in April 2015. (See 80 FR 21508-21509.) Subsequently, at the 
request of several commenters, including industry commenters, BSEE 
extended the comment period for the proposed rule to 90 days, so 
commenters would have even more time to develop and present their views 
and relevant information.
    Subsequently, BSEE received over 170 comments on the proposed rule, 
some extremely detailed, covering almost every section of the proposed 
rule, and hundreds of which related to specific technical, economic and 
other issues. Many of the comments were submitted by members or 
representatives of the offshore oil and gas industry, as well as 
environmental groups, academics, other Federal agencies, and interested 
members of the public. BSEE subject matter experts (including 
experienced engineers and economists) carefully considered all of the 
relevant and significant comments in developing this final rule. As 
discussed elsewhere in this document, BSEE not only responded to those 
comments, but made a number of revisions to the final rule to address 
concerns or information described in the comments.
    In light of all of these efforts, BSEE does not agree with the 
commenters that urged BSEE to delay this final rule pending more 
workshops. BSEE intends to stay fully engaged with the affected 
industry and other stakeholders as this rule is implemented, and 
expects to participate in future meetings and workshops where the 
issues in this rulemaking will continue to be discussed. As experience 
and additional information are gained under this rule, BSEE will both 
provide guidance and clarification on this rule, as necessary.
c. Licensed Engineers
    Summary of Comments: A commenter recommended that BSEE require the 
use of a licensed engineer at every stage during the entire life-cycle 
of OCS platforms, including design, development, construction, 
commissioning, maintenance, operations and salvage. The commenter noted 
that licensed professional engineers (PEs) are required by law to hold 
public safety paramount.
     Response: BSEE does not agree that the use of PEs should 
be required more often than already provided for in this final rule and 
the existing regulations. Several provisions of the final rule require 
PE certifications. For example, final Sec.  250.428(b) requires 
certification by a PE for changes to casing setting depth or hole 
interval drilling depth and changes to the well program due to an 
inadequate cement job. There are also several provisions in the 
existing

[[Page 25904]]

regulations (e.g., Sec.  250.420(a)(6)(i)) that require, or allow, the 
use of PEs and that are unchanged by this final rule. In addition, the 
requirements in this final rule for verifications and certifications by 
a BAVO or other independent third-party will help ensure that the 
safety and environmental protection purposes of this rule will be 
achieved without the need for additional requirements for use of PEs.
d. Requests for Shorter or Longer Compliance Periods
    Summary of Comments: Some commenters observed that the proposed 
rule was published more than five years after the Deepwater Horizon 
incident. The commenters voiced support for the proposed effective date 
of 3 months following publication of the final rule for most of the 
proposed rule's requirements, since most, but not all, operators are 
already using equipment and procedures consistent with a majority of 
the proposed requirements. The commenters expressed concern with the 
proposal for longer compliance periods for several key requirements, 
including: 3 years for RTM; 5 years for shear rams on subsea BOPs and 
on surface BOPs on floating facilities; and 7 years for a mechanism 
coupled with each shear ram that centers drill pipe during shearing 
operations. One of the commenters noted it could be more than sixteen 
years after the Deepwater Horizon incident before BSEE finalizes and 
the industry implements critical components of offshore drilling 
safety. The commenters urged BSEE to shorten these compliance periods 
to enhance safety and environmental protection in an expeditious 
manner.
    BSEE received other comments on the proposed rule, however, that 
raised concerns that the proposed compliance periods for certain 
provisions were too short. Those concerns included: Availability of 
required equipment; time needed to plan and install the equipment; and 
time needed to develop new or alternative equipment to meet the 
requirements.
     Response: BSEE agrees that it is extremely important to 
move ahead with these final rules to implement many of the 
recommendations from the Deepwater Horizon investigations and to help 
prevent catastrophic events from occurring again. BSEE considered a 
number of factors in identifying appropriate compliance periods for the 
various provisions in this rule, including information from public 
commenters on those requirements and information obtained, among other 
activities, from prior interactions with stakeholders, involvement in 
development of industry standards, and evaluation of current 
technology.
    BSEE considered all of the comments regarding shortening and 
lengthening the compliance periods and determined that most of the 
proposed compliance periods were appropriate. BSEE did, however, 
determine that several requirements warranted longer compliance 
periods, as discussed in part III of this document. BSEE believes that 
compliance with these rules will improve well control, safety and 
environmental protection in a timely manner for the near and long term.
5. Contractor/Operator/Manufacturer Responsibilities
    Summary of comments: Several commenters expressed uncertainty 
regarding potential responsibilities and liabilities of contractors and 
individuals performing regulated activities.
     Response: These final regulations do not alter BSEE's 
existing position and interpretations with respect to the parties 
responsible for complying with applicable regulations and related 
requirements. The lessee, operator (if one has been designated), and 
the person that actually performs an activity (which includes 
contractors) to which a particular provision of a regulation, lease, 
permit, or plan applies are jointly and severally responsible for 
complying with that provision. (See Sec.  250.146(c).) Regulatory 
compliance is a fact-specific and context-specific matter, dependent 
upon that contractor's actual scope of activities and responsibilities 
(which is typically a matter of private contract with the lessee/
operator), and is therefore not susceptible to general 
characterization. BSEE's responses to specific issues regarding 
responsibilities for compliance follow.
    Summary of comments: Some commenters asserted that if contractors 
and individuals (along with lessees, operators, et al.) are jointly and 
severally responsible for compliance, proposed Sec.  250.107(a)(4)--
requiring lessees, holders of operating rights, designated operators 
and certain others to comply with all lease, plan, and permit terms and 
conditions--would implicitly require contractors and other individuals 
to ascertain all lease, plan, and permit terms and conditions, and 
potentially would make the contractor and individuals responsible for 
compliance with all such terms and conditions. The commenters asked if 
that is what BSEE intended.
     Response: Under existing Sec.  250.146(c), the lessee, 
operator (if one has been designated), and the person actually 
performing an activity (including contractors or individuals) to which 
a particular regulation applies are jointly and severally (i.e., 
equally) responsible for complying with that regulation. Therefore, 
actual performance of an activity is one of the triggers for the 
responsibility to comply with the associated requirements of lease, 
permit and plan terms and conditions of approvals. (See, e.g., existing 
Sec.  250.101(a).) Accordingly, under final Sec.  250.107(a)(4), any 
person who actually performs an activity governed by a lease, permit or 
plan term or condition will also be responsible for compliance with 
that term or condition.
    BSEE expects the person performing such an activity to be familiar 
with all terms and conditions relevant and applicable to the activity. 
However, contractors and other parties actually performing specific 
activities are not responsible for complying with lease, permit or plan 
terms or conditions that are outside the scope of activities that they 
actually perform. Thus, it is not necessary for such persons 
(contractors or individuals) to be familiar with terms or conditions of 
the lease, permit or plan that are not associated with activities that 
they actually perform.
    Summary of comments: Some commenters asked whether, under proposed 
Sec.  250.107(e)--regarding BSEE orders to ensure compliance with the 
part 250 regulations--BSEE would issue orders to shut-in operations to 
the ``lessee, the owner or holder of operating rights, a designated 
operator or agent of the lessee(s)'' and any person actually performing 
the activity.
     Response: BSEE has the legal authority under OCSLA and its 
implementing regulations to issue shut-in orders to the lessee, 
operator (if one has been designated), and the person (which includes 
contractors) actually performing an activity to which a particular 
regulation, lease, permit, or plan applies. Regardless of whether BSEE 
orders a contractor to shut-in operations, BSEE will typically issue 
such an order to the lessee or designated operator in such cases.
    Summary of comments: Some commenters asked whether, under proposed 
Sec.  250.428(d)--which pertains to certain cementing and casing 
situations--reports to the District Manager of immediate actions taken 
to ensure the safety of the crew or to prevent a well-control event, 
create an obligation for contractors to provide individual reports or 
to verify that such reports have been submitted by the operator.
     Response: As a general matter, BSEE looks to the 
designated operator to make filings on behalf of all lessees and owners 
of operating rights. More

[[Page 25905]]

specifically, new Sec.  250.428(d) describes actions a lessee (among 
others included in the definition of ``you'' in Sec.  250.105) must 
take when remediating inadequate cement jobs. Because existing Sec.  
250.146(c) states that when a regulation requires that a lessee take an 
action, the person actually performing the activity is also responsible 
for complying with that requirement, it follows that the lessees' 
reporting duties under Sec.  250.428(d) for immediate action to 
remediate inadequate cement jobs could extend to a contractor to the 
extent that contractor actually performs the activity.
    Summary of comments: Some commenters asked BSEE to clarify who is 
ultimately responsible for the determination that a well has been 
secured, under proposed Sec.  250.703(c), which requires continuous 
surveillance of the rig floor from the beginning of operations until 
the well is completed or abandoned unless the well has been secured.
     Response: Under Sec.  250.146(c), the lessee, operator (if 
one has been designated), and the person actually performing the 
activity are jointly and severally responsible for complying with the 
regulation. If a contractor actually performs activities associated 
with securing a well, that contractor is responsible for complying with 
this regulation in performing those activities.
    Summary of comments: Some commenters asked if, under proposed Sec.  
250.712, which discusses rig movement reporting requirements, BSEE 
expects rig movement reports to be made directly by a drilling 
contractor and if the drilling contractor will be held responsible for 
the report in the absence of reporting by the operator.
     Response: Under existing Sec.  250.146(c) and final Sec.  
250.712, the lessee, operator (if one has been designated), and the 
person (including a contractor) actually performing the activity are 
jointly and severally responsible for complying with this rig movement 
reporting regulation. However, it does not follow that, even if a 
contractor actually moves the rig, the contractor must report the 
movement. When parties are jointly and severally responsible to comply 
with a requirement, any of the responsible parties could satisfy that 
requirement; in general, BSEE would expect the lessee or the operator 
to file such a report, although there may be circumstances in which it 
would be reasonable and prudent for the contractor who moved the rig to 
submit the report. In all cases, at least one of the responsible 
parties must fulfill the regulatory requirements.
    Summary of comments: Some commenters asked whether, under proposed 
Sec.  250.715(f)--which requires lessees, designated operators, holders 
of operating rights (and other entities specified in the Sec.  250.105 
definition of ``you'') to allow BSEE real-time access to MODU or jack-
up location data--BSEE expects that a drilling contractor will directly 
provide BSEE with access to rig location data, and whether the drilling 
contractor will be held responsible for providing such access only in 
the absence of any action by the operator.
     Response: Final Sec.  250.715(f) requires lessees, 
designated operators, holders of operating rights (and other entities 
specified in the existing Sec.  250.105 definition of ``you'') to allow 
BSEE real-time access to MODU or jack-up location data. Under existing 
Sec.  250.146(c) however, the lessee, operator (if one has been 
designated), and the person actually performing the activity (including 
a contractor) required by Sec.  250.715(f) are jointly and severally 
responsible for providing BSEE with access to rig location data.
    Summary of comments: A commenter asked whether, under proposed 
Sec.  250.720 (securing of wells), a contractor would bear a residual 
responsibility/liability for downhole integrity of the well or the 
effectiveness of the well plugs.
     Response: Final Sec.  250.720 specifies a number of well 
security procedures that must be followed before moving off the well. 
Some of those procedures are substantive and require physical activity 
(such as installing two independent barriers) and some are 
administrative (e.g., seeking approval by the BSEE District Manager for 
installation of independent barriers). In some cases, certain 
activities under Sec.  250.720 may be performed by a contractor or 
another person acting on behalf of the lessee or operator. In 
accordance with Sec.  250.146(c), the lessee, designated operator, and 
the person actually performing any activity related to securing a well 
under Sec.  250.720 are jointly and severally responsible for complying 
with the requirements of that section. It is not possible, however, to 
specify in advance how multi-party responsibility for compliance (and 
liability for noncompliance) with Sec.  250.720 would be apportioned 
among lessees, operators, or other persons (including contractors) who 
perform any of the actions required by Sec.  250.720 because 
responsibility would necessarily depend on fact-specific circumstances 
associated with each case. BSEE notes, however, that Sec.  250.720 does 
not expressly require the installation of plugs or address the issue of 
``residual responsibility'' for long-term integrity of the well; 
rather, it requires the installation of two independent barriers and 
approval by the District Manager of those barriers or of alternative 
procedures for securing the well if it is not possible to install the 
barriers.
    Summary of comments: Some commenters asked whether there is an 
implicit requirement under proposed Sec.  250.724, regarding RTM, for 
contractors or individuals who perform any of the actions required by 
Sec.  250.724 to: Maintain duplicate records; and ascertain if the 
required real-time data gathering, monitoring, recordkeeping and 
transmission are being undertaken by the operator and, if they are not, 
to suspend operations.
     Response: As discussed in part V.B.4 of this document, the 
final RTM requirements in Sec.  250.724 are somewhat different, based 
on other comments received, than the proposed requirements. However, 
although under existing Sec.  250.146(c) and final Sec.  250.724, the 
lessee, designated operator, and the person (including a contractor) 
actually performing the activity are jointly and severally responsible 
for complying with the final RTM requirements, neither the proposed nor 
final rule requires the contractor (or other person) to keep duplicate 
records. Nor does the final regulation require a contractor to 
determine whether a lessee or operator is otherwise gathering, 
recording, storing or transmitting required real-time data beyond the 
activities actually performed by the contractor or other person.
    Summary of comments: Under proposed Sec.  250.730(c)--regarding 
follow-up activities after a BOP equipment failure--a commenter 
asserted that a prudent drilling contractor would conduct such follow-
up, especially since API Standard 53 covers follow-up activities. The 
commenter claimed that incorporation of that standard in the rule would 
make the standard's follow-up requirements mandatory. However, the 
commenter questioned whether a contractor would have a regulatory 
obligation to perform those follow-up activities. The commenter also 
asked what, if any, regulatory obligations are created for equipment 
manufacturers.
     Response: To the extent that a drilling contractor 
actually performs any BOP equipment follow-up activity required by 
final Sec.  250.730(c), the contractor is jointly and severally 
responsible, along with the lessee and designated operator, for 
compliance with the specific requirement applicable to that activity. 
In particular, if the

[[Page 25906]]

contractor performs any of the reporting or notification required by 
Sec.  250.730(c), the contractor is responsible, along with the lessee 
and designated operator, for complying with the terms of the applicable 
requirement(s). If the contractor (or any other person) is not actually 
performing a required activity, but believes that a lessee, operator or 
other person may have failed to comply with any applicable requirement 
under BSEE's regulations, the contractor may report such noncompliance 
to BSEE in accordance with Sec.  250.193.
    Section 250.730(c) does not impose any requirements on OEMs.
    Summary of comments: With regard to the proposed recordkeeping 
requirements in proposed Sec. Sec.  250.740, 250.741, and 250.746, one 
commenter stated that, while a prudent drilling contractor presumably 
would maintain relevant records, such prudence differs from a 
regulatory obligation to do so. The commenter also asked whether BSEE's 
intends that these provisions create a regulatory requirement for 
contractors or individuals to maintain records duplicating those 
maintained by the operator.
     Response: To the degree that a contractor or any other 
person actually performs any of the recordkeeping activities required 
by Sec. Sec.  250.740, 250.741, and 250.746, that person is jointly and 
severally responsible, with the lessee and designated operator (if 
any), for complying with the applicable requirements, including record 
retention, imposed by those sections. Those provisions of the final 
rule do not, however, require that the lessee, designated operator, or 
the person performing the recordkeeping requirements maintain duplicate 
copies of the records kept by other jointly responsible parties.
6. Economic Analysis Comments
a. Analysis Period Used in the Initial Regulatory Impact Analysis (RIA)
    Summary of comments: BSEE received several comments suggesting that 
the analysis period used in the initial RIA \10\ for the proposed rule 
was insufficient to fully assess the impacts of the rule on OCS 
operations. Commenters noted, in particular, that offshore developments 
and equipment have lifecycles of 20 to 30 years, making the 10-year 
analysis period used in the initial RIA insufficient for estimating the 
costs and benefits of the rule.
---------------------------------------------------------------------------

    \10\ This document uses the terms ``initial RIA'' and ``initial 
economic analysis'' interchangeably. Both terms refer to the initial 
regulatory impact analysis performed for the proposed rule, as 
required by E.O. 12866, which is available in the regulatory docket 
for this rule at: www.regulations.gov (Enter BSEE-2015-0002).
---------------------------------------------------------------------------

     Response: BSEE determined that that the 10-year analysis 
period used in the initial RIA is appropriate to maintain reasonable 
certainty of the estimates, given the uncertainties that exist beyond 
10 years with regard to industry activities, technological change, and 
energy markets.
b. Issues Associated With the Economic Baseline
    Summary of comments: BSEE received several comments on the initial 
RIA indicating that some of the costs assumed to be part of the 
baseline (and, therefore, not considered costs of the rule) are 
actually related to activities that either are not covered by current 
industry standards or are not in accordance with existing regulations. 
Specifically, commenters referred to costs related to requirements for 
activity reporting and recordkeeping, BOP system testing, autoshear/
deadman/EDS systems, casing and cementing, maintenance and inspection, 
and redundant components for well control, among others, as examples of 
costs the analysis purportedly failed to consider because they were 
assumed to be part of the baseline.
     Response: BSEE established the baseline used in the 
initial (and the final) RIA in accordance with the guidance provided by 
Office of Management and Budget (OMB) Circular A-4 (``Regulatory 
Analysis''). This guidance states that the ``baseline should be a best 
assessment of the way the world would look absent the proposed 
action[,]'' i.e., without the implementation this final rule. (OMB 
Circular A-4 sec. E. 2. ``Developing a Baseline.'') Without this rule, 
BSEE's best assessment of the way the world would look includes 
compliance costs associated with current industry practices, existing 
regulations, DWOPs, NTLs, and industry standards. Therefore, based on 
the Circular A-4 guidance, BSEE has reasonably determined that the 
costs listed by the commenters are appropriately included in the 
baseline.
    In contrast, many of the comments appeared to assume that any cost 
associated with requirements of this regulation is a cost of the rule 
regardless of whether that cost is already incurred based on current 
standard industry practice, existing regulations, or other indicators 
of state of the world in the absence of this rule. This assumption is 
inconsistent with both OMB guidance and with the general principles 
upon which an RIA is based. Additional discussion of BSEE's development 
of the baseline scenario can be found in Section 4 and in Appendix A of 
the final RIA for this rule, which is available in the regulatory 
docket at www.regulations.gov (enter BSEE-2015-0002).
c. Costs Related to Equivalent Circulating Density Information
    Summary of comments: One comment on the initial RIA asserted that 
the requirement to include information on the ECD under proposed Sec.  
250.413 would take additional time by the drilling engineer and 
additional staff time to interface with BSEE personnel.
     Response: BSEE notes that this information is already 
included in the driller's report, which is an existing requirement, and 
thus there is no additional cost as a result of this requirement.
d. Costs Related to Wellhead Systems Information
    Summary of comments: One comment stated that the additional 
information to be provided on wellhead systems under proposed Sec.  
250.414(j) would require operators to include wellhead and liner hanger 
specifications in the APD, resulting in an additional cost to 
operators.
     Response: This information is readily available from the 
OEM, once the operator purchases the wellheads, so the additional cost 
to operators due to these requirements should be minimal.
e. Tubing and Wellhead Equipment Costs
    Summary of comments: Some comments asserted that BSEE failed to 
adequately consider costs associated with the requirements in proposed 
Sec. Sec.  250.518 and 250.619 for complying with industry standards 
for tubing and wellhead equipment.
     Response: BSEE notes that these costs are included in the 
baseline since the only requirements in these sections that impose any 
costs are those associated with meeting the existing industry standard 
(i.e., API spec. 11D1) for tubing and wellhead equipment that industry 
already follows.
f. Installation of Locking Devices
    Summary of comments: Some comments suggested that BSEE had not 
included the cost of requiring the installation of hydraulically 
operated locks on surface BOP systems, under proposed Sec.  250.733 
(now covered under final Sec.  250.735(g).)
     Response: Although the revised final rule will not require 
installation of hydraulically operated locks on surface BOP systems (as 
discussed in part VI.C),

[[Page 25907]]

BSEE agrees with the comment that the costs of installing hydraulic 
locks should have been included in the initial RIA. Under the revised 
final Sec.  250.735(g), operators are not require to install hydraulic 
locks on surface BOPs. Instead, operators must install remotely-
operated locks (which may but are not required to be hydraulic locks) 
on surface BOP blind shear rams and must install either manual or 
remotely-operated locks on surface BOP pipe rams or variable bore rams. 
Although not required to do so, operators may choose to comply with 
this revised requirement by installing hydraulic locks on some or all 
of these surface BOP sealing rams. Therefore, as one of the comments 
suggested, BSEE has added to the final economic analysis a one-time 
cost of $50,000 for each of the estimated 50 surface BOP rigs that 
could choose to install hydraulic locks this installation. Accordingly, 
the final RIA includes a one-time cost to industry of $2.5 million.
g. Capping Stack Test Costs
    Summary of comments: Some comments suggested that BSEE 
underestimated the costs of capping stack tests in the initial RIA.
     Response: BSEE analyzed these comments and agrees that the 
cost estimate should be revised upward. Using information provided in 
one of the comments, BSEE revised the cost estimate (to industry 
overall) from $80,000 per year to $226,000 per year.
h. Costs related to Safe Drilling Margins
    Summary of comments: Some comments suggested that the costs in the 
initial RIA should have included a higher cost for the requirement for 
safe drilling margins under proposed Sec.  250.414. The proposed 
requirement specified that the static mud hole weight must be at least 
0.5 ppg below the minimum of the lower of the estimated fracture 
gradient or the casing shoe pressure integrity test (the 0.5 ppg safe 
drilling margin).
     Response: This proposed requirement was revised in the 
final rule to allow for alternative drilling margins in situations 
where the operator provides justification and documentation in the APD 
that warrant variations, based on the specific well conditions, in 
order to maintain a level of safety equivalent to the 0.5 ppg 
requirement. Because the 0.5 ppg safe drilling margin is consistent 
with typical margins in approved APDs under current BSEE and industry 
practice, and the provision for approval of alternative margins is 
consistent with existing Sec.  250.141, the costs associated with 
complying with these safe drilling margin requirements (other than 
minor administrative and recordkeeping costs) are part of the baseline.
    Additionally, the commenters' estimated costs for complying with 
the proposed safe drilling margin requirements, based on the proposed 
language, would be significantly less under the final regulatory 
language, which provides operators with more flexibility to set lower 
drilling margins, upon providing adequate documentation with the APD 
submittal and receiving approval by BSEE.
i. RTM-Related Costs
    Summary of comments: BSEE received several comments suggesting that 
the costs associated with RTM requirements for well operations were 
underestimated in the initial RIA.
     Response: These comments tended to assume greater demands 
on the RTM systems (such as the exchange of more information through 
RTM than was necessary, or the mandatory creation of new RTM centers) 
than the proposed rule actually intended. Further, BSEE has clarified 
and modified several aspects of the RTM requirements, and made them 
more performance-based, in the final rule. Although the performance-
based requirements should make the RTM provisions less costly overall 
than the proposed requirements (since operators presumably will use the 
lowest cost means to achieve the performance goals), the final rule 
retains several of the proposed RTM requirements that were the basis of 
most of the RTM-related costs estimated in the initial RIA. (For 
example, the final rule still requires that operators gather and 
monitor RTM data, using an independent automated system, on the well's 
BOP control system, the fluid handling system, and downhole 
conditions.) After further review of its initial RIA, BSEE has 
concluded that the initial costs estimates for the proposed RTM 
requirements, as they were originally intended, are a reasonable and 
conservative upper bound on the potential costs of the final rule, and 
that the commenters' higher estimates were based on incorrect 
assumptions about the scope and intent of the proposed requirements. 
Accordingly, BSEE has retained the initial costs estimates for RTM in 
the final RIA. Further discussion of the cost estimates for the final 
RTM requirements are found in part VIII, ``Regulatory Planning and 
Review,'' and in the final RIA.
j. BAVO-Related Costs
    Summary of comments: New paragraph (a) in final Sec.  250.732 
requires any organizations that want to become a BAVO to submit certain 
information. Some comments suggested that this imposes additional 
paperwork costs on industry.
     Response: BSEE agrees and the final RIA estimates that 
these costs will result in an increase of approximately $10,000 
annually to industry, including BAVO applicants.
k. MIA Report Costs
    Summary of comments: BSEE received a comment that included a 
substantially higher estimate of the cost to operators for submitting 
the MIA Report to BSEE.
     Response: BSEE notes that the commenter incorrectly 
calculated this cost on a per-well basis, instead of on a per-rig 
basis, which is how the cost will actually be accrued. Accordingly, we 
have made no change to the initial RIA cost estimate, which is included 
in the final RIA.
l. Surface BOP Stacks and Drilling Risers Costs
    Summary of comments: BSEE received comments asserting that the 
estimated costs in the initial RIA associated with the dual bore 
drilling riser requirements for surface BOP stacks were incomplete. In 
particular, one comment asserted that the proposed requirement for dual 
bore risers would necessitate the replacement of several existing riser 
systems.
     Response: The dual bore riser requirements in final Sec.  
250.733(b)(2) are limited to facilities or BOPs that are installed 
after the effective date for those requirements. Thus, BSEE does not 
anticipate any additional replacement costs for current drilling 
risers.
m. Gas Bleed Line Requirement Costs
    Summary of comments: Some comments suggested that BSEE 
underestimated the cost of the requirement involving the installation 
of a gas bleed line under proposed Sec.  250.734(a)(15).
     Response: BSEE has revised this requirement in the final 
rule by clarifying that the gas bleed line must be installed below the 
upper annular (not below both annulars), and the final requirement thus 
costs less than the proposed requirement would have cost. Moreover, 
based on BSEE's most recent analysis, the vast majority of subsea BOPs 
already have a gas bleed line installed, and the ones that do not will 
require only very slight modification under the final rule. Thus, the 
final RIA estimates a lower cost of compliance for this provision of 
the final rule.

[[Page 25908]]

n. Costs of Accumulator System Requirements
    Summary of comments: BSEE received comments on the proposed 
accumulator system requirements in the proposed rule at Sec.  250.735, 
including estimates of industry costs to comply with these 
requirements. Many of the estimated costs in these comments exceeded 
the costs estimated by BSEE in the initial RIA.
     Response: The final regulatory text for this requirement 
has been changed to better align with API Standard 53, thereby reducing 
its cost to industry. The remaining costs to comply with this final 
requirement are now minimal, as described in the final RIA.
o. Costs Related To Testing of ROV Intervention Functions
    Summary of comments: BSEE received a comment that the testing of 
ROV intervention functions under proposed Sec.  250.737 would require 
additional operational time per well, thereby imposing an additional 
cost.
     Response: BSEE does not estimate that there will be any 
additional costs to operators in this regard since such testing is 
consistent with industry standards, and is thus within the baseline of 
the analysis.
p. Costs Related To Breakdown and Inspection of BOP System and 
Components
    Summary of comments: Several commenters asserted that the 
requirement in proposed Sec.  250.739 that operators break down the 
entire BOP system every 5 years for inspection, without the option to 
phase or stagger inspection, would cause rigs to be out of service for 
extended periods of time, at substantial opportunity costs to industry.
     Response: As described in detail in parts V.B.3 and VI.C 
of this document, BSEE has revised the requirement in Sec.  250.739 of 
the final rule to allow for phased inspections over the course of 5 
years. This change should eliminate the need for rigs to be brought out 
of service for extended periods of time, and thus reduces if not 
eliminates the opportunity costs of such inspections.
q. Indirect Economic Impacts of the Rule
    Summary of comments: Claimed indirect costs--Some comments 
suggested that BSEE should consider additional impacts of the rule. For 
example, several comments asserted that the analysis did not 
appropriately account for broader ``indirect'' economic costs (such as 
costs arising out of job losses associated with reduced exploratory 
drilling activities) that commenters asserted may occur as a result of 
the rule. One of these comments also provided an economic analysis of 
the broad effects of the rule on the national economy.
     Response: BSEE does not agree that what the commenter has 
described as ``indirect costs'' of the rule are within the scope of the 
RIA as required by E.O. 12866. OMB Circular A-4 characterizes the 
indirect effects of a rulemaking as ``ancillary benefits and 
countervailing risks,'' but also states that these types of forecasted 
consequences, if highly speculative, may not be worth further formal 
analysis. Because there are a number of important and variable factors 
(unrelated to the implementation of the new regulations), such as the 
future price of oil, that will impact both the offshore oil and gas 
labor market and the marketplace for offshore oil and gas equipment and 
products, BSEE believes it is too speculative to predict whether this 
rulemaking will have the types of broad and indirect effects discussed 
by the comments. In addition, the indirect impacts expressed by the 
comments appear to be overstated or based upon certain assumptions for 
which there is no clear foundation.\11\ Moreover, many of those 
estimated costs appear to be associated with requirements that are part 
of the economic baseline (e.g., compliance with relevant provisions of 
API Standard 53); while others are associated with requirements 
discussed in the proposed rule that are not included in the final rule 
(e.g., the proposed 1.5 times volume capacity accumulator requirement).
---------------------------------------------------------------------------

    \11\ For example, one comment assumed that the costs of the rule 
would lead to a 20 percent decrease in the number of floating units 
and over 30 percent decrease in fixed platforms, but provided no 
explanation for those assumptions.
---------------------------------------------------------------------------

    In addition, the commenters did not take into account the potential 
benefits to industry in terms of reduced costs of operation associated 
with implementation of the new regulations. For example, the reduction 
in costs attributable to the change in the BOP pressure testing 
frequency for workovers and decommissioning will exceed the costs that 
will result from the final rule.
    The commenters also did not account for the indirect benefits from 
the rulemaking that may accrue to entities other than offshore 
operators. For example, the requirements for new equipment and for use 
of BAVOs may result in an increase in the offshore labor force, which 
should result in overall economic benefits. Although such indirect 
benefits may also be speculative, and thus do not warrant further 
analysis under OMB Circular A-4, their absence from the commenters' 
estimates means that their estimates do not present a complete picture 
of all of the potential indirect effects.
    Summary of comments: Costs to Contractors--Several commenters 
asserted that BSEE did not adequately account for the additional costs 
to contractors that would result from the proposed rule.
     Response: BSEE disagrees with this comment because, in 
estimating costs, BSEE considered the costs of all of the equipment and 
labor services that would be needed to meet new requirements, 
regardless of how that equipment or labor is provided (whether by 
lessees, operators, or contractors).
    Summary of comments: Offshore support industries--Commenters also 
stated that BSEE overlooked potential negative impacts to industries 
that support offshore oil and gas exploration and development.
     Response: BSEE disagrees with this comment. The economic 
analysis included in the initial RIA considered the costs of all of the 
equipment and labor services that would be needed to meet the new 
requirements. Many of the negative impacts projected by the commenters 
are speculative and outside the scope of the type of analysis required 
to support this rulemaking. (For example, one comment stated that the 
rule was ``unworkable as written and could effectively shut-down 
drilling operations . . . similar to another drilling moratorium.'') In 
addition, some commenters projected additional costs to industries that 
support offshore oil and gas exploration and development, but did not 
address whether there are potential benefits to other types of 
industries resulting from the new requirements. Thus, even assuming 
they were within the scope of this analysis, these comments do not 
present a complete picture of the potential impacts on other 
industries.
r. Impacts of the Regulation on National Energy Security
    Summary of comments: BSEE received comments that the initial RIA 
did not account for the impacts of the proposed regulation on national 
energy security. These comments suggested that the rule would weaken 
national energy security by reducing domestic oil production and 
increasing reliance on foreign oil.
     Response: BSEE does not agree with this comment. The 
commenters' prediction about the weakening of national energy security 
is highly speculative and thus outside of the scope of the regulatory 
impact analysis

[[Page 25909]]

required by E.O. 12866 and OMB Circular A-4. For example, these 
comments apparently assume that this rulemaking will cause a reduction 
in domestic oil production over some period of time. As previously 
discussed, the net economic effect of the final rule on the oil and gas 
industry should be positive (i.e., the potential benefits exceed the 
potential costs), which does not support the assumption of a reduction 
in domestic oil production. Rather, future technological advancements 
and variable market factors (e.g., the price of oil) unrelated to the 
requirements of this final rule, are more likely to affect the future 
domestic oil production.
7. Clarification of Maximum Anticipated Surface Pressure (MASP)
    Summary of comments: Some commenters recommended that BSEE change 
the reference to MASP in specific sections throughout the rule (e.g., 
proposed Sec.  250.734(a), requiring that the working pressure rating 
of each BOP component exceed the applicable MASP) to ``maximum 
anticipated wellhead pressure'' (MAWHP). They asserted that there is no 
industry agreed-upon definition of MASP, but that MAWHP is defined in 
API Standard 53.
     Response: BSEE does not agree that the recommended change 
is necessary. The MASP must be identified for the specific operation, 
and for a subsea BOP, the MASP must be taken at the mudline, as 
explained in Sec.  250.730(a). As a practical matter, for surface BOPs, 
the MASP is the same as the MAWHP; and for subsea BOPs, the MASP, when 
taken at the mudline, as required by Sec.  250.730(a), is also the same 
as the MAWHP. BSEE does not agree that use of MASP will cause any 
confusion. BSEE's existing regulations (e.g., former Sec.  250.448(b)), 
have long used the term MASP, and BSEE does not believe that the 
industry will have any difficulty understanding the meaning and use of 
that term in this rule.

C. Section-By-Section Summary and Responses to Significant Comments on 
the Proposed Rule

    This summary discusses every section of 30 CFR part 250 covered by 
the proposed rule and this final rulemaking; sections of the existing 
regulations that were not addressed in the proposed or final rule are 
not included in this summary. BSEE did not receive any substantive 
comments on numerous sections covered by the proposed rule; those 
sections are included in this final rule and are summarized here. BSEE 
received substantive comments on many other sections covered by the 
proposed rule, some of which have been included in this final rule 
without revision and some of which have been revised in the final rule. 
Those sections, and the relevant comments on those sections as well as 
BSEE's responses are summarized here.

Subpart A--General

What does this part do? (Sec.  250.102)

    This section of the existing regulation provides information on 
where to find information about various OCS operations in 30 CFR part 
250. BSEE proposed to add new information to this section so the public 
will know where they can find requirements for well operations and 
equipment in new subpart G. BSEE received no substantive comments on 
this provision of the proposed rule and has included the proposed 
language in the final rule without change.

What must I do to protect health, safety, property, and the 
environment? (Sec.  250.107)

    This section of the existing regulation lays out performance-based 
and other requirement that operators must meet to protect safety, 
health, property and the environment and requires the use of BAST 
whenever practical. BSEE proposed several revisions to this existing 
regulation. BSEE proposed to revise paragraph (a) of this section to 
include performance-based requirements that operators utilize 
recognized engineering practices that reduce risks to the lowest level 
practicable during activities covered by the regulations and conduct 
all activities pursuant to the applicable lease, plan, or permit terms 
or conditions of approval. BSEE also proposed adding new paragraph (e) 
to clarify BSEE's authority to issue orders when necessary to protect 
health, safety, property, or the environment. BSEE received several 
comments on the proposed changes and additions to this section but, for 
the following reasons, has included the proposed language in the final 
rule without change.

Comments Related to Proposed Sec.  250.107--Suggested Standards for 
Incorporation

    Summary of comments: Commenters expressed several concerns about 
this section. One commenter focused on the performance-based intent of 
this section. The commenter recommended that BSEE incorporate by 
reference established and well known standards (International 
Electrotechnical Commission (IEC) 61508 and 61511)) to support the 
provisions. The commenter suggested that these standards, which are for 
developing safety instrument systems, including programmable systems 
(i.e., software), to a target level of reliability, could be adapted to 
support the rule. The commenter suggested that the methodology in IEC 
61508 and 61511 could be used to manage components and materials to 
ensure quality, so that reliability is not degraded and can be 
controlled via this process even if original parts are replaced by less 
expensive versions that have the same specification.
     Response: The international electrical standards referred 
to by the commenter (which apply broadly to electrical and electronic 
systems used to carry out safety functions and are not specifically 
related to well control systems) were not proposed for incorporation in 
the proposed rule and are outside the scope of this rulemaking. 
However, BSEE may evaluate those standards at a later date and, if BSEE 
determines that it is reasonable and appropriate to incorporate some 
parts or all of those standards, BSEE may propose to do so in another 
rulemaking.

Comments Related to Proposed Sec.  250.107(a)--Definition of ``You''

    Summary of comments: Some commenters asserted that proposed Sec.  
250.107(a)(4)--requiring lessees, designated operators, and other 
persons specified in the existing definition of ``you'' in Sec.  
250.105, to comply with all lease, plan and permit terms and 
conditions--creates an implicit requirement for contractors or 
individuals performing specific activities subject to the regulations 
to ascertain all lease, plan, and permit terms and conditions.
     Response: As discussed in part VI.B.5 of this document, 
compliance with Sec.  250.107(a)(4) does not require a contractor or 
other individual performing specific activities required by the part 
250 regulations to be knowledgeable about every term in a lease, permit 
or plan if those terms are unrelated to the specific activities 
performed by the contractor. However, because existing Sec.  250.146(c) 
makes any person who actually performs an activity jointly and 
severally responsible for compliance with the applicable regulatory 
provision, such persons should be familiar with the terms and 
conditions of the lease, permit or plan that are relevant to that 
activity.

Comments Related to Proposed Sec.  250.107(a)(3)--Concerns Related to 
BAST

    Summary of comments: Multiple commenters asserted that the new

[[Page 25910]]

language in proposed Sec.  250.107(a)(3) would implicitly change the 
BAST provisions in former Sec.  250.107(c). In particular, multiple 
comments focused on the requirement in proposed Sec.  250.107(a)(3) 
that lessees, operators, and others defined as ``you'' by Sec.  250.105 
use ``recognized engineering practices'' to reduce risks to the lowest 
practicable level. These commenters noted that the term ``recognized 
engineering practices'' is not defined in the regulations and 
questioned what practices would be considered as ``recognized'' and 
where the recognized practices would be referenced. Commenters also 
questioned what would happen if arguably better engineering methods and 
practices are developed in the future, but are not yet generally 
``recognized'' by industry.
     Response: It is unclear why the commenter believed the new 
requirements proposed in Sec.  250.107(a)(3) would change the BAST 
provisions in Sec.  250.107(c). The commenter may have assumed that the 
new requirement would supersede or be inconsistent with the requirement 
to use BAST whenever practical. However, Sec.  250.107(a)(3) does not 
change the BAST requirement; in fact, the new requirement is intended 
to complement the BAST provision by establishing a risk-based goal (to 
reduce risks to the lowest practicable level), and a performance-based 
requirement that lessees/operators meet that goal by using recognized 
engineering practices, when conducting certain regulated activities 
(i.e., design, fabrication, installation, operation, inspection, 
repair, and maintenance). Such risk reduction and performance-based 
approaches are used in other provisions of this final rule and other 
BSEE regulations.
    Regarding the specific comments on ``recognized engineering 
practices,'' BSEE expects that those practices may be drawn, for 
example, from established codes, industry standards, published peer-
reviewed technical reports or industry recommended practices, and 
similar documents applicable to relevant engineering activities. BSEE 
may issue additional guidance on such issues in the future, when and if 
specific circumstances warrant such guidance.

Comments Related to Proposed Sec.  250.107(a)(3)--Suggestions for 
Alternative Approaches To Reducing Risks

    Summary of comments: One commenter commended BSEE for proposing the 
general performance-based requirement in Sec.  250.107(a)(3) to reduce 
risks to their lowest practicable levels. The commenter noted that 
regulators can play a role in defining and challenging companies' risk 
control measures, and that this active engagement with industry drives 
down risk. The commenter also asserted that many of the other 
requirements in the proposed rule are overly prescriptive. The 
commenter suggested that prescriptive requirements can lead to safety 
plateaus, instead of continual improvements, and that some of the 
standards referenced in the proposed rule may not always reflect 
current industry best practices and, thus, would not encourage 
innovation. The commenter stated that it would be better for BSEE's 
regulations to include provisions that adapt in real-time to industry 
best practices and innovations.
     Response: BSEE agrees with the commenter's suggestion that 
it is often appropriate to use performance-based requirements that set 
safety and environmental protection goals and encourage innovation and 
continual improvement in meeting those goals, and that new Sec.  
250.107(a)(3) is such a requirement. In addition, numerous other 
provisions in this final rule are also performance-based. As to the 
commenter's suggestion that there may be additional opportunities to 
include more performance-based measures (presumably in lieu of 
prescriptive requirements) in this rule, the commenter provided no 
specific alternatives for BSEE to consider. In any event, as explained 
elsewhere in this document, the final rule revises several provisions 
of the proposed rule, as suggested by other commenters, to make them 
less prescriptive and more performance-based (e.g., the revised safe 
drilling margin provision in final Sec.  250.414(c)). On the whole, 
BSEE believes that this final rule effectively combines prescriptive 
and performance-based measures, as appropriate, to ensure and improve 
well control and to prevent harm to persons and the environment.

Comments Related to Proposed Sec.  250.107(e)--Concerns About BSEE-
Issued Orders

    Summary of comments: A commenter asked whether orders issued by 
BSEE under proposed Sec.  250.107(e) (e.g., to ensure compliance with 
30 CFR part 250 regulations, or to prevent serious, irreparable or 
immediate harm, or to stop violations of the law) would be issued to 
both the ``lessee, the owner or holder of operating rights, a 
designated operator or agent of the lessee(s)'' and to any person 
actually performing the activity. Another commenter stated that the 
orders described in proposed Sec.  250.107(e) are reactive methods for 
enforcing performance requirements, and that reactive methods are not 
enough to reduce risks to the lowest level.
     Response: Regarding the entities to whom BSEE may issue 
orders under new Sec.  250.107(e), it would be premature and 
speculative for BSEE to identify in advance all of the parties to whom 
any specific order may be issued. Orders will be issued on a case-by-
case basis as appropriate under the particular circumstances of each 
case. BSEE has legal authority to issue shut-in orders to lessees, 
operators (if designated) and any person (including contractors) who 
actually performs any activity to which a regulation or lease, plan or 
permit term applies. Whether or not BSEE orders a contractor to shut-in 
operations (suspension), BSEE typically also issues a corresponding 
order to the lessee or designated operator in these cases.
    BSEE agrees with the comment stating that orders issued under this 
section could, at least in some cases, be `reactive'' in nature, and 
that reactive measures alone may not be enough to reduce risks to the 
lowest level. However, any orders issued under Sec.  250.107(e) would 
be only one of many measures established by this final rule, most of 
which set performance goals or prescribe specific measures to be taken 
in advance of any harm, to improve safety and environmental protection. 
BSEE has determined that orders authorized by paragraph (e) are an 
appropriate complement to those other measures to ensure that the 
regulations, as a whole, achieve their protective purpose.

Service Fees (Sec.  250.125)

    The table in this section of the existing regulation lists fees 
that operators must pay to BSEE for certain services. BSEE proposed to 
revise this section to reflect the current citation for payment of the 
service fee relating to DWOPs. BSEE received no substantive comments on 
this provision of the proposed rule and has included the proposed 
language in the final rule without change.

Documents Incorporated by Reference (Sec.  250.198)

    This section of the existing regulation 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. This section also discusses BSEE's process for 
incorporating documents by reference, the regulatory

[[Page 25911]]

effects of incorporation, and procedures that operators may follow to 
seek BSEE's approval to comply with alternatives to an incorporated 
document. BSEE proposed revising this section to add references to the 
standards to be incorporated by reference in subpart G. BSEE received 
several comments on the proposed additions to Sec.  250.198. BSEE 
considered those comments and, for the following reasons, has retained 
the proposed language, without change, in the final rule.

Comments Related to Proposed Sec.  250.198--Technical Support Documents

    Summary of comments: A commenter requested that BSEE publish 
``technical support documents'' summarizing its work in reviewing each 
standard that it proposed to incorporate by reference in this rule, 
including a determination that each standard is BAST.
     Response: All of the documents proposed to be incorporated 
by reference in this rulemaking were and are available for public 
review. The National Technology Transfer and Advancement Act (NTTAA) of 
1995 (Pub. L. 104-113) requires that BSEE rely on voluntary consensus 
standards where practical, Public Law 104-113, section 12(d). BSEE 
reliance on these standards is principally achieved through 
incorporation by reference of industry standards into the bureau's 
regulations. It is unclear what ``technical support documents'' the 
commenter is referring to, but the NTTAA does not require an agency to 
publish its underlying deliberations on why it is appropriate to 
incorporate by reference a specific standard. BSEE has explained its 
reasons for incorporating the standards referenced in this rulemaking 
in both the proposed rule and this preamble.
    In addition, BSEE does not make a BAST determination in connection 
with the incorporation of industry standards. BSEE's authority under 
the NTTAA to incorporate industry standards into BSEE regulations is 
separate from the authority to require BAST under OCSLA. The NTTAA 
mandates that Federal agencies use technical standards developed or 
adopted by voluntary consensus standards bodies, as opposed to using 
government-unique standards, when practical. BSEE follows the 
requirements of the NTTAA and of OMB Circular A-119 when incorporating 
standards into the regulations. These are not tied to the BAST concepts 
derived from OCSLA or its implementing regulations.

Comments Related to Proposed Sec.  250.198--Concerns About the 
Incorporation of Earlier Editions of Standards

    Summary of comments: A number of commenters noted that some of the 
standards proposed for incorporation by reference in this rule do not 
reflect the current editions of those standards. Commenters requested 
that BSEE update those standards to the current editions when 
incorporated in the final rule. Commenters stated that the updated 
standards reflect the latest knowledge and experience of industry 
experts resulting from a collaborative review of the standards. They 
also stated that older editions of some standards are no longer 
available, and that incorporation of older editions may create 
confusion. Commenters suggested that, to resolve the issue of keeping 
incorporated standards up to date, BSEE should remove references to 
specific editions of the standards and add language to the regulations 
that refers to the ``most current edition'' of a standard.
     Response: BSEE recognizes the concern related to 
incorporating the most current edition of each standard. BSEE reviews 
all standards incorporated by reference to ensure they are appropriate 
and technically sound. BSEE can choose to keep a certain edition in the 
regulations even if there is an updated edition (e.g., if BSEE does not 
agree with the technical changes or options allowed in a newer edition 
of an industry standard). This is done on a case-by-case basis for each 
standard. The change to a new edition, or removal of a discontinued 
standard, is not automatic and requires rulemaking. (In some cases, 
BSEE may use a direct final rule to incorporate new editions of 
standards already incorporated, if the new edition meets the 
requirements of Sec.  250.198(a)(2)). BSEE is actively reviewing new 
editions of many standards, although newer editions are constantly in 
development.
    Moreover, BSEE is prohibited, under applicable rules governing 
incorporation by reference, from automatically incorporating future 
amendments to or editions of a standard. (See 1 CFR 51.2(f); 30 CFR 
250.198(a)(1).) However, operators may comply with a later edition of a 
standard incorporated in BSEE regulations if the operator demonstrates 
that compliance with the newer edition is at least as protective as the 
incorporated edition, and if BSEE approves the alternative compliance. 
(See 30 CFR 250.198(c).) Operators can also continue to use older 
standards, other than those incorporated by reference, if they can 
demonstrate an equivalent level of safety and environmental protection, 
pursuant to Sec.  250.141.

Comments Related to Proposed Sec.  250.198--Effective Dates of 
Standards

    Summary of comments: Other commenters requested that, for standards 
applicable to equipment requirements under this rule, BSEE add 
provisions that allow the operator to use the standard that was in 
effect at the date the specific equipment was manufactured. This would 
prevent existing equipment and facilities that were manufactured and 
accepted under previous standards from being rendered obsolete by 
regulations incorporating newer standards. One commenter noted that 
BSEE is taking that approach with another rulemaking; i.e., proposed 
updating of the edition of API Spec. 2C for offshore pedestal-mounted 
cranes currently incorporated in Sec.  250.108 (see 80 FR 34113 (June 
15, 2015)). Commenters specifically cited the need to apply this 
approach to four standards proposed for incorporation in this rule: 
ANSI/API Spec. 16A, ANSI/API Spec. 16C, API Spec. 16D, and API RP 17H. 
However, another commenter recommended that BSEE require operators with 
existing equipment to comply with the latest industry standards 
contained in API Standard 53.
     Response: BSEE has addressed comments regarding the 
applicability of this rule's equipment requirements to existing 
equipment and facilities (e.g., requests to ``grandfather'' in existing 
equipment and facilities) in part VI.B of this document. With respect 
to the suggestion that BSEE require compliance with the ``latest . . . 
standards'' referenced in API Standard 53, BSEE must follow the 
provisions of the NTTAA and the guidelines issued by the OMB in 
Circular No. A-119 for incorporation of voluntary consensus standards. 
Under Circular No. A-119, the date of issuance of the standard being 
incorporated must be included in the regulation. Similarly, existing 
Sec.  250.198(a)(1) requires that an incorporation by reference is 
limited to a specific edition of the incorporated document and does not 
include future revisions to that document. Thus, BSEE may not simply 
incorporate ``the latest edition'' of any standard, as suggested by the 
commenter. However, as previously explained, BSEE may approve 
compliance with a later (or an earlier) edition of an incorporated 
standard if an operator requests and justifies such an alternative 
under Sec.  250.198(c) or Sec.  250.141.

[[Page 25912]]

    For the same reason, BSEE does not agree with the commenters' 
suggestion that the rules allow an operator to use equipment that meets 
whatever ``standard was in effect at the date the specific equipment 
was manufactured.'' Under the NTTAA and implementing regulations, any 
equipment standard that BSEE incorporates by reference must be 
identified by date and edition number. However, BSEE has addressed the 
``grandfathering'' issue for existing equipment in part VI.B.4 of this 
document. And, where applicable, BSEE may approve compliance with an 
earlier edition of an incorporated standard if an operator requests and 
justifies such an alternative under Sec.  250.198(c) or Sec.  250.141.

Comments Related to Proposed Sec.  250.198--Normative References

    Summary of comments: Several commenters suggested that BSEE should 
not directly incorporate normative references (second-tier documents) 
used in an incorporated standard (first-tier document), in particular, 
API Standard 53.\12\ Those commenters supported the incorporation of 
API Standard 53 in its entirety, and asserted that the normative 
references contained in that standard would also implicitly apply. One 
commenter also stated that separately incorporating the normative 
references within API Standard 53 would confuse the operators. However, 
other commenters suggested that concerns related to applying the 
edition of an equipment standard in existence at the time the equipment 
was manufactured (as previously discussed) would be minimized if the 
normative references in those standards were not incorporated by 
reference in BSEE's regulations.
---------------------------------------------------------------------------

    \12\ ``Normative references'' are typically other documents 
incorporated by reference within a standard that are considered 
necessary for compliance with specific parts of the ``first-tier'' 
standard.
---------------------------------------------------------------------------

    Commenters asked if it was BSEE's intent to require the application 
of the normative references in API Standard 53 for purposes other than 
their relation to the provisions of API Standard 53 to be incorporated 
in the final rule. If so, they requested that BSEE should specifically 
state those other purposes in the final rule.
     Response: BSEE recognizes that compliance with a normative 
reference in an incorporated standard is implicitly necessary at times 
to ensure actual compliance with an incorporated standard. However, 
BSEE has decided to expressly incorporate the normative references 
within API Standard 53 (i.e., relevant provisions of API Spec. 6A, API 
Spec. 16A, API Spec. 16C, API Spec. 16D, and API Spec. 17D), in the 
regulations (see final Sec.  250.732(a)(2)) so that it is clear when 
compliance with those documents is required. This is also consistent 
with guidance from the Office of the Federal Register (OFR) related to 
the incorporation of second-tier documents. (See 78FR 60,784, 60,794-95 
(Oct. 2, 2013).)

Comments Related to Proposed Sec.  250.198--Additional Standards 
Documents Suggested for Incorporation

    Summary of comments: Commenters suggested that in addition to 
updating the incorporation of API Spec. 6A, BSEE should also 
incorporate API Standard 6ACRA, First Edition, (June 2015) and API Spec 
6A718, First Edition (March 2004), for completeness.
     Response: BSEE agrees that certain documents are more 
effective if incorporated with other associated documents. However, we 
did not include the suggested documents in the proposed rule, and BSEE 
has not yet determined whether those standards should be incorporated 
in the regulations. We may consider these documents for incorporation 
in the future using the evaluation process previously described. If 
BSEE decides to incorporate these documents, we will do so through a 
separate rulemaking.

Comments Related to Proposed Sec.  250.198--Effective Dates of 
Documents

    Summary of Comments: A commenter requested that we remove the 
effective dates from the citations of standards in Sec.  250.198. The 
commenter suggested that the effective dates are of the monogram 
licenses, not for general industry use of the documents, and including 
the effective dates in the regulations could cause confusion. A 
commenter recommended that BSEE use the descriptions shown in the API 
Publications Catalog, which only include the standard number, title, 
publication date, and any errata/addenda.
     Response: BSEE disagrees. As previously stated, BSEE is 
required to include certain information from the standard, including 
the dates and editions of the incorporated documents, when 
incorporating documents by reference. (See Sec.  250.198(a)(1); 1 CFR 
51.9(b)(2).)

Comments Related to Proposed Sec.  250.198--Availability of 
Incorporated Standards

    Summary of comments: Two commenters asserted that BSEE acted 
illegally by not providing free, unrestricted, and online access to the 
standards incorporated by reference in the proposed rulemaking. The 
commenters asserted that BSEE had failed to make the incorporated 
materials reasonably available to the public, to discuss in the 
proposed rule preamble how it worked to make those materials reasonably 
available to interested parties, and to summarize in the preamble the 
material it proposed to incorporate, and thus that BSEE had violated 
the OFR regulations at 1 CFR 51.5(a). The commenters further asserted 
that, by failing to provide access to the incorporated standards, the 
proposed rule violated the APA because the proposed rule did not 
include ``either the terms or substance of the proposed rule or a 
description of the subjects or issues involved.'' (See 5 U.S.C. 
553(a).) The commenters recommended that BSEE re-publish the proposed 
rule, with the standards available freely online.
    The commenters also asserted various technical obstacles to 
purchasing the standards (both for print and online) from API and to 
viewing them in person at BSEE's offices. The commenters also raised 
numerous objections to the manner in which API presents the documents 
online, including technical hurdles for visually impaired people to 
view the standards online. The commenters also asserted that BSEE is in 
violation of the Rehabilitation Act of 1973 because visually impaired 
individuals are not able to view the standards properly on API's Web 
site. They also asserted that there is no guarantee by BSEE that the 
currently free online access for viewing the standards on API's Web 
site will last. Another commenter requested that, if BSEE cannot make 
the documents available to the general public, BSEE should, at a 
minimum, grant access to certain types of organizations (e.g., local 
governments).
     Response: These comments do not address the substantive 
merits of the proposed rule. Rather, the comments principally focus on 
legal criteria relevant to BSEE's incorporation by reference of various 
industry standards.
    Many of the detailed assertions in the comments (e.g., complaints 
about API's Web site advertisements) are outside the scope of this 
rulemaking as well as unrelated to BSEE's compliance with applicable 
regulations for incorporating documents by reference, and thus do not 
require any further response.
    In determining which industry standards to incorporate by reference 
into its regulations, BSEE has carefully evaluated potentially relevant 
standards, considered input from

[[Page 25913]]

various interested stakeholders, and proposed for incorporation those 
standards that BSEE determined, in its judgment, would reasonably serve 
the safety and environmental protection purposes of its regulations. In 
developing this final rule, BSEE also considered public comments on the 
proposed rule regarding which standards would best serve those 
purposes, as discussed elsewhere in this document. In doing so, BSEE 
has also complied with the mandate of the NTTAA (previously discussed) 
to make use, where appropriate and practical, of existing consensus 
standards in lieu of developing new government regulatory standards.
    Moreover, BSEE disagrees with the commenters' claims that BSEE 
failed to discuss the actions it took to ensure that the materials 
incorporated in these rules were, and will be, reasonably available or 
to actually make the materials reasonably available. In proposing 
certain standards for incorporation in the final rule, and finalizing 
such incorporations in this final rule, BSEE has followed the 
requirements and procedures for incorporation by reference set out in 
OFR's regulations. (See 1 CFR part 51.)
    In order to be eligible for incorporation by reference, a document 
must be ``reasonably available'' to affected persons (1 CFR 51.5, 
51.7(a)(3)) and the notice of proposed rulemaking must discuss how the 
incorporated document is reasonably available to interested parties or 
how the agency worked to make those documents reasonably available. 
(See id. at Sec.  51.5(a)(1).) The notice of final rulemaking must also 
discuss the ways that the incorporated document is reasonably available 
to, and how it can be obtained by, interested parties. (See id. at 
Sec.  51.5(b)(2).)
    The primary regulated community for these regulations is the 
offshore oil and gas industry, for which the costs for purchasing a 
copy of the industry standards (if they choose to do so) incorporated 
by reference in this final rule are not unreasonable. For other members 
of the public (including other government entities), BSEE discussed in 
the preamble to the proposed rule (see 80 FR 21506), and in this 
document (under ``Availability of Incorporated Documents for Public 
Viewing''), the reasonable methods by which the standards incorporated 
here may be reviewed, inspected, copied, or purchased.
    In brief, BSEE explained in both documents how any member of the 
public may review the referenced standards for free on API's Web site 
or in person at BSEE's offices in Sterling, VA, or at NARA's offices in 
Washington, DC. These actions are consistent with BSEE's prior 
rulemakings incorporating many other standards in the part 250 
regulations. Moreover, BSEE received informal approval from OFR for the 
proposed incorporations by reference in the proposed rule, and formal 
approval for the final incorporations in this final rule, in accordance 
with OFR's regulations (1 CFR 51.3 and 51.5), which include the 
requirement for making the documents reasonably available.
    Similarly, we disagree with the commenters' claim that the proposed 
rule violated the APA by failing to adequately describe the materials 
proposed for incorporation. To the contrary, the proposed rule 
adequately described the referenced standards (see 80 FR 21506-21508), 
as does this document. In addition, OFR's informal approval of the 
proposed incorporations, and its formal approval of the incorporations 
in this final rule, means that OFR agrees that BSEE has met the 
requirement in the OFR regulations for describing the incorporated 
materials. (See 1 CFR 51.5(a)(2) and (b)(3).)
    In addition, contrary to commenters' claims that BSEE must provide 
free, downloadable copies of the standards on its Web site, 
notwithstanding API's copyright claims to those standards, OFR has 
expressly concluded that an agency's incorporation by reference of 
copyrighted material does not result in the loss of that copyright.\13\ 
OFR reached this conclusion based in part on its analysis of the 
decision in Veeck v. Southern Building Code Congress International, 
Inc., 293 F.3d 791 (5th Cir. 2002). In the preamble to its recently 
promulgated amendments to the rules for incorporation by reference, OFR 
stated:
---------------------------------------------------------------------------

    \13\ Contrary to some commenters' claims, OFR's regulations also 
do not require BSEE to provide free, downloadable copies of the 
incorporated documents online, whether or not they are copyrighted. 
OFR expressly rejected that suggestion in its recent document 
promulgating the current regulations governing incorporation by 
reference. (See 79 FR 66267 (Nov. 7, 2014).)

that recent developments in Federal law, including the Veeck 
decision and the amendments to the Freedom of Information Act 
(FOIA), and the NTTAA have not eliminated the availability of 
copyright protection for privately developed codes and standards 
referenced in or incorporated into Federal regulations. Therefore, 
we agreed with commenters who said that when the Federal government 
references copyrighted works, those works should not lose their 
---------------------------------------------------------------------------
copyright.

(See 79 FR 66273.)

    Under the OFR regulations, BSEE is permitted to incorporate 
copyrighted materials into its regulations. Implicit within that 
permission is the fact that access to and presentation of certain 
incorporated standards is controlled principally by the third-party 
copyright holder. While BSEE works diligently to maximize the 
accessibility of incorporated documents, and offers direction to where 
the materials are reasonably available, it also must ultimately respect 
the publisher's copyright. Accordingly, issues related to how API 
structures its Web site or formats its copyrighted materials offered 
for free access are outside of BSEE's control and beyond the scope of 
this rulemaking.

Paperwork Reduction Act Statements--Information Collection (Sec.  
250.199)

    This section of the existing regulation provides the OMB control 
numbers associated with information collections under each subpart of 
part 250, and generally provides BSEE's reasons for collecting the 
information and explains how the information is used. BSEE proposed to 
revise this section by updating the OMB control numbers, by rewording 
some of the explanations for BSEE's information collections, and by 
adding references to proposed new information collections. After 
considering comments submitted on this section, BSEE has included the 
proposed language in the final rule without significant revisions. 
However, in response to certain comments, BSEE has revised the 
estimated burden hours for compliance with some of the information 
collections in the final rule, as explained in the following responses.

Comments Related to Sec.  250.199--General Requirements for Well 
Operations and Equipment

    Summary of comments: Several commenters raised concerns that 
additional time would be needed to account for requests for departures 
from operating requirements, as provided in Sec.  250.702, and for 
requests for approval to use new or alternative procedures or equipment 
during operations, as provided in Sec.  250.701. For example, some 
commenters asserted that the proposed requirement for use of subsea 
BOPs with ``dual-pod control systems'' and kelly valves will lead to 
requests for departures and for alternative procedures. The commenter 
explained that such requests would be likely because API Standard 53 
requires subsea stacks to ``have fully redundant control pods'' and 
because kelly valves are no longer in widespread use in offshore 
drilling operations.

[[Page 25914]]

     Response: As discussed later in this part of the document, 
we have revised the requirement for subsea BOPs with ``dual-pod control 
systems'' to require only a ``redundant pod control system.'' This 
change will align the pod requirement in the regulations with the 
language of API Standard 53. BSEE agrees with the comment about the 
limited availability of kelly valves and has revised final Sec.  
250.736(d)(1) by replacing the references to kelly valves with 
``applicable [k]elly-type valves'' as described in API Standard 53. 
Regardless, BSEE does not agree with the commenters' assertions 
regarding increased paperwork burdens. Ultimately, the requests for 
alternate procedures or equipment and requests for departures 
referenced in Sec. Sec.  250.701 and 250.702 are voluntary submissions 
made pursuant to longstanding regulations found at Sec. Sec.  250.141 
and 250.142, and thus do not reflect a new paperwork burden under this 
rule.

Comments Related to Sec.  250.199--APDs

    Summary of comments: Several comments requested that we include 
additional burden hours to prepare required permitting information. One 
commenter stated that the dual riser requirement in proposed Sec.  
250.733(b) may require additional engineering time to assure existing 
floating production facilities have the room to accept dual bore risers 
or dual shear ram BOPs. Another commenter stated that, to meet the 
requirements in Sec.  250.734(c) for drilling out the surface casing in 
a new well with a subsea BOP, additional burden hours would be needed 
to submit a revised APD, including the required third-party 
verifications, and to obtain BSEE's approval.
    One commenter stated that Sec.  250.418(g) of the proposed rule 
would likely require additional engineering time to develop a well 
abandonment plan that includes wash out or cement displacement to 
facilitate casing removal upon well abandonment. Another commenter 
stated that an additional man-day per individual well would be needed 
to provide a description of the source control and containment 
capabilities and receive APD approval pursuant to Sec.  250.462(c).
    We also received a comment requesting that we increase the 
estimated burden hours given that additional drilling prognosis 
information in the APD may be required by the District Manager under 
Sec.  250.414(k).
     Response: BSEE agrees with several of the commenters' 
assertions and has increased the burden estimate for preparing APDs and 
APMs to comply with this final rule as described in part VIII 
(Paperwork Reduction Act (PRA) of 1995).

Comments Related to Sec.  250.199--Tubing and Wellhead Equipment

    Summary of comments: One commenter asserted that it may not be 
possible to set a packer deep enough to have a column of kill weight 
fluid at the packer. As a result, additional engineering time would be 
required to comply with the Sec.  250.518(e) requirement for tubing and 
wellhead equipment for completion operations to determine if the casing 
design is suitable.
     Response: BSEE agrees with the comment and has increased 
the burden for APMs to account for the descriptions and calculations of 
packer depths required by this rule.

Comments Related to Sec.  250.199--Well Operations

    Summary of comments: We received numerous comments on the Sec.  
250.724(b) proposed RTM requirements. Commenters stated that such 
monitoring on all well operations, including shallow water shelf 
operations, would result in significant additions to the sensor, data 
integration, data telemetry band width, data reception and storage, and 
data monitoring and interpretation burden for all operators. They also 
expressed concern about how to comply with the new requirements to 
conduct continuous RTM of the BOP control system, the well's fluid 
handling systems on the rig, and the well's downhole conditions with 
the bottom hole assembly tools, and provisions for storage of the data.
     Response: BSEE agrees with the comment and has increased 
the burden hours to account for the development and implementation of 
an RTM plan, as required by the final rule, that includes all data 
required by Sec.  250.724.

Comments Related to Sec.  250.199--BOP System Requirements

    Summary of comments: We received comments claiming that additional 
engineering time would be necessary to comply with the requirements of 
Sec.  250.730(d). Since Sec.  250.730(d) requires that any BOP stack 
manufactured after the effective date of the regulation comply with API 
Spec. Q1, the commenter stated that additional burden hours will be 
needed to design a BOP stack that complies with API Spec. Q1.
    In addition, several commenters stated that there is an additional 
burden involved with submittals of an MIA Report as required by Sec.  
250.732(d) for a subsea BOP, a BOP used in an HPHT environment, or a 
surface BOP used on a floating facility. Specifically, they asserted 
that BSEE failed to account for the burden of obtaining BAVO 
certification of the MIA Report, as required by proposed Sec.  
250.731(f).
     Response: BSEE does not agree that any additional burden 
hours should be added for compliance with Sec.  250.730(d). That 
provision does not create any new information collection burdens since 
it requires compliance with existing industry standards, the costs of 
which are included in the economic baseline.
    However, BSEE has increased the burden hours for requesting 
approval to use new or alternative procedures, along with supporting 
documentation if applicable under Sec.  250.730, should an operator 
seek to deviate from the requirements of Sec.  250.730(d). BSEE has 
also increased the burden hours for complying with the Sec.  250.731(f) 
MIA Report certification requirement.

Subpart B--Plans and Information

What must the DWOP contain? (Sec.  250.292)

    This section of the existing regulation specifies information 
(e.g., description of the typical wellbore, structural design for each 
surface system) that must be included in a DWOP. BSEE proposed no 
changes to existing paragraphs (a) through (o) of Sec.  250.292, and 
the final rule makes no changes to those paragraphs. BSEE proposed to 
add a new paragraph (p) to this section and to redesignate existing 
paragraph (p) as paragraph (q). Proposed new paragraph (p) specified 
information that must be included in the DWOP if the operator proposes 
to use a pipeline FSHR meeting certain conditions. This information is 
used in planning for production development. BSEE received several 
comments on this proposed addition, and for the following reasons, has 
included proposed paragraph (p) in the final rule with one revision to 
the proposed language, as described in the following response and in 
part V.C of this document. Former paragraph (p) is also included in the 
final rule, without change, as new paragraph (q).

Comments Related to Sec.  250.292(p)--Pipeline Freestanding Hybrid 
Risers (FSHRs)

    Summary of comments: Commenters suggested that BSEE apply Sec.  
250.292(p) only to permanent FSHRs, and not to risers used for 
exploratory wells or for source control and containment. Those 
commenters noted that exploration wells are not covered under the 
existing DWOP regulations (Sec. Sec.  250.286 through

[[Page 25915]]

250.295), which apply to deepwater development projects, and that 
risers used for source control and containment are not part of a 
permanent installation.
     Response: BSEE agrees that this requirement applies only 
to permanent FSHRs for development projects under a DWOP. It is 
incorporated into a regulation setting forth requirements for the 
contents of a DWOP. Accordingly, it is inapplicable to operations that 
do not require a DWOP. BSEE would permit temporary FSHRs, such as those 
used with containment systems to respond to an emergency, on a case-by-
case basis. BSEE has revised this paragraph in the final rule to 
clarify that it applies only to FSHRs ``on a permanent installation.''

Subpart D--Oil and Gas Drilling Operations General Requirements (Sec.  
250.400)

    This section of the existing regulation was entitled ``Who is 
subject to the requirements of this subpart?'' BSEE proposed to revise, 
this entire section, including the section heading, to require that 
drilling operations be done in a safe manner to protect against harm or 
damage to life (including fish and other aquatic life), property, 
natural resources of the OCS (including any mineral deposits), the 
National security or defense, or the marine, coastal, or human 
environment. BSEE also proposed to clarify that, for drilling 
operations, the operator must follow the requirements of this subpart 
and the applicable requirements of proposed subpart G. BSEE received no 
substantive comments on this proposed provision and made no changes to 
the proposed language, which is now included in the final rule.

What must I do to keep wells under control? (Sec.  250.401)

    BSEE proposed to remove and reserve this section of the existing 
regulation and to move the content of this former section to proposed 
Sec.  250.703. BSEE received no comments on the proposed removal and 
reservation of this section and the final rule implements that action.

When and how must I secure a well? (Sec.  250.402)

    BSEE proposed to remove and reserve this section of the existing 
regulation and to move the content of this former section to proposed 
Sec.  250.720. BSEE received no comments on the proposed removal and 
reservation of this section and the final rule implements that action.

What drilling unit movements must I report? (Sec.  250.403)

    BSEE proposed to remove and reserve this section of the existing 
regulation and to move the content of this existing regulation to 
proposed Sec.  250.712. BSEE received no comments on the proposed 
removal and reservation of this section and the final rule implements 
that action.

What additional safety measures must I take when I conduct drilling 
operations on a platform that has producing wells or has other 
hydrocarbon flow? (Sec.  250.406)

    BSEE proposed to remove and reserve this section of the existing 
regulation and to move the content of this former section to proposed 
Sec.  250.723. BSEE received no comments on the proposed removal and 
reservation of this section and the final rule implements that action.

What information must I submit with my application? (Sec.  250.411)

    This section of the existing regulation specified certain 
information that must be included in an APD, including descriptions of 
``diverter and BOP systems.'' BSEE proposed to slightly revise this 
section to separate the requirements for diverter and BOP descriptions, 
and to updates the cross-reference in the section to include new 
subpart G. BSEE received no substantive comments on this provision of 
the proposed rule and made no changes to the proposed language, which 
is included in the final rule.

What must my description of well drilling design criteria address? 
(Sec.  250.413)

    This section of the existing regulation specifies the type of 
information that must be provided in the well drilling description 
portion of an APD. BSEE did not propose any changes to paragraphs (a) 
through (f) of the former Sec.  250.413, which are retained unchanged. 
BSEE proposed to revise former paragraph (g) to require that the 
maximum ECD be included on the pore pressure/fracture gradient plot in 
the APD. BSEE received multiple comments on the proposed changes to 
paragraph (g) and, for the following reasons, has decided to revise the 
proposed language to require that the ``planned safe drilling margin,'' 
instead of the ECD, be included on the pore pressure/fracture gradient 
plot under the final rule.

Comments Related to Proposed Sec.  250.413(g)--Well Drilling Design 
Criteria

    Summary of comments: Multiple commenters had concerns regarding the 
requirement in proposed Sec.  250.413(g) that well drilling design 
criteria include a plot showing maximum ECD. They stated that operators 
need to manage and adjust ECD during real-time operations, and thus no 
margin between ECD and fracture pressure or safety margin should be 
required to be specified in advance as part of the APD. The commenters 
also suggested that, since the intended use of the ECD cannot be 
specified in advance, it should be deleted from Sec.  250.413(g).
     Response: BSEE agrees with the commenters that, since ECD 
may need to be adjusted during operations, BSEE would need to provide 
more clarification about how to determine maximum ECD in order for 
operators to include it within the plots. Therefore, BSEE removed the 
reference to ECD from final Sec.  250.413(g) and inserted in its place 
a requirement to plot the planned safe drilling margin, as required to 
be included in the APD by final Sec.  250.414(c). This planned safe 
drilling margin is based in part on the planned ECD and thus will 
provide information essentially equivalent to what inclusion of the 
maximum ECD would have provided.

What must my drilling prognosis include? (Sec.  250.414)

    This section of the existing regulation describes the information 
that must be included in the drilling prognosis portion of an APD. BSEE 
did not propose any changes to paragraphs (a) and (b), and paragraphs 
(d) through (g), of the existing regulation and they have been retained 
unchanged. BSEE proposed to revise paragraphs (c), (h), and (i) of the 
existing regulation and to add new paragraphs (j) and (k) to Sec.  
250.414. Specifically, BSEE proposed: To revise paragraph (c) to better 
define the safe drilling margin requirements; clarify paragraphs (h) 
and (i) with minor wording changes; to add a new paragraph (j) 
requiring that the drilling prognosis include both the type of wellhead 
and liner hanger systems to be installed and a descriptive schematic; 
and to add a new paragraph (k) requiring submittal of any additional 
information required by the District Manager as needed to clarify or 
evaluate the drilling prognosis. BSEE received some comments on 
proposed paragraph (j), but has included that paragraph in the final 
rule without change. BSEE received many comments on the

[[Page 25916]]

proposed changes to paragraph (c) and on proposed paragraph (k). After 
considering the comments, and for the reasons stated in the following 
responses to those comments, BSEE has revised the language of proposed 
paragraphs (c) and (k) and included that revised language in the final 
rule.

Comments Related to Proposed Sec.  250.414(c)--Safe Drilling Margin

    Summary of comments: BSEE received extensive comments on the 
proposed requirements in Sec.  250.414(c) regarding safe drilling 
margins. The majority of these comments stated that the proposed 0.5 
ppg safe drilling margin would pose operational problems, reduce the 
safety of drilling operations, and lead to unintended consequences. 
Commenters provided examples of concerns, such as limiting the 
selection of drilling fluids; potentially requiring more casing strings 
or smaller production casing sizes; economic hardships due to not being 
able to reach reservoirs by setting more casing; decreased production 
from the smaller hole sizes; and undue burden of submittals for 
alternative compliance. Recommendations to revise proposed Sec.  
250.414(c) included performance of a risk assessment and calculations 
to establish safe drilling margins for each well and for each drilling 
interval within the well.
    BSEE also received comments on the proposed Sec.  250.414(c)(3) 
requirements related to the ECD. Some commenters interpreted this 
proposed language to mean that drilling must stop when any lost 
circulation occurs. Clarifying language was recommended as follows: 
``if lost circulation occurs, then the losses should be mitigated, and/
or ECD managed to reduce the effects of lost circulation as per API 
Bulletin 92L.''
    We also received a comment on the proposed requirements in Sec.  
250.414(c) for determining pore pressure and lowest estimated fracture 
gradients for specific intervals. The commenter emphasized that the 
purpose for this paragraph is to address planning (prognosis) for 
drilling operations and that it should not apply to the actual 
operations. The commenter recommended the following language: ``during 
planning for a specific interval, the relevant available offset hole 
behavior observations must be considered.''
     Response: BSEE agrees with a majority of the comments on 
Sec.  250.414(c) and has not included proposed paragraph (c)(3) in the 
final rule (and renumbered proposed paragraph (c)(4) as paragraph 
(c)(3) in the final rule). BSEE otherwise revised paragraph (c) in the 
final rule to require a planned safe drilling margin that is between 
the estimated pore pressure and the lesser of estimated fracture 
gradients or casing shoe pressure integrity test and based on a risk 
assessment consistent with expected well conditions and operations. 
Final paragraph (c) also requires that the safe drilling margin include 
use of equivalent downhole mud weight that is (i) greater than the 
estimated pore pressure, and (ii) except as provided in paragraph 
(c)(2), a minimum of 0.5 pound per gallon below the lower of the casing 
shoe pressure integrity test or the lowest estimated fracture gradient. 
Final paragraph (c)(2) now clarifies that, in lieu of meeting the 
criteria in paragraph (c)(1)(ii), operators may use an equivalent 
downhole mud weight as specified in the applicable APD, provided that 
the operators submits adequate documentation (such as risk modeling 
data, off-set well data, analog data, seismic data) to justify the 
alternative equivalent downhole mud weight. Finally, paragraph (c)(3) 
states that, when determining the pore pressure and lowest estimated 
fracture gradient for a specific interval, the operator must consider 
related off-set well behavior observations.
    Although 0.5 ppg is typically an appropriate safe drilling margin 
for normal drilling scenarios, BSEE understands there are circumstances 
where a lower drilling margin may be acceptable to drill a well safely. 
The revisions made in the final rule better define safe drilling 
margins, requiring the 0.5 ppg margin under most circumstances, but 
providing operators with the flexibility to use a lower safe drilling 
margin when appropriate.
    The changes in the final rule will alleviate, if not eliminate, 
much of industry's operational and economic concerns with the proposed 
0.5 ppg margin, including industry's concern that a 0.5 ppg drilling 
margin--with no exceptions--would effectively preclude the continued 
use of dynamic pressure drilling and inhibit development of new 
technology.
    By requiring justification for, and prior approval by BSEE of, any 
alternative to the 0.5 ppg margin, these revisions will provide BSEE 
with the information needed to make appropriate case-by-case decisions 
on specific drilling margins. BSEE could also use this option to 
identify and focus its resources on the potentially higher risk well 
sections where the safe drilling margin may be of greater concern. 
These revisions will increase planning flexibility for operators when 
drilling into areas that could require lower safe drilling margins, 
such as depleted sands or below salt (common occurrences in the GOMR). 
Industry will be able to determine and use (subject to BSEE approval) 
appropriate mud properties (density, viscosity, additives, etc.) best 
suited for a specific well interval based on drilling and geological 
parameters.
    The final rule also revised the proposed language to refer to 
``off-set well''--instead of ``hole''--conditions; the final rule 
language will better align the regulatory language with industry 
terminology and clarify BSEE's intent. For a more in-depth discussion 
of the changes to final Sec.  250.414(c), refer to part V.B.1 of this 
document.

Comments Related to Proposed Sec.  250.414(j)--Wellhead System and 
Liner Hanger System

    Summary of comments: BSEE received comments on the proposed Sec.  
250.414(j) requirements related to wellhead system and liner hanger 
system information. Commenters stated that operators will not have 
access to machine drawings for equipment purchased from manufacturers 
since this is considered proprietary data. A commenter recommended that 
the word ``descriptive'' be changed to ``detailed'' and that BSEE allow 
documentation that is available to the operator to be provided to BSEE.
     Response: BSEE disagrees with these comments and has made 
no changes to Sec.  250.414(j) in the final rule. BSEE is aware that 
operators typically receive schematics from the manufacturers, and 
those schematics are sufficient to meet the requirements for describing 
the wellhead and liner hanger systems. In addition, it is unclear from 
the comment why a change from ``descriptive'' to ``detailed'' would 
better classify the type of schematics available.

Comments Related to Proposed Sec.  250.414(k)--Additional Information

    Summary of comments: BSEE received comments on the proposed Sec.  
250.414(k) requirement to provide any additional information required 
by the District Manager. Commenters stated that this section should be 
restricted to necessary information that can be reasonably supplied by 
the operator. Commenters also suggested that the District Manager 
should provide justification to the operator for the requested 
additional information.
     Response: The District Manager may require additional 
information on the drilling prognosis on a case-by-case basis, based on 
unique site or well conditions. The District Managers would, of course, 
take into account the potential need for such information to

[[Page 25917]]

protect personnel or the environment, given the purposes of these 
regulations. Like many similar provisions throughout part 250, Sec.  
250.414(k) is intended to give District Managers the necessary 
flexibility and discretion to require information as needed in specific 
cases to fulfill the purposes of the regulation. Nonetheless, BSEE has 
slightly revised paragraph (k) in the final rule to confirm that the 
District Manager may require additional information needed to clarify 
or evaluate the drilling prognosis submitted under this section.

What must my casing and cementing programs include? (Sec.  250.415)

    This section of the existing regulation describes the information 
on casing and cementing programs that must be included in an APD. BSEE 
proposed no changes to paragraphs (b) through (f) of this section, 
which have been retained unchanged in the final rule. BSEE proposed to 
revise former paragraph (a) of this section to require casing 
information for all sections of each casing interval. BSEE proposed 
that operators must include bit depths (including measured and true 
vertical depth (TVD)) and locations of any installed rupture disks, and 
indicate either the collapse or burst ratings, in their APDs. Requiring 
this information for all sections for each casing interval will make 
well design calculations and APD submittals more accurate and provide a 
more complete representation of the well. BSEE received one comment on 
the proposed Sec.  250.415, and as discussed in the following response, 
has included proposed paragraph (a) in the final rule without change.

Comments Related to Proposed Sec.  250.415--Quality Assurance

    Summary of comments: One commenter suggested that we require a 
Quality Assurance/Quality Control (QA/QC) plan for cement installation 
and recommended that we add the QA/QC protocol to Sec.  250.415 and 
require it for each well.
     Response: Section 250.420(a)(6) of the existing 
regulations already requires the casing and cementing design to include 
a certification signed by a registered PE. This verification of the 
casing and cementing design by a PE provides the necessary QA/QC. We 
have, therefore, made no changes to final Sec.  250.415 based on the 
comment.

What must I include in the diverter description? (Sec.  250.416)

    This section of the existing regulation specified the information 
that must be included in the descriptions of diverter systems and BOP 
systems contained in an APD. BSEE proposed to revise this section by 
removing former paragraphs (c) through (f), which required certain 
information for BOP system descriptions, which BSEE proposed to move to 
new Sec. Sec.  250.703, 250.731 and 250.732, and by removing paragraph 
(g), which specified criteria for independent third-parties that verify 
certain BOP information. Under the proposed rule, Sec.  250.416 would 
include only the former language, in paragraphs (a) and (b), regarding 
diverter descriptions and would be re-titled accordingly. Based on 
comments submitted on the proposed changes to this section, as 
explained in the following response, BSEE has included former paragraph 
(a) in the final rule without change, as proposed. BSEE also included 
former paragraph (b) in the final rule, with one minor change to the 
former paragraph (b)(1).

Comments Related to Proposed Sec.  250.416--Descriptions of Diverter 
Systems

    Summary of comments: One commenter was concerned that proposed 
Sec.  250.416 did not actually require use of equipment and 
instrumentation to identify hydrocarbons that have travelled above the 
BOP and into the marine riser. The commenter stated that current rigs 
have zero riser instrumentation (for detecting/tracking hydrocarbons 
within the marine riser), and that they are equipped with a diverter 
system. The commenter suggested that we completely revise Sec.  
250.416(b) to require that diverters have riser instrumentation (such 
as ``distributed'' pressure gauges to measure differential pressures) 
that can confirm that the volume of gas does not exceed a certain limit 
and impose back[hyphen]pressure to keep gas from coming out of 
solution.
     Response: BSEE does not agree with the suggestion that we 
should transform proposed Sec.  250.416 from an informational provision 
(i.e., requiring a description of the diverter system) into a 
substantive equipment provision requiring specific instrumentation. 
Although BSEE agrees that there may be some potential benefits from the 
use of instrumentation on the riser, additional research and study 
needs to be done before BSEE could determine whether such a substantive 
requirement should be added to the regulations. If future research or 
study reports or other information becomes available to BSEE warranting 
this additional requirement, BSEE may propose revision of this section 
in a future rulemaking.

Comments Related to Proposed Sec.  250.416(b)(1)--Diverter Systems

    Summary of comments: Another commenter was concerned that proposed 
Sec.  250.416(b)(1) would require information in the APD about annular 
BOPs in diverter housings, even though not all diverters use annular 
elements. The commenter stated that some diverters use ``insert 
elements,'' which are not the same as annular BOPs, and recommended 
that BSEE replace ``annular BOP'' in proposed Sec.  250.416(b)(1) with 
``sealing element.''
     Response: BSEE agrees with the commenter that not all 
diverters use annular BOPs. Accordingly, BSEE has revised this section 
in the final rule by replacing ``annular BOP'' with ``element,'' which 
covers all of the different types of components (including annular BOPs 
and sealing elements) that may be installed in the diverter housing.

What must I provide if i plan to use a mobile offshore drilling unit 
(MODU)? (Sec.  250.417)

    BSEE proposed to remove and reserve this section and to move the 
content of this former section to proposed Sec.  250.713. BSEE received 
no comments on the proposed removal and reservation of this section and 
the final rule takes that action.

What additional information must I submit with my APD? (Sec.  250.418)

    This section of the existing regulation specified certain 
additional information (e.g., rated capacity of the drilling rig, 
drilling fluids program) that must be included in an APD. BSEE did not 
propose any changes to paragraphs (a) through (f) of the existing 
regulation, which are therefore retained unchanged. BSEE proposed to 
revise paragraph (g) of the existing regulation, which requires 
operators to seek approval for plans to wash out or displace cement to 
facilitate casing removal upon well abandonment, by adding a 
requirement to describe how far below the mudline the operator plans to 
displace cement and how the operator will visually monitor returns. 
This proposed change would provide information to assist BSEE in 
deciding whether to approve such plans. BSEE received no substantive 
comments on this proposed addition to paragraph (g), which is included 
in the final rule as proposed.

What well casing and cementing requirements must I meet? (Sec.  
250.420)

    This section of the existing regulation imposes specific 
requirements for casing and cementing of all wells. BSEE proposed to 
revise the introductory text

[[Page 25918]]

of this section, to re-designate former paragraph (a)(6) as paragraph 
(a)(7), and to insert a new paragraph (a)(6) that requires adequate 
centralization to help ensure proper cementation. BSEE also proposed to 
add a new paragraph (b)(4), requiring approval by the District Manager 
of changes to certain planned casing parameters, as well as a new 
paragraph (c)(2), requiring the use of a weighted fluid during 
displacement to maintain an overbalanced hydrostatic pressure during 
the cement setting time and thus enhance wellbore stability during 
cementing. BSEE received and considered comments on proposed paragraphs 
(a) and (c) and, as explained in the following responses, has included 
proposed paragraph (a) in the final rule without change. BSEE also 
included proposed paragraph (c) in the final rule, but revised proposed 
paragraph (c)(2) slightly in response to this section's summary of 
comments and responses.

Comments Related to Proposed Sec.  250.420(a)--Centralizers

    Summary of comments: One comment was submitted by multiple 
commenters on the proposed requirement in Sec.  250.420(a)(6) for use 
of centralization to ensure proper cementation. It stated that the 
proposed requirement needs to be changed to allow for methods other 
than centralizers to meet the cementing requirements of this section 
because there are instances where using centralizers will actually 
increase risk. The commenters provided examples of the need for 
centralization, including the inability to ream down casing and the 
likelihood of greater casing wear if the pipe is not centered. The 
commenters also provided examples, however, of why centralizers should 
not be the exclusive method for centralization, including the assertion 
that centralizers may increase the chance of pack-off, increase the 
number of connections in the casing string (because centralizer subs 
are often the only option for centralization), and damage the wellhead 
components (due to centralizer pass through). One commenter recommended 
the following alternative language: ``Provide adequate centralization 
and/or other methods to aid proper cementation to meet well design 
objectives within the constraints imposed by hydraulic, operational, 
logistical or well architecture limitations (ref. [API] Standard 65-2 
2nd Edition.)''
     Response: The commenter incorrectly assumes that Sec.  
250.420(a)(6) provides for the use of centralizers only. That provision 
does not specify or limit how centralization should be achieved. There 
are many options to ensure centralization besides the use of 
centralizers, and BSEE expects that multiple methods may be required to 
ensure adequate centralization. BSEE relies on industry best practices 
and industry standards to help determine suitable methods for 
centralization while cementing. BSEE also disagrees with the 
commenter's recommended inclusion of a reference to API Standard 65-2 
(2nd Edition), since a written description of how the operator 
evaluated the relevant practices is already required under Sec.  
250.415(f) (``What must my casing and cementing programs include?''). 
Therefore, no changes to proposed paragraph (a)(6) are necessary, and 
BSEE has included that paragraph in the final rule as proposed.

Comments Related to Proposed Sec.  250.420(c)--Cement Compressive 
Strength

    Summary of comments: One commenter suggested that BSEE increase the 
required compressive strength of cement (500 psi) under proposed Sec.  
250.420(c)(1) in order to reduce the risk of cement failure, especially 
in zones of critical cement where pressures and stresses are higher. 
The commenter also recommended adding a requirement for the cement 
mixture in the zone of critical cement to meet a 1,200 psi compressive 
standard within 72 hours.
     Response: BSEE disagrees and has retained the proposed 
language requiring 500 psi compressive cement strength, which is the 
same as the requirement in the former paragraph (c), in the final rule. 
This requirement is also consistent with the provisions in API RP 65 
part 2, already incorporated in the existing regulations, and with 
industry practice.

Comments Related to Proposed Sec.  250.420(c)(2)--Cementing

    Summary of comments: One comment was submitted by multiple 
commenters on the requirements in proposed Sec.  250.420(c)(2) for use 
of weighted fluids during cementing. The comment stated that the 
proposed casing and cementing requirements increase the risk of lost 
circulation, which will result in failure to achieve zonal isolation. 
The commenter suggested that, if Sec.  250.420(c)(2) refers to 
conditions at the center of the well, the language should be revised to 
provide: ``You must use a weighted fluid during displacement.''
     Response: BSEE agrees with the commenter and has revised 
Sec.  250.420(c)(2) in the final rule by clarifying that a weighted 
fluid must be used ``during displacement.'' This revision will help 
resolve the commenter's concerns about the weighted fluid being in the 
center of the well.

What are the casing and cementing requirements by type of casing 
string? (Sec.  250.421)

    This section of the existing regulation specifies casing and 
cementing requirements applicable to certain types of casing strings 
(e.g., drive or structural strings, conductor strings). BSEE did not 
propose any changes to paragraphs (a) and (c) through (e) of the 
existing regulation, which are therefore retained unchanged. BSEE 
proposed revising former paragraph (b), however, to specify that if 
oil, gas, or unexpected formation pressure is encountered, the operator 
must set conductor casing immediately, above the encountered zone, even 
if that is before the planned casing point. This proposed provision was 
intended to ensure that conductor casing is not placed across a 
hydrocarbon zone. BSEE also proposed to revise former paragraph (f) to 
eliminate the potential use of liners as conductor casing. This 
proposed revision would help ensure that the drive pipe is not exposed 
to wellbore pressures. BSEE received and considered comments on 
proposed paragraphs (b) and (f) and, as explained in the following 
responses, has retained proposed paragraph (b) in the final rule 
without change. However, the final rule revises the proposed language 
in paragraph (f) as discussed in the following responses and in part 
V.C of this document.

Comments Related to Proposed Sec.  250.421(b)--Conductors

    Summary of comments: Some comments on proposed Sec.  250.421(b) 
requested clarification as to whether the 22-inch and 20-inch casing 
used in deepwater operations is considered surface pipe and therefore 
subject to regulation under Sec.  250.421(c) (requirements for surface 
casing) rather than Sec.  250.421(b) (requirements for conductor 
casing). If BSEE agrees with that view, the commenter has no objection 
to proposed Sec.  250.421(b) with regard to 20- and 22-inch casing.
    A commenter also requested confirmation that drive pipe and jetted 
pipe are considered structural pipe and therefore are subject to 
regulation under former Sec.  250.421(a) (requirements for drive or 
structural casing) rather than the proposed Sec.  250.421(b). If BSEE 
agrees with that view, the commenter has no objection to proposed Sec.  
250.421(b) with regard to drive pipe and jetted pipe.

[[Page 25919]]

    One commenter suggested rewording the proposed revision to the 
existing requirement for setting casing immediately upon encountering 
oil, gas, or unexpected formation pressure before the planned casing 
point. The language of the proposed rule would require the casing to be 
set above the encountered zone. While the commenter did not object to 
the proposed revision, it suggested deleting the phrase ``before the 
planned casing point'' from the former and proposed regulatory text, 
and adding to the end of that provision the phrase ``even if it is 
before the planned casing point.''
    Another commenter suggested a change to a longstanding cementing 
requirement in existing (and proposed) Sec.  250.421(b) for 
verification of annular fill by observation of cement returns or, when 
observation is not possible, by using additional cement to ensure fill-
back to the mudline. The commenter indicated that, due to the long 
distances between the platform and the mud line at deepwater locations, 
excess hydrostatic cement pressure does not allow for a full column of 
cement to reach the platform level, making visual observation 
problematic. The commenter suggested that BSEE address this concern by 
allowing use of lift pressure calculations or ``tag and circulate'' to 
confirm visual evidence of cement location, and by adding language to 
the cementing provisions in Sec.  250.421(b) that would require 
operators to discuss the cement fill level with the District Manager 
when ``drilling in deeper water on fixed structures, where it may not 
be feasible to observe cement return.''
     Response: BSEE agrees that 20- and 22-inch casing may be 
considered surface pipe and, thus, subject to Sec.  250.421(c). BSEE 
also agrees that drive pipe and jetted pipe can be considered 
structural pipe and, thus, subject to Sec.  250.421(a). Accordingly, no 
change to the proposed language in paragraph (b) is necessary on those 
points.
    BSEE does not agree that the proposed conductor casing requirement 
for encounters with oil, gas or unexpected formation pressure that 
occur before the planned casing point should be reworded as suggested 
by the commenter. The casing requirements under former and proposed 
Sec.  250.421(b) state that if oil, gas or unexpected formation 
pressure is encountered before the planned casing point, casing must be 
set immediately; the only change proposed by BSEE to paragraph (b) was 
to clarify that, in such a case, the casing must be set above the 
encountered zone. BSEE does not believe that the commenter's suggested 
rephrasing would add any extra clarity or change the meaning of the 
proposed language in any useful way.
    Finally, BSEE did not propose any changes to the existing cementing 
requirements for conductors. As described previously, the proposed 
change to Sec.  250.421(b) clarifies the location where conductor 
casing must be set if the operator encounters oil or gas or unexpected 
formation pressure before the planned casing point; i.e., above the 
encountered zone. In any case, BSEE does not agree with the suggested 
revision to the cementing requirements with regard to deepwater 
drilling. Current cementing requirements, as reflected in former and 
proposed Sec.  250.421(b), already provide that if visual observation 
of cement returns from the annular is not possible, additional cement 
must be added to ensure cement returns to the mudline. To date, BSEE is 
unaware of any actual problems from applying that practice reflected in 
the regulation to fixed platforms drilling in deeper water; thus, there 
is no need to add the language suggested by the commenter. If any 
actual problems with that approach arise in the future, the operator 
should consult the District Manager regarding appropriate action and, 
if warranted, request approval of alternative procedures or equipment 
under Sec.  250.141.

Comments Related to Proposed Sec.  250.421(f)--Casing and Liners

    Summary of comments: With regard to proposed Sec.  250.421(f)--
revising existing casing requirements for liners by prohibiting use of 
liners as conductor casings--commenters raised concerns about how 
casing would be treated in deepwater riserless operations. One 
commenter suggested that the cementing requirements should apply to 
surface wellhead systems where structural casing extends back to the 
surface facility, and stated that conductor liner is an effective 
option for use as casing in mud line suspension completion systems. The 
commenter suggested that BSEE add the following text to Sec.  
250.421(f):

    A casing string whose top is above the mudline and that has been 
cemented back to the mudline will be not considered a liner. When 
conductor liner systems are needed in special applications, such as 
mud line suspension systems or drilling only applications, you must 
receive approval from the District Manager. You may not use a liner 
as conductor casing when surface wellhead systems are in use without 
mud line suspension systems and the structural casing extends back 
to the surface facility.

In support of the suggested change, the commenter stated that, for 
deepwater operations, this language would allow large outside diameter 
conductor hung in the supplemental wellhead adapter to be used as 
intended (i.e., as a conductor) without being considered a liner 
subject to the liner cementing requirements.

     Response: BSEE agrees with the commenter that when the 
casing string top is above the mudline and has been cemented back to 
the mudline, the casing string should not be considered a liner. 
Accordingly, to clarify this intent, BSEE has revised the casing 
requirements in final Sec.  250.421(f) to state that ``[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.'' BSEE also agrees 
with the commenter that a large outside diameter conductor hung in the 
supplemental wellhead adapter should not be considered a liner. No 
change to the language of paragraph (f) is necessary on this point.

Comments Related to Proposed Sec. Sec.  250.421(b) and (f)--
Centralizing Casing

    Summary of comments: One commenter supported the proposed new 
requirements in Sec. Sec.  250.421(b) and (f), but suggested that BSEE 
add more specific instruction on how to centralize casing (e.g., by 
specifying centralization requirements according to casing type). The 
commenter stated that if casing inside the well is not properly 
centralized, it will have thinner cement, or possibly no cement, where 
the pipe is near or in contact with the earthen wall. The commenter 
noted that thin areas of cement are easily cracked and damaged. The 
commenter noted further that cement that is not well-bonded to the 
outside of the casing or earthen hole, or that is damaged by subsequent 
well activities, creates a conduit for hydrocarbon movement, which 
increases the risk of losing well control. The commenter suggested 
that, at a minimum, surface casing should be centralized at the shoe 
and at every fourth casing joint and that intermediate and surface 
casing should be centralized at the base and top and at every tenth 
casing joint.
    The commenter also suggested that additional centralizers should be 
used in highly deviated well sections. This commenter also recommended 
that BSEE change the proposed regulation to require that: (a) The 
surface casing be set deep enough to provide a competent structure to 
support the BOP and to contain any formation pressures that may be 
encountered before the next

[[Page 25920]]

casing is run; (b) the entire surface casing annulus should be cemented 
to the surface (presumably the mudline); and (c) the surface casing 
must stop above any significant pressure zone or hydrocarbon zone to 
ensure the BOP can be installed prior to drilling into a pressure zone 
or into hydrocarbons.
     Response: BSEE agrees with the comment that requiring 
centralization will increase the probability of a successful and 
effective cement job. However, BSEE does not agree that centralization 
requirements should be included in Sec.  250.421, as suggested by the 
commenter. BSEE proposed, and Sec.  250.420(a)(6) of the final rule 
requires, adequate centralization (which does not mean the use of 
centralizers only) to ensure proper cementing programs. In addition, 
final Sec.  250.420(a)(7)--formerly Sec.  250.420(a)(6)--already 
requires that operators submit certifications signed by registered PEs 
that the casing and cementing design is appropriate and sufficient. 
These provisions will help ensure that casing is properly centralized. 
In addition, existing Sec.  250.415(f) requires that the cementing and 
casing programs included in the APD describe how the operator uses API 
Standard 65--part 2 to evaluate best practices, including best 
practices for centralizing casing. This also helps ensure that casing 
is properly centralized. Accordingly, BSEE did not propose any changes 
to the surface casing provisions under former Sec.  250.421 with 
respect to centralization, and no change to the former or proposed 
requirements are necessary on this point.

Comments Related to Proposed Sec.  250.421(f)--Liner Lap Length

    Summary of comments: A commenter did not agree with the requirement 
in proposed Sec.  250.421(f) to have a liner lap length specified for 
liners with liner top packers. The commenter stated that liner lap 
length requirements in production wells may adversely affect the 
ability to complete the well efficiently.
     Response: BSEE agrees with the commenter's intent and has 
revised the proposed cementing requirements for liners by adding 
language to final Sec.  250.421(f) stating that as provided by (d) and 
(e), if you have a liner lap and are unable to cement 500 feet above 
the previous shoe, you must submit and receive approval from the 
District Manager on a case-by-case basis. This revision provides 
additional flexibility to ensure that production wells are completed 
efficiently.

What are the requirements for casing and liner installation? (Sec.  
250.423)

    This section of the existing regulation was entitled ``What are the 
requirements for pressure testing casing?'' BSEE proposed to change the 
former title of this section to more accurately reflect proposed 
changes within the section that establish requirements for installing 
casings and liners. BSEE also proposed to revise paragraphs (a) through 
(c) of former Sec.  250.423 to clarify that liner latching mechanisms, 
if applicable, need to be engaged upon successfully installing and 
cementing the casing string or liner. These proposed revisions were 
intended to reinforce the importance of properly securing liners in 
place to ensure wellbore integrity. BSEE received and considered 
comments on the proposed revisions and the language in proposed 
paragraphs (a) and (b) has been revised as discussed in the following 
responses. Proposed paragraph (c), however, is included in the final 
rule without change.

Comments Related to Proposed Sec.  250.423(a) and (b)--Ensuring 
Lockdown Mechanism Is Engaged

    Summary of comments: One commenter recommended that the 
introductory sentence in proposed Sec.  250.423--regarding casing and 
liner installation--be changed in order to provide greater clarity for 
industry.
    Multiple commenters raised the concern that the language in 
proposed Sec.  250.423(a) and (b) does not define or explain how to 
measure success in ensuring that latching/locking mechanisms are 
engaged after ``successfully installing and cementing'' the casing 
string and liner, respectively. They stated that many systems do not 
have a way to ``ensure'' that the lockdown mechanism is properly 
engaged; all they can do is ensure that the proper procedures to set 
the lockdown mechanism are followed. The commenters recommended that 
BSEE remove the word ``successfully'' from Sec. Sec.  250.423(a) and 
(b) and say instead that, ``[y]ou must ensure that the latching 
mechanisms or lock down mechanisms are engaged upon installation of 
each casing string.''
     Response: BSEE does not agree that the suggested change to 
the introductory sentence in proposed Sec.  250.423 is necessary to 
avoid confusion. The commenter did not explain why that sentence is 
unclear or why the commenter's suggested change would make the language 
clearer. In fact, the introductory sentence in the proposed rule was 
exactly the same as the language in existing Sec.  250.423(b), and BSEE 
is unaware of any confusion regarding the meaning of that language. 
Accordingly, BSEE has not changed that sentence in the final rule.
    BSEE agrees with the suggestion that more guidance is needed in 
this section for operators to determine when casing strings and liners 
have been successfully installed and cemented. Therefore, we have 
revised proposed Sec.  250.423(a) and (b) in this final rule to include 
references to the cementing requirements of Sec.  250.428(c). In 
effect, the latching mechanisms or lock down mechanisms must be engaged 
upon successfully installing and cementing the liner. If the operator 
determines under Sec.  250.428(c) that the cement job is adequate 
(i.e., successful), then the latching/locking mechanisms should be 
engaged. If there are indications of an inadequate cement job, actions 
should be taken in accordance with Sec.  250.428 to ensure proper 
cementation before the latching or locking mechanisms are engaged.

Comments Related to Proposed Sec.  250.423(c)--Proper Casing or Liner 
Installation

    Summary of comments: One commenter suggested that BSEE add a new 
requirement to Sec.  250.423(c) for monitoring and verification of 
make-up and torqueing of casing and tubular connections. The commenter 
suggested the use of torque/turn evaluation equipment when installing 
production casing and tubing to confirm that thread mating has been 
performed according to applicable specifications.
     Response: BSEE does not agree that these suggested changes 
are necessary to ensure proper installation of casing and tubing. BSEE 
already requires a pressure test on the casing seal assembly under 
former Sec.  250.423(b)(3)--now Sec.  250.423(c)--and submittal to BSEE 
of both the test procedures and test results, in order to verify the 
integrity of the casing and connections. Therefore, no additional 
language is needed to help confirm casing integrity.

What are the requirements for prolonged drilling operations? (Sec.  
250.424)

    BSEE proposed to reserve and remove this section and to move the 
content of this former section to proposed Sec.  250.722. BSEE received 
no comments on the proposed removal and reservation of this section, 
and the final rule takes that action.

What are the requirements for pressure testing liners? (Sec.  250.425)

    BSEE proposed to reserve and remove this section and to move the 
content of

[[Page 25921]]

this former section to proposed Sec.  250.721. BSEE received no 
comments on the proposed removal and reservation of this section and 
the final rule takes that action.

What are the recordkeeping requirements for casing and liner pressure 
tests? (Sec.  250.426)

    BSEE proposed to reserve and remove this section and to move the 
content of this former section to proposed Sec.  250.746. BSEE received 
no comments on the proposed removal and reservation of this section, 
and the final rule takes that action.

What are the requirements for pressure integrity tests? (Sec.  250.427)

    This section of the existing regulation requires pressure integrity 
testing below the surface casing or liner and at certain drilling 
intervals. BSEE proposed to revise former paragraph (b) of this section 
to clarify that operators must maintain the safe drilling margins 
required by proposed Sec.  250.414. Although BSEE received and 
considered comments on this proposed requirement, the final rule 
includes this paragraph as proposed for the reasons discussed in the 
following responses.

Comments Related to Proposed Sec.  250.427(b)--Safe Drilling Margin

    Summary of comments: Multiple commenters raised the concern that 
changing the casing design for wells in order to maintain the safe 
drilling margins specified in proposed Sec.  250.414 could make some 
wells uneconomical, due to the need for smaller completions and thus, 
potentially uneconomical production rates.
    Although BSEE only proposed a minor change to existing Sec.  
250.427 (i.e., adding a cross-reference in paragraph (b) to the new 
safe drilling margin provisions in proposed Sec.  250.414), these same 
commenters also raised concerns with the existing requirement in Sec.  
250.427(b) that safe drilling margins must be maintained and that 
drilling must be suspended and the situation remedied when the drilling 
margins cannot be maintained. The commenters stated that suspending 
drilling to set pipe based on the proposed 0.5 ppg safe drilling 
margin--which they considered a legacy drilling margin from shallow 
shelf wells--would have severe negative consequences for many deepwater 
or depleted zone wells being drilled today and to be drilled in the 
future. In addition, the commenters claimed that maintaining the 
proposed 0.5 ppg safe drilling margin may require so many additional 
casing strings that it could hinder many deeper well designs in that 
they would no longer have the capability to run additional casing 
strings as needed to meet the applicable containment requirements. All 
commenters on this issue recommended that BSEE revise the second 
sentence in Sec.  250.427(b) to state that ``[w]hen you cannot maintain 
the safe margins, you must suspend drilling operations and remedy the 
situation in accordance with accepted industry practices as documented 
in API Bulletin 92L or as otherwise approved by the District Manager.'' 
Two of the commenters also suggested that BSEE require the operator to 
assess risk in addition to receiving District Manager approval for the 
remedial activity.
     Response: As discussed elsewhere in this document (see 
part V.B.1), based on other comments BSEE has revised the safe drilling 
margin requirements in final Sec.  250.414 to provide operators more 
flexibility in determining a proper safe drilling margin. The revisions 
to that section resolve most, if not all, of the concerns raised by the 
commenters in connection with proposed Sec.  250.427. In this final 
rule, BSEE is not specifying how the operator must remedy the situation 
when the safe drilling margin cannot be maintained. Accordingly, BSEE 
has not made the changes to proposed Sec.  250.427 requested by the 
commenters. However, BSEE will evaluate API Bulletin 92L and, if BSEE 
determines that it is appropriate to require application of that 
standard to remedial actions when safe drilling margins cannot be 
maintained, BSEE may propose incorporating that standard in the 
regulations in a separate rulemaking.

What must I do in certain cementing and casing situations? (Sec.  
250.428)

    This section of the existing regulation describes actions that must 
be taken when certain situations (e.g., unexpected formation pressures) 
are encountered during casing or cementing operations. BSEE did not 
propose changes to paragraph (a) or paragraphs (e) though (i). BSEE 
proposed to revise paragraph (b) of this section to require District 
Manager approval for proposed hole interval drilling depth changes 
(greater than 100 feet total vertical depth), and submittal of a 
certification that a PE has reviewed and approved the proposed changes. 
These proposed requirements were intended to assist BSEE in verifying 
the actual well conditions.
    BSEE also proposed to revise former paragraph (c), to clarify the 
requirements for actions that must be taken if there is an indication 
of an inadequate cement job, and former paragraph (d), clarifies that 
if the cement job is inadequate, the District Manager must approve all 
proposed remedial actions (except immediate action to ensure safety or 
to prevent a well-control event). In addition, BSEE proposed to add 
paragraph (k) (concerning the use of valves on drive pipes during 
cementing operations for the conductor casing, surface casing, or 
liner), to require certain actions to assist BSEE in assessing the 
structural integrity of the well. After consideration of comments on 
these proposed revisions, BSEE has included proposed paragraphs (b), 
(c), and (d) in the final rule without change. However, as discussed in 
the following responses, BSEE has revised the language of proposed 
paragraph (k) in the final rule.

Comments Related to Proposed Sec.  250.428(b)--Changing Casing Setting 
Depths or Hole Interval Drilling Depth

    Summary of comments: One commenter raised concerns that the 
proposed changes to existing Sec.  250.428(b), which specifies what 
operators must do when they need to change casing setting depths or 
hole interval drilling depths, would be too restrictive. The commenter 
asserted that if the requirement was limited to changes that exceed 300 
feet TVD--instead of 100 feet TVD as proposed--it would minimize 
unnecessary resubmittals of proposed changes to District Managers for 
approval and certifications of the proposed changes by PEs.
     Response: BSEE does not agree with this comment. Changing 
the requirement in Sec.  250.428(b) from 100 feet TVD to 300 feet TVD 
would adversely affect the source control and containment capabilities 
required by Sec.  250.462(a) since it could affect the performance and 
integrity of the well as designed and affect the determination of 
whether a full shut-in can be achieved. Accordingly, BSEE made no 
changes in the final rule to the proposed language of paragraph (b) in 
response to this comment.

Comments Related to Proposed Sec.  250.428(b) and (d)--PE Certification

    Summary of comments: Multiple commenters raised concerns with the 
requirement in proposed Sec.  250.428(b) and (d) that a PE certify that 
he or she has reviewed and approved proposed changes to casing setting 
depths as well as proposed changes to the well program to remedy an 
inadequate cement job. The commenters asserted that PE certification of 
proposed changes to casing setting depths should be required only if 
those changes would

[[Page 25922]]

affect the effectiveness of a barrier or if the change in the casing 
setting depth would lead to a significant change in the cementing 
program (e.g., exposure of an additional hydrocarbon zone).
    In case of an inadequate cement job, the commenters recommended 
that BSEE require that: (1) The operator submit a remedial action plan 
that includes immediate action and planned future action; (2) the 
District Manager approve the remedial action, unless immediate actions 
must be taken to ensure the safety of the crew or to prevent a 
well[hyphen]control event; (3) if the operator completes any unapproved 
immediate action to ensure the safety of the crew or to prevent a 
well[hyphen]control event, the operator must submit a description of 
the action to the District Manager when that action is complete; and 
(4) any changes to the well program (implicitly including casing or 
cement programs) that can impact the effectiveness of the barrier will 
require a certification by a PE that he or she reviewed and approved 
the proposed changes, and the changed well programs must meet any other 
requirements of the District Manager.
    One commenter also requested that BSEE clarify whether the PE 
certifications required by Sec.  250.428 refer only to changes to the 
casing design and primary cementing plans and not to proposed changes 
included in an APM. The commenter suggested revising the PE 
certification language in that paragraph to read: ``certifying that the 
PE reviewed and approved the revised casing and/or cement program.''
     Response: BSEE does not agree that any of the changes to 
proposed Sec.  250.428 suggested in these comments are necessary. BSEE 
does not agree that PE certifications for changes to casing setting 
depths should only be required when such changes would degrade barrier 
effectiveness. Changes to the casing setting depths could also affect 
the performance and integrity of the well as designed and 
determinations as to whether a full shut-in can be achieved. In 
addition, PE certification provides additional QA/QC and helps ensure 
that the actions are appropriate for the specific well. If an operator 
has any questions about what specific changes the PE must certify, the 
operator may contact the appropriate District Manager.
    BSEE agrees, however, with the commenter's request that we clarify 
that the PE certification requirements in proposed Sec.  250.428(b) and 
(d) apply only to the changes described in those paragraphs and not to 
other changes included in an APM. That is the correct interpretation of 
those provisions and no change to the proposed language of those 
paragraphs is necessary in the final rule.

Comments Related to Proposed Sec.  250.428(c)--Indications of 
Inadequate Cement Job

    Summary of comments: Several commenters recommended adding ``lift 
pressure analysis'' to the list of actions (i.e., temperature survey, 
cement evaluation log, or combination of both) as an alternative method 
to determine the adequacy of the cement job under proposed Sec.  
250.428(c)(1). The commenters stated that cement lift pressure analyses 
are an industry-recognized alternative to cement evaluation logs for 
determining the top of cement.
    Another commenter stated that the requirements in Sec.  250.428(c) 
should be revised so that when a casing shoe is not set in 
hydrocarbons, only a shoe test would be required to confirm that the 
cement job was successful. On the other hand, the commenter suggested 
that if hydrocarbons are present, a shoe test would not be enough to 
confirm cement job success, and a combination of other techniques 
(including lift pressure analysis, radioactive tracers, and/or cement 
bond logging) should be required to confirm job success.
    One commenter supported the proposed changes to Sec.  250.428, but 
recommended that the diagnostic tests should also be run for all 
offshore wells to verify adequate cement placement. The commenter also 
recommended that the proposed requirements in Sec.  250.428(d) for 
remedying inadequate cement jobs be strengthened to require a repeat 
cement evaluation log to verify that the cement repair was successful.
     Response: BSEE does not agree that the changes suggested 
by these comments are necessary. Lift pressure analysis and a shoe test 
by themselves are not conclusive indicators of an adequate cement job, 
and the additional techniques (i.e., temperature survey or cement 
evaluation log or a combination of both) in Sec.  250.428(c) may be 
necessary to assist in locating the top of the cement.
    With regard to the comment on strengthening the requirements for 
remedial actions in proposed Sec.  250.428(d), there is no need to 
specify that a repeat cement evaluation is necessary if there is any 
indication that the repair was inadequate. In such a case, Sec.  
250.428(c) would still apply, and the actions required by that 
paragraph, including a PE certification, must still be taken.
    BSEE also does not agree with the suggestion that Sec.  250.428(c) 
should apply to all wells, even if there is no indication of an 
inadequate cement job. When there is no indication of an inadequate 
cement job, the existing requirement to pressure test all casings and 
liners (formerly Sec.  250.423, redesignated as Sec.  250.721 in this 
final rule) provides a reasonable indication of a good cement job.

Comments Related to Proposed Sec.  250.428(d)--Immediate Action 
Reporting

    Summary of comments: Regarding the ``immediate action'' reporting 
requirement in Sec.  250.428(d), one commenter asked whether there is 
an obligation for contractors to provide individual reports or to 
verify that such reports have been submitted by the operator. Regarding 
the remedial action reporting, another commenter asked whether BSEE had 
any expectation that a drilling contractor would submit this report.
     Response: As a general matter, BSEE looks to the 
designated operator to make filings on behalf of all lessees and owners 
of operating rights. This issue is discussed in more detail in part 
VI.B.5 of this document.

Comments Related to Proposed Sec.  250.428(k)--Valves Used on the Drive 
Pipe

    Summary of comments: With regard to proposed Sec.  250.428(k)--
specifying what an operator must do when it plans to use a valve on the 
drive pipe during cementing for conductor or surface casings or for 
liners--one commenter suggested that the reference to use of a valve 
was too limiting. The commenter suggested changing the word ``valve'' 
to ``barrier.'' This would make the requirements in Sec.  250.428(k) 
applicable to pressure caps, stabs, or other barriers in addition to 
valves.
    The commenter also pointed out that for subsea wells, several 
valves are normally used, one for each port; therefore, the proposed 
rule should not use the singular word ``valve.'' The commenter also 
said that it is common practice to use a secondary barrier (such as a 
pressure cap) to supplement a valve (i.e., in case the valve leaks). 
Therefore, the commenter recommended that BSEE revise the proposed 
requirement that ``[y]our description [of the plan to use a valve] must 
include a schematic of the valve and height above the water line . . 
.'' to read: ``Your description must include a schematic of the primary 
and secondary barriers and height above mud-line. . . .''
     Response: BSEE agrees that changing ``valve'' to 
``valves'' in Sec.  250.428(k) is appropriate, and has

[[Page 25923]]

revised the final rule accordingly. However, BSEE does not agree that 
the other changes suggested by the commenters are necessary. In 
proposed, and now final, Sec.  250.428(k), the reference to valves is 
limited to valves used to verify visible cement returns, and thus it is 
expected that some cement will escape those valves. They do not serve 
the same purpose as other barriers.

What are the general requirements for BOP systems and system 
components? (Sec.  250.440)

    BSEE proposed to reserve and remove this section and to move the 
content of this former section to proposed Sec.  250.730. BSEE received 
no comments on the proposed removal and reservation of this section, 
and the final rule takes that action.

What are the requirements for a surface BOP stack? (Sec.  250.441)

    BSEE proposed to reserve and remove this section and to move the 
content of this former section to proposed Sec. Sec.  250.733 and 
250.735. BSEE received no comments on the proposed removal and 
reservation of this section and the final rule takes that action.

What are the requirements for a subsea BOP system? (Sec.  250.442)

    BSEE proposed to reserve and remove this section and to move the 
content of this former section to proposed Sec.  250.734. BSEE received 
no comments on the proposed removal and reservation, and the final rule 
takes that action.

What associated systems and related equipment must all BOP systems 
include? (Sec.  250.443)

    BSEE proposed to reserve and remove this section and to move the 
content of this former section to proposed Sec. Sec.  250.733, 250.734, 
and 250.735. BSEE received no comments on the proposed removal and 
reservation, and the final rule takes that action.

What are the choke manifold requirements? (Sec.  250.444)

    BSEE proposed to reserve and remove this section and to move the 
content of this former section to proposed Sec.  250.736. BSEE received 
no comments on the proposed removal and reservation of this section, 
and the final rule takes that action.

What are the requirements for kelly valves, inside BOPs, and drill-
string safety valves? (Sec.  250.445)

    BSEE proposed to reserve and remove this section and to move the 
content of this former section to proposed Sec.  250.736. BSEE received 
no comments on the proposed removal and reservation of this section, 
and the final rule takes that action.

What are the BOP maintenance and inspection requirements? (Sec.  
250.446)

    BSEE proposed to reserve and remove this section and to move the 
content of this former section to proposed Sec.  250.739. BSEE received 
no comments on the proposed removal and reservation of this section, 
and the final rule takes that action.

When must I pressure test the BOP system? (Sec.  250.447)

    BSEE proposed to reserve and remove this section and to move the 
content of this former section to proposed Sec.  250.737. BSEE received 
no comments on the proposed removal and reservation of this section, 
and the final rule takes that action.

What are the BOP pressure tests requirements? (Sec.  250.448)

    BSEE proposed to reserve and remove this section and to move the 
content of this former section to proposed Sec.  250.737. BSEE received 
no comments on the proposed removal and reservation of this section, 
and the final rule takes that action.

What additional BOP testing requirements must I meet? (Sec.  250.449)

    BSEE proposed to reserve and remove this section and to move the 
content of this former section to proposed Sec.  250.737. BSEE received 
no comments on the proposed removal and reservation of this section, 
and the final rule takes that action.

What are the recordkeeping requirements for BOP tests? (Sec.  250.450)

    BSEE proposed to reserve and remove this section and to move the 
content of this former section to proposed Sec.  250.746. BSEE received 
no comments on the proposed removal and reservation of this section, 
and the final rule takes that action.

What must I do in certain situations involving BOP equipment or 
systems? (Sec.  250.451)

    BSEE proposed to reserve and remove this section and to move the 
content of this former section to proposed Sec.  250.738. BSEE received 
no comments on the proposed removal and reservation of this section, 
and the final rule takes that action.

What safe practices must the drilling fluid program follow? (Sec.  
250.456)

    This section of the existing regulation specifies safe practices 
(e.g., proper conditioning of drilling fluid) that must be included in 
a drilling fluid program. BSEE proposed no significant changes to 
paragraphs (a) through (i) of the existing regulation. However, BSEE 
proposed removing paragraph (j) of the existing regulation, re-
designating former paragraph (k) as paragraph (j), and moving the 
content of former paragraph (j), which requires District Manager 
approval for displacing kill-weight fluid, to proposed Sec.  
250.720(b). This was intended to clarify that this requirement applies 
to all drilling, workover, completion, and abandonment operations. BSEE 
received no substantive comments on this provision of the proposed 
rule, and the final rule takes these actions.

What are the source control, containment, and collocated equipment 
requirements? (Sec.  250.462)

    This section of the existing regulation was entitled ``What are the 
requirements for well-control drills?'' BSEE proposed to re-title and 
completely revise this section, and to move the contents of former 
Sec.  250.462 to proposed Sec. Sec.  250.710 and 250.711. As proposed, 
Sec.  250.462 would require the operator to demonstrate the ability to 
control or contain a blowout event at the sea floor. Proposed paragraph 
(a) would require the operator to determine its source control and 
containment capabilities; proposed paragraph (b) would require that 
operators have access to, and the ability to deploy, source control and 
containment equipment (SCCE) necessary to regain control of the well; 
proposed paragraph (c) would require submittal of a description of the 
source control and containment capabilities before BSEE approves an 
APD; proposed paragraph (d) requires reevaluation by BSEE approval if 
certain events occur; and proposed paragraph (e) outlines maintenance, 
inspection, and testing requirements for specified containment 
equipment. After consideration of comments on the proposed section, and 
as explained in the following responses, BSEE has included paragraphs 
(a) through (d) in the final rule as proposed. BSEE has, however, 
revised the language of proposed paragraph (e) in the final rule.

Comments Related to Proposed Sec.  250.462--Introductory Paragraph

    Summary of comments: One commenter recommended that an ``alternate 
contingency plan'' be added

[[Page 25924]]

at the end of the introductory paragraph to Sec.  250.462 and also to 
the description of SCCE in Sec.  250.462(c)(1) and (c)(3). The 
commenter asserted that this would provide an equivalent seabed source 
control and containment alternative, and that the proposed rule does 
not promote the development of alternative technologies that may be 
more effective than traditional responses.
     Response: BSEE does not agree with this comment. Companies 
are free to design any type of equipment as long as they demonstrate it 
has the capability to respond to a loss of well-control situation. 
Therefore, no changes are needed to this proposed section in response 
to this comment.

Comments Related to Proposed Sec.  250.462(a)--Determining Source 
Control and Containment Capabilities

    Summary of comments: Several commenters suggested revising proposed 
Sec.  250.462(a)(2) to differentiate well designs that can be fully 
shut-in from those that can only be partially shut-in, and to require 
operators to ``verify,'' rather than to ``determine,'' that a full 
shut-in can be achieved. Some of these same commenters also recommended 
adding a new paragraph (a)(3) to require that an operator have the 
capability to: ``flow and capture the residual fluids to a subsea 
well.'' Commenters also suggested that the analyses required in 
proposed Sec.  250.462(a)(1) and (2) be bolstered by stating that the 
analyses should be performed using the most current version of the well 
containment screening tool. Commenters stated that the BSEE-endorsed 
well containment screening tool provides the necessary analysis; 
operators have used this tool for over four years and submit it with 
all affected APDs. Commenters suggest that this currently accepted 
practice should be acknowledged and codified.
     Response: BSEE disagrees with the suggestion that the rule 
should require use of the well containment screening tool. Although the 
rule does not require operators to use that tool, it is an acceptable 
tool to use for the analyses required in final Sec.  250.462(a)(1) and 
(2), and is typically included as a condition in APDs. Similarly, the 
other recommended changes to paragraph (a) are not necessary, since use 
of the well containment screening tool would lead to essentially the 
same results that the commenters' recommendations are intended to 
achieve.

Comments Related to Proposed Sec.  250.462(b)--SCCE

    Summary of comments: One commenter requested BSEE add subsea device 
connections or transition connections from one component to another to 
the equipment listed in Sec.  250.462(b) as SCCE. The commenter 
asserted that for industry to progressively address safety, efficiency, 
timeliness, certainty in methods and systems to contain and capture 
reservoir fluid, BOP connections and containment points should be 
considered as SCCE.
     Response: BSEE does not agree with the requested addition 
to proposed paragraph (b). The equipment requirement that the commenter 
recommends adding to this provision is already addressed in the APD and 
the well containment screening tool. BSEE will not approve an APD 
unless the operator ensures that it has the equipment needed. BSEE does 
not specify what equipment is to be used for a given scenario under 
final Sec.  250.462(b); that provision requires only that the equipment 
be accessible and capable of responding to an oil spill.
    Summary of comments: Some commenters requested other changes to 
proposed Sec.  250.462(b), asserting that SCCE requirements should be 
specific to each well and that cap and flow equipment should not be 
required for wells that are specifically designed for shut-in on a full 
hydrocarbon column. Among other things, the commenters requested that 
BSEE clarify that SCCE means the capping stack, cap and flow system, 
and ``(where applicable . . . , containment dome (i.e., localized, non-
pressurized, subsea fluids collection device),'' and that cap and flow 
systems (including containment domes) are not required for wells that 
are designed for shut-in on a full column of hydrocarbons.
     Response: BSEE does not agree that the requested changes 
are necessary. The initial screening of a well might indicate that it 
can be fully shut-in, but the operator should always have the equipment 
necessary and available if something happens that would change the 
outcome of the situation from a full shut-in to a cap and flow 
scenario. The initial screening presents a model outcome based on what 
is known at the time that the APD is submitted. BSEE realizes there is 
always the potential that, although the results of the initial 
screening indicate that the well could be controlled through a full 
shut-in (capping only), the well could actually require cap and flow if 
an actual loss of well control were to occur. BSEE wants to ensure that 
the operator is prepared for this situation and has all of the assets 
that may be needed available to respond to a loss of well control.

Comments Related to Proposed Sec.  250.462(c)--Description of Source 
Control and Containment Capabilities

    Summary of comments: Regarding proposed Sec.  250.462(c), 
commenters raised questions and recommended wording changes. Three 
commenters stated that industry already submits the required documents 
with each permit application (RP checklist) and suggested that the 
Regional Containment Demonstration (RCD), once approved, would satisfy 
the new requirements. Other commenters suggested retaining flexibility 
for containment capabilities (i.e., pre-installed capping device for 
spar and TLPs, in-situ burning and dispersants) and suggested that BSEE 
revise Sec.  250.462(c)(1) to allow an ``approved alternate contingency 
plan'' as an alternative to a description of containment capabilities 
for controlling and containing a blowout event at the seafloor. 
Commenters also suggested that BSEE change proposed Sec.  250.462(c)(3) 
to allow ``other approved contingency plan equipment'' as an 
alternative to information showing that the operator has access to and 
ability to deploy all equipment required by paragraph (b).
     Response: BSEE agrees that the RCD may indicate source 
control and containment capabilities, but operators should not assume 
that pre-installed containment equipment (i.e., pre-installed capping 
device) will work. This equipment is located on the rig and does not 
replace a capping stack, which is located elsewhere and can be used in 
the event that the equipment located on the rig fails. Therefore, BSEE 
requires operators to demonstrate that they are ready to respond with 
additional equipment (i.e., capping stack), if necessary. Moreover, 
subsea dispersant equipment are not considered source control or 
containment devices, but rather equipment that is collocated and 
deployed alongside SCCE operations. Accordingly, BSEE does not agree 
with the recommended changes to proposed Sec.  250.462(c).

Comments Related to Proposed Sec.  250.462(d)--Notification of BSEE

    Summary of comments: Some commenters requested a change to the 
requirements in proposed paragraph (d) to advise BSEE of any well 
design change and to suspend operations until the required out-of-
service SCCE is repaired or replaced. The commenters asserted that the 
proposed requirement to advise BSEE of any well design change will pose 
an undue burden on both the operator and BSEE. They also claimed that 
it is important to clarify

[[Page 25925]]

that only well design changes which negatively impact the results of 
the well containment screening tool require notification to BSEE. They 
also suggested that a risk-based approach should be adopted, that risk 
should be managed to the lowest possible level, and that if BSEE's 
regional representatives are not satisfied that the risk justifies 
continuing operations, then operations should be halted and the permit 
withdrawn. Therefore, the commenters suggested that BSEE revise 
proposed Sec.  250.462(d)(1) to set conditions on when BSEE should be 
advised of well design change; i.e., that BSEE should be advised only 
in the event of ``any changes in the well design or well conditions 
that require a revised permit to drill to be submitted and can impact 
the results of the well containment screening tool.''
    One commenter also recommended that, since proposed Sec.  
250.462(d)(2) would require the operator to contact the BSEE Regional 
Supervisor to reevaluate source control and containment capabilities if 
required SCCE is out of service, the operator should be required to 
secure the well and suspend drilling operations until the SCCE 
equipment is repaired or replaced and returned to full active service.
     Response: BSEE does not agree that any change to proposed 
paragraph (d) is warranted by these comments. BSEE will require 
notification if there are any well design changes. However, BSEE is not 
specifying the approach to be used for reevaluation of source control 
and containment capabilities; the well containment screening tool 
mentioned by the commenter would be acceptable in most circumstances. 
The notifications for the well design changes must be submitted at the 
time the operator submits a revised permit. BSEE will evaluate, on a 
case-by-case basis, whether there is adequate equipment available if 
the SCCE is out of service, and will then determine if the operator 
needs to suspend drilling operations.

Comments Related to Proposed Sec.  250.462(e)--Maintaining, Testing, 
and Inspecting SCCE

    Summary of comments: BSEE received several comments on the cap and 
flow requirements in proposed Sec.  250.462(e). In general, the 
comments stated that it is not necessary to have ``cap and flow'' 
capacity if a capping stack is capable of achieving a complete shut-in 
of the well. The commenters also stated that if an operator's 
evaluation, using the BSEE-endorsed well containment screening tool, 
indicates that a wellbore can be completely shut-in while maintaining 
full integrity, then cap-and-flow well design and equipment should not 
be required for the permit. The commenters suggested, however, that the 
cap-and-flow well design and equipment should be required for permit 
approval if the well containment screening tool indicates loss of 
wellbore integrity when attempting a complete shut-in. Another comment 
concerning the maintenance, testing, and inspection of SCCE, as 
required in proposed Sec.  250.462(e), suggested that BSEE should use 
the API terminology of ``pressure containing,'' rather than the 
proposed ``pressure holding,'' to eliminate the possibility of 
misinterpretation. It was also suggested that BSEE consider referring 
to API RP 17W in paragraph (e) to provide more clarity regarding 
documentation, document retention, and reporting requirements in the 
proposed table of requirements.
     Response: Operators should always be ready to respond to a 
discharge or loss of well control requiring cap and flow response 
elements, even if the initial screening suggests that the wellbore can 
be fully shut-in. However, BSEE agrees that the terminology change 
suggested by the commenters (replacing ``pressure holding'' with 
``pressure containing'') will improve consistency with current industry 
usage and provides a better description of the purpose of the 
equipment. Accordingly, BSEE included that revision in final Sec.  
250.462(e).
    We do not agree, however, that API RP 17W should be incorporated in 
the final rule at this time. BSEE did not propose to incorporate that 
standard and, although we may consider this document for incorporation 
in the future, using the evaluation process previously described, if we 
decide it is appropriate to incorporate that standard, we will do so 
through a separate rulemaking.

Comments Related to Proposed Sec.  250.462(e)--Testing SCCE

    Summary of comments: Commenters provided specific comments on, and 
recommended revisions to, proposed Sec.  250.462(e), suggesting that 
BSEE develop alternative testing methods and frequencies that will 
provide an equivalent or greater degree of verification. Some comments 
also addressed how pressure testing should be witnessed. Several 
commenters suggested that there should only be one witness during 
pressure testing to avoid duplication and the spending of unnecessary 
resources. Commenters suggested that the witness should be either BSEE 
or a BAVO, but not both.
    One commenter stated that the required function testing of capping 
stacks should be conducted quarterly, and that pressure testing of all 
critical capping stack components should be conducted on a biennial 
basis.
    Commenters also suggested changes to the proposed paragraph (e) to 
implement their comments, including changing ``pressure holding 
critical components'' to ``pressure containing critical components, and 
changing the proposed witnessing requirement to allow witnessing by 
BSEE ``and/or an independent third-party.''
     Response: As discussed in the previous response, BSEE has 
agreed to change ``pressure holding critical components'' to ``pressure 
containing critical components'' in the final rule. This change 
provides a better description of the purpose of the equipment. BSEE has 
also addressed the concerns the commenters expressed on the use of 
BAVOs elsewhere in this document, in regard to Sec. Sec.  250.731 and 
250.732 and other BAVO-related provisions. BSEE disagrees with the 
suggestion that the proposed requirement that both BSEE and a BAVO 
witness the pressure tests be revised to require the presence of only 
one or the other. It is important for BSEE and a BAVO to witness all 
pressure testing, whenever it is possible for BSEE to be present. 
Although BSEE may not be available to witness every test, BSEE expects 
that it will witness a pressure test and a function test at least once 
per year. Therefore, BSEE has determined that is necessary to require a 
BAVO to witness every pressure test so that BSEE can be assured that 
every test is performed correctly. BSEE has also slightly revised the 
language in final Sec.  250.462(e)(1)(ii) to clarify that if a BSEE 
representative is not available, the test may be witnessed by a BAVO 
alone.

Comments Related to Proposed Sec.  250.462(e)(2)(i)--Production Safety 
Systems Used for Flow and Capture Operations

    Summary of comments: Several commenters suggested changes to the 
Sec.  250.462(e)(2)(i) requirements for production safety systems used 
for flow and capture operations. The commenters stated that subpart H 
of part 250 (Sec. Sec.  250.800 through 250.808) includes requirements 
for items below the wellhead (i.e., subsurface valves) that do not 
encompass source control equipment. They recommended the following 
change in the proposed text of paragraph (e)(2)(i): ``Meet the

[[Page 25926]]

requirements set forth in Sec.  250.800 through 250.808, Subpart H, 
excluding equipment requirements that would be installed below the 
wellhead or that are not applicable to the cap-and-flow system.''
     Response: BSEE agrees with the commenter that this 
provision should not apply to downhole safety systems and has revised 
the final rule to exclude equipment below the wellhead.

Comments Related to Proposed Sec.  250.462(e)(3)--Inspection of Subsea 
Utility Equipment

    Summary of comments: Several commenters suggested BSEE should 
define the expectations for inspection of subsea utility equipment in 
Sec.  250.462(e)(3). They asserted that subsea utility equipment--such 
as debris removal kits, hydraulic power units, coiled tubing, hydrate 
control, and dispersant injection equipment,--is in common use as 
provided by contractors and specific equipment is not designated in 
those retainer agreements. They suggested revising the language in 
proposed paragraph (e)(3) to more clearly define the scope of equipment 
that needs to be available for inspection, as follows: ``Subsea utility 
equipment, requirements, you must: Have all equipment utilized uniquely 
for containment operations available for inspection at all times.''
     Response: BSEE agrees that the nature of the equipment 
that the operator needs to make available to BSEE for inspection can be 
better defined. Accordingly, BSEE has decided to revise the requirement 
in final Sec.  250.462(e)(3) to state, ``[h]ave all referenced 
containment equipment available for inspection at all times.'' BSEE 
also revised this section to include a parallel provision for 
collocated equipment. If the equipment is in use for other normal 
operations, BSEE expects that it would inspect similar equipment 
provided by the same contractor (i.e., coiled tubing).

When must I submit an application for permit to modify (APM) or an end 
of operations report to BSEE? (Sec.  250.465)

    This section of the existing regulation specifies circumstances 
that require an operator to submit an APM or EOR (Form BSEE-0125) and 
the timeframes for doing so. BSEE did not propose any changes to this 
section of the existing regulation, except former paragraph (b)(3). 
Accordingly, the remainder of former Sec.  250.465 is retained in the 
final rules without change. BSEE proposed to revise former paragraph 
(b)(3) to clarify that, if there is a revision to the drilling plan, 
major drilling equipment change, or a plugback, the operator must 
submit an EOR within 30 days after completing the work. This proposed 
provision was intended to help ensure that BSEE has current well 
information. BSEE received no substantive comments on proposed 
paragraph (b)(3), and the final rule includes that paragraph as 
proposed.

Comments Related to Proposed Sec.  250.465--Timeliness and Consistency 
of BSEE Action on Permit Applications

    Summary of comments: Although the only revision to Sec.  250.465 
that BSEE proposed was to former Sec.  250.465(b)(3), regarding 
submittal of EORs (i.e., to incorporate the new EOR requirements in 
proposed Sec.  250.744), one commenter raised general concerns 
regarding the timeliness and consistency of BSEE action on permit 
applications. The commenter stated that, although operators strive to 
submit permit applications well in advance of planned operations, BSEE 
engineers are not able to timely process new applications. Frequently 
BSEE is reviewing new permit requests just prior to a rig arriving, or 
after a rig is already on location, sometimes just before operations 
would have begun. The commenter also asserted that final approval of 
APDs and APMs is often received after operations begin, resulting in 
updated regulatory stipulations or changes to plans which can lead to 
non-compliance issues, confusion between parties, and could result in 
increased operational risks.
     Response: BSEE understands the concerns raised by these 
comments and is making efforts to improve the timeliness of its review 
and approval of APDs and APMs. With regard to this rulemaking, however, 
because these comments are outside the scope of the proposed rule, BSEE 
has not made any revisions concerning APM or APD submittals or 
approvals. Final paragraph (b)(3) requires submission of EORs within 30 
days of completing work and does not address the submission of permit 
applications.

What records must I keep? (Sec.  250.466)

    BSEE proposed to reserve and remove this section and to move the 
content of this former section to proposed Sec.  250.740. BSEE received 
no substantive comments on this provision, and the final rule takes 
that action.

How long must I keep records? (Sec.  250.467)

    BSEE proposed to reserve and remove this section and to move the 
content of this former section to proposed Sec.  250.741. BSEE received 
no comments on the proposed removal and reservation, and the final rule 
takes that action.

What well records am I required to submit? (Sec.  250.468)

    BSEE proposed to reserve and remove this section and to move the 
content of this former section to proposed Sec. Sec.  250.742 and 
250.743. BSEE received no comments on the proposed removal and 
reservation, and the final rule takes that action.

What other well records could I be required to submit? (Sec.  250.469)

    BSEE proposed to reserve and remove this section and to move the 
content of this former section to proposed Sec.  250.745. BSEE received 
no comments on the proposed removal and reservation, and the final rule 
takes that action.

Subpart E--Oil and Gas Well-Completion Operations

General Requirements (Sec.  250.500)

    This section of the existing regulation requires that well-
completion operations be conducted in a way that protects human and 
animal life, property, OCS natural resources, National security and the 
environment. BSEE proposed to revise this section by adding language 
requiring operators to follow the applicable requirements of proposed 
new Subpart G (in addition to Subpart E). BSEE also proposed to replace 
the word ``shall'' with ``must'' throughout this section in order to 
clarify that the provision is mandatory. BSEE received no substantive 
comments on these proposed revisions to the existing regulation and has 
made no changes to the proposed language in the final rule.

Equipment Movement (Sec.  250.502)

    BSEE proposed to reserve and remove this section and to move the 
content of this former section to proposed Sec.  250.723. BSEE received 
no comments on the proposed removal and reservation of this section, 
and the final rule takes that action.

Crew Instructions (Sec.  250.506)

    BSEE proposed to reserve and remove this section and to move the 
content of this former section to proposed Sec.  250.710. BSEE received 
no comments on the proposed removal and reservation of this section, 
and the final rule takes that action.

Well-control Fluids, Equipment, and Operations (Sec.  250.514)

    This section of the existing regulation requires that well-control 
fluids, equipment, and operations be designed,

[[Page 25927]]

used, maintained and tested to control the well under foreseeable 
conditions. BSEE did not propose any changes to this section except 
proposing to remove paragraph (d) of the existing regulation and move 
its content to proposed Sec.  250.720. BSEE received no substantive 
comments on this proposed revision and the final rule takes that 
action.

What BOP information must I submit? (Sec.  250.515)

    BSEE proposed to reserve and remove this section and to move the 
content of this former section to proposed Sec. Sec.  250.731 and 
250.732. BSEE received no comments on the proposed removal and 
reservation of this section, and the final rule takes that action.

Blowout Prevention Equipment (Sec.  250.516)

    BSEE proposed to reserve and remove this section and to move the 
content of this former section to proposed Sec. Sec.  250.730, 250.733, 
250.734, 250.735, and 250.736. BSEE received no comments on the 
proposed removal and reservation of this section, and the final rule 
takes that action.

Blowout Preventer System Tests, Inspections, and Maintenance (Sec.  
250.517)

    BSEE proposed to reserve and remove this section and to move the 
content of this former section to proposed Sec. Sec.  250.711, 250.737, 
250.738, 250.739, and 250.746. BSEE received no comments on the 
proposed removal and reservation of this section, and the final rule 
takes that action.

Tubing and Wellhead Equipment (Sec. Sec.  250.518--Completion 
Operations and 250.619--Workover Operations)

    These sections of the existing regulation provide requirements for 
placement of tubing strings, periodic evaluation of casing subject to 
prolonged operations, and monitoring of casing pressure for completions 
and workovers, respectively. BSEE proposed to remove former paragraph 
(b) from both sections (and to redesignate the remaining paragraphs 
accordingly); and to add new paragraphs (e) and (f) to both sections. 
Those new paragraphs would apply to packers and bridge plugs and 
require adherence to newly incorporated API Spec. 11D1, Packers and 
Bridge Plugs; clarify criteria production packer setting depths; and 
require that an APM include a description of, and calculations for 
determining, the production packer setting depths. After consideration 
of comments on the proposed revisions, BSEE has removed former 
paragraphs (b) from both sections in the final rule; has included 
paragraph (f), as proposed, in both final sections; and has revised the 
proposed language in paragraph (e) of Sec. Sec.  250.518 and 250.619, 
as discussed in the following responses and in part V.C of this 
document.

Comments Related to Proposed Sec. Sec.  250.518 and 250.619--Packers 
and Bridge Plugs

    Summary of comments: Certain commenters stated that compliance with 
API Spec. 11D1 should not be required for temporary packers and bridge 
plugs (i.e., those used for well servicing). Commenters stressed that 
API Spec. 11D1 does not apply to temporary packers and bridge plugs.
    Commenters also had concerns about the proposed requirements in 
Sec. Sec.  250.518(e) and 250.619(e) for setting depth and location of 
the packers. For example, the commenters were concerned that the 
regulations could require setting the packers as close as possible to 
the perforated interval and within the cemented interval of the casing 
section.
    One commenter asked BSEE to clarify whether the requirements in 
proposed Sec. Sec.  250.518 and 250.619 would apply only to packers and 
bridge plugs installed after the rule takes effect, or whether they 
would also apply to packers and plugs already installed before the 
rules take effect.
     Response: BSEE agrees with the commenters that the API 
standard itself does not apply to temporary plugs and packers, and thus 
that these regulations should only require compliance with API Spec. 
11D1 for permanent packers and bridge plugs. Accordingly, BSEE has 
revised the text in paragraphs (e)(1) of final Sec. Sec.  250.518 and 
250.619 to reflect that the requirement applies only to permanently 
installed packers and bridge plugs.
    BSEE understands the concerns about the production packer setting 
requirements. However, BSEE wants to ensure that the packer is set as 
required in this section in order to help ensure long term equipment 
reliability. For example, setting a packer in a cemented interval will 
slow down deterioration that could occur in other settings and thus 
will prolong the effectiveness of the packer. Also, BSEE wants to 
ensure that the packer is not set too high, so that, if there is a 
problem with the packer in the well (e.g., a leak), operators will have 
enough space above the packer to pump a sufficient volume of weighted 
fluid into the well to exert a hydrostatic force greater than the force 
created by the reservoir pressure below the packer. If there are any 
concerns about the specific packer setting depth in any given case, the 
operator may contact the appropriate District Manager for guidance.
    Finally, BSEE agrees that final Sec. Sec.  250.518 and 250.619 are 
applicable only to packers and bridge plugs installed after the 
effective date of the final rule, and they do not require removal and 
replacement of existing packers and bridge plugs already in use. We 
slightly revised final Sec.  250.518(e) to further clarify that intent; 
no change to final Sec.  250.619(e) is necessary since that language is 
already clear on this point.

Subpart F--Oil and Gas Well-Workover Operations

General Requirements (Sec.  250.600)

    This section of the existing regulation requires workover 
operations to be conducted in a way that protects human and animal 
life, property, OCS natural resources, National security and the 
environment. BSEE proposed no changes to this section except proposing 
to add a requirement for operators to follow the applicable provisions 
of new subpart G (in addition to subpart F). BSEE received no 
substantive comments on this proposed revision, and the final rule adds 
the proposed language to final Sec.  250.600.

Equipment Movement (Sec.  250.602)

    BSEE proposed to reserve and remove this section and to move the 
content of this former section to proposed Sec.  250.723. BSEE received 
no comments on the proposed removal and reservation of this section, 
and the final rule takes that action.

Crew Instructions (Sec.  250.606)

    BSEE proposed to reserve and remove this section and to move the 
content of this former section to proposed Sec.  250.710. BSEE received 
no comments on the proposed removal and reservation of this section, 
and the final rule takes that action.

Well-Control Fluids, Equipment, and Operations (Sec.  250.614)

    BSEE proposed to remove paragraph (d) of this former section and to 
move it to proposed Sec.  250.720. BSEE received no substantive 
comments on this provision of the proposed rule and the final rule 
takes that action.

What BOP information must I submit? (Sec.  250.615)

    BSEE proposed to reserve and remove this section and to move the 
content of this former section to proposed Sec. Sec.  250.731 and 
250.732. BSEE received no comments on the proposed removal

[[Page 25928]]

and reservation of this section, and the final rule makes that change.

Coiled Tubing and Snubbing Operations (Sec.  250.616)

    This section of the existing regulation was entitled ``Blowout 
Prevention Equipment'' and provided criteria for design, use, 
maintenance, and testing of BOPs and related well-control equipment. 
BSEE proposed to re-title Sec.  250.616 as ``Coiled tubing and snubbing 
operations,'' to remove paragraphs (a) through (e) of the former 
section, and to move the content of those sections to final Sec. Sec.  
250.730 and 250.733 through 250.736. BSEE also proposed to re-designate 
former paragraphs (f) through (h) as paragraphs (a) through (c) without 
changing the contents of those paragraphs. As proposed, redesignated 
paragraph (a) sets minimum requirements for coiled tubing equipment and 
operations; redesignated paragraph (b) sets certain requirements for 
BOP system components for workover operations with a tree in place; and 
redesignated paragraph (c) requires that an inside BOP or certain types 
of safety valves be maintained on the rig floor during workovers. BSEE 
received no substantive comments on this provision of the proposed rule 
and final Sec.  250.616 includes the proposed changes without 
additional revision.

Blowout Preventer System Testing, Records, and Drills (Sec.  250.617)

    BSEE proposed to reserve and remove this section and to move the 
content of this former section to proposed Sec. Sec.  250.711, 250.737, 
and 250.746. BSEE received no comments on the proposed removal and 
reservation of this section, and the final rule takes that action.

What are my BOP inspection and maintenance requirements? (Sec.  
250.618)

    BSEE proposed to reserve and remove this section and to move the 
content of this former section to proposed Sec.  250.739. BSEE received 
no comments on the proposed removal and reservation of this section, 
and the final rule takes that action.

Subpart G--Well Operations and Equipment

General Requirements

What operations and equipment does this subpart cover? (Sec.  250.700)

    As provided for in the proposed rule, this new section explains 
that subpart G applies to drilling, completion, workover, and 
decommissioning activities and equipment. BSEE received no substantive 
comments on this provision of the proposed rule and has made no changes 
to the proposed language in the final rule.

May I use alternate procedures or equipment during operations? (Sec.  
250.701)

May I obtain departures from these requirements? (Sec.  250.702)

    As provided for in the proposed rule, Sec. Sec.  250.701 and 
250.702 add provisions to new Subpart G acknowledging operators' 
ability to request BSEE approval of alternative procedures or equipment 
and to request departures from operating requirements in accordance 
with existing Sec. Sec.  250.141 and 250.142, respectively. BSEE has 
considered the comments submitted on these proposed sections, and as 
explained in the following responses, the final rule includes these 
sections without change.

Comments Related to Proposed Sec. Sec.  250.701 and 250.702--Alternate 
Procedures or Equipment and Departures

    Summary of comments: Multiple commenters raised concerns about such 
requests. In particular, some commenters claimed that some of BSEE's 
past decisions on alternatives and departure requests were not 
consistent across all districts.
    Another commenter asserted that the proposed rule is unclear about 
when it would be appropriate for BSEE to allow a departure from the 
well operations and equipment regulations in subpart G. The commenter 
stated that the reasons for granting a departure are not specified in 
existing Sec.  250.142 or proposed Sec.  250.702, and that the existing 
and proposed regulatory language for departure requests does not 
specify that the operator must demonstrate that it will achieve at 
least the same level of safety and environmental protection as the 
regulation from which it wants to depart. The commenter recommended 
that BSEE remove the proposed and existing regulations for departures, 
unless BSEE can explain its reasons for allowing departures from the 
applicable drilling requirements, or why a departure should be allowed 
without requiring an adequate substitute for the relevant requirements. 
The same commenter suggested that existing Sec.  250.408 and proposed 
Sec.  250.701 provide an adequate option for operators to request 
approval to use alternative procedures in situations, such as technical 
innovations, where there is a beneficial reason to allow such 
alternatives, that must meet or exceed the requirements in the 
regulations. Other commenters also raised questions regarding 
contractor responsibilities.
     Response: BSEE and the operators need enough flexibility 
under these rules to reasonably accommodate a wide range of potential 
alternative compliance methods and departures. Requests to use 
alternate procedures or equipment must provide sufficient justification 
for BSEE to make a determination that the proposed alternatives provide 
a level of safety and environmental protection that equals or surpasses 
current requirements. With respect to requests for departures from 
operating requirements, BSEE does not specify the type of justification 
required because doing so could unnecessarily limit the submission of 
supporting documentation that could be pertinent under the various 
circumstances that might arise. Moreover, even though existing Sec.  
250.409 and proposed Sec.  250.702 do not expressly require an operator 
seeking a departure to demonstrate that the operator can still achieve 
the same level of safety and environmental protection required by the 
rules, BSEE expects that any request for departure will include 
appropriate measures to ensure safety and environmental protection. 
Accordingly, BSEE has not made any changes to this provision in the 
final rule.
    BSEE is aware of operator perceptions that some past decisions made 
by different Regions or Districts on alternative compliance or 
departure requests appeared to lack complete consistency. However, 
approval of an alternative compliance or departure request is largely 
dependent upon specific site conditions and operational parameters that 
can vary significantly, even for requests that otherwise seem similar 
on their face. Thus, some perceived inconsistent decisions are 
explainable in light of the different case-specific facts and 
circumstances. BSEE strives to ensure consistency in decision-making 
among all Regions and Districts, and BSEE is developing internal 
procedures to improve consistency. In any event, this commenter's 
concerns about consistency do not require any change to the 
regulations.
    Regarding the concerns raised about contractor responsibilities, 
that issue is discussed in part VI.B.5 of this document.

What must I do to keep wells under control? (Sec.  250.703)

    As provided for in the proposed rule, this new section is intended 
to clarify certain precautions required to ensure well control at all 
times. Paragraphs (a)

[[Page 25929]]

through (f) of proposed Sec.  250.703 are included in the final rule 
without change for the reasons discussed in the following responses to 
comments. Proposed paragraph (f) of this section would require the use 
of equipment that is appropriately designed, tested, and rated. 
However, as explained in the following responses to comments on this 
proposed section, paragraph (f) in the final rule has been revised to 
clarify that it applies to the ``maximum environmental and operational 
conditions'' (rather than the proposed ``most extreme conditions'') to 
which the equipment will be exposed.

Comments Related to Proposed Sec.  250.703--General Well-Control 
Requirements

    Summary of comments: One commenter asserted that the rules should 
focus on minimizing the volume of an influx to a well and should 
require better ways (such as Coriolis meters, additional sensors, and 
personnel training) to determine and recognize flow. This commenter 
described an alternative approach based on understanding and 
recognizing well characteristics. The commenter noted that some 
companies already routinely perform this type of work. The commenter 
suggested the following revisions to the proposed rule: (1) Providing 
more emphasis on accurately measuring flows to and from a well; (2) 
remedying the current lack of control devices/instrumentation installed 
with deep-water marine riser systems; (3) requiring well-specific/rig-
specific training for personnel; and (4) requiring realistic well 
control modeling of the well systems.
     Response: This section of the final rule provides both 
specific and general performance-based parameters for keeping wells 
under control that are applicable to all types of wells and conditions. 
However, the listed parameters are not exclusive of other well control 
measures. This section requires operators to ``take the necessary 
precautions,'' not just the precautions listed in Sec.  250.703, to 
control wells and to ``[u]se and maintain equipment and materials 
necessary to ensure the safety and protection of personnel . . . and 
the environment.'' BSEE did not prescribe specific technological 
requirements, including some of the equipment recommended by the 
commenter, because we do not want to limit the operators' options to 
ensure and improve safety. BSEE is directly involved with numerous 
research projects, and aware of others, involving technological 
advancements that could improve equipment and processes, including ways 
to better identify an influx to a well and to improve rig personnel 
situational knowledge. As more information on such advancements becomes 
available, BSEE may use that information to update the regulations, as 
appropriate, in separate rulemakings. As a result, no changes were made 
to the proposed rule in response to this comment.

Comments Related to Proposed Sec.  250.703--Best Available and Safest 
Drilling Technology

    Summary of comments: One commenter discussed concerns about the 
potential change in expectations for operations that could result from 
the absence of the phrase ``best available and safest drilling 
technology,'' which was contained in former Sec.  250.401(a) but which 
was not in proposed Sec.  250.703. Instead, proposed Sec.  250.703(a) 
would require the operator to ``use recognized engineering practices 
that reduce risks to the lowest level practicable.'' The commenter 
recommended that BSEE include both phrases in the final, promulgated 
version of Sec.  250.703.
     Response: BSEE does not agree that adding the phrase 
``best available and safest drilling technology'' to Sec.  250.703 is 
necessary. The BSEE Director, under authority delegated by the 
Secretary of the Interior, will determine when to apply BAST for 
specific technologies. In applying BAST, the BSEE Director will 
determine: When the failure of equipment would have a significant 
effect on safety, health, or the environment; the economic feasibility 
of the technology; if the incremental benefits are clearly insufficient 
to justify the incremental costs of utilizing such technologies; and 
whether requiring the use of BAST is practicable on existing 
operations.
    In this rulemaking, BSEE is not undertaking a BAST determination 
with respect to any specific technology that may be utilized to satisfy 
the requirements of Sec.  250.703. Moreover, the requirement to use 
recognized engineering practices is one broadly associated with 
processes and methods. In contrast, the BSEE's BAST authority focuses 
on technologies, rather than practices.

Comments Related to Proposed Sec.  250.703(f)--Most Extreme Service 
Conditions

    Summary of comments: Some commenters requested revisions to 
proposed Sec.  250.703(f), which would require the use of equipment 
that ``has been designed, tested, and rated for the most extreme 
service conditions to which it will be exposed while in service.'' 
Commenters asserted that multiple extreme conditions are unlikely to 
occur simultaneously; thus, expected conditions based on engineering 
judgment would better represent the real world. The commenters stated 
that unnecessary over-design of equipment, which could result from the 
proposed language, could decrease overall system reliability and 
introduce additional risk. For example, the commenters noted that 
increased design loads for BOPs would lead to larger material forgings, 
adding to overall stresses and fatigue loads experienced by wellheads 
and casing strings.
    Other commenters asserted that the proposed language regarding 
``most extreme conditions'' is unclear, and recommended revising the 
regulation to use the term ``anticipated conditions'' instead. Some 
commenters also suggested that if BSEE believes extreme load survival 
is warranted for certain pieces of equipment, then BSEE should require 
extreme load survivability, and justify it, as a separate provision.
     Response: BSEE agrees that confusion could be created by 
the term ``most extreme conditions.'' Accordingly, BSEE has revised 
final Sec.  250.703(f) by replacing ``most extreme service conditions 
to which it will be exposed'' with the phrase ``the maximum 
environmental and operational conditions to which it may be exposed.'' 
The latter phrase is derived from former Sec.  250.417(a), which is now 
designated as Sec.  250.713(a) in this final rule and which retains 
that phrase. Thus, industry is already familiar with the meaning of 
that language. BSEE intends that language to ensure that equipment used 
for operations is designed, tested, and rated for the most adverse 
weather and other conditions specific to the location in which it will 
be used and the well conditions to which it may be exposed. For 
example, equipment used in the GOM does not need to be designed, 
tested, and rated for Arctic conditions unless that equipment will be 
used in the Arctic. However, equipment used in the GOM does need to be 
designed, tested and rated for the possibility of extreme weather 
conditions, including hurricanes.

Rig Requirements

What instructions must be given to personnel engaged in well 
operations? (Sec.  250.710)

    As provided for in the proposed rule, this new section requires 
personnel engaged in well operations to be

[[Page 25930]]

instructed in safety requirements, possible hazards, and general safety 
considerations, as required by subpart S of part 250, prior to engaging 
in operations. Also as provided for in the proposed rule, this section 
clarifies that the well-control plan must contain instructions for 
personnel about the use of each well-control component of the BOP 
system, and must include procedures for shearing pipe and sealing the 
wellbore in the event of a well control or emergency situation before 
MASP conditions are exceeded. These changes will help establish better 
proficiency for personnel using well-control equipment.
    After consideration of the comments submitted on this proposed 
section, BSEE included the proposed language for this new section in 
the final rule without change, except that final paragraph (a) includes 
minor revisions to the proposed language in order to clarify the intent 
of this paragraph that personnel must be instructed in hazards and 
safety requirements.

Comments Related to Proposed Sec.  250.710(b)--Well and Rig Specific 
Training

    Summary of comments: One commenter recommended that this section 
should place more emphasis on well and rig specific training for the 
crew. The commenter suggested that proposed Sec.  250.710(b)--regarding 
the contents and use of well control plans--comes close to that goal. 
However, the commenter suggested that BSEE should go further, including 
requiring that personnel be fully informed of the characteristics of 
the well.
     Response: BSEE does not agree that the suggested changes 
to this section are necessary. The requirements of Sec.  250.710(b) are 
intended to, and should be sufficient to, help ensure that rig 
personnel engaged in well operations are informed about their specific 
well-control duties and capable of performing them.

Comments Related to Proposed Sec.  250.710(b)--Well-Control Plan

    Summary of comments: Another commenter expressed general support 
for proposed Sec.  250.710(b), but recommended that BSEE require that a 
well-control expert prepare the plan. This commenter also provided 
additional suggestions for what the plan should address, such as well-
control measures using the primary rig, source control and containment 
equipment, and secondary relief rigs. The commenter also expressed 
concerns about the proposed requirement to post a copy of the well-
control plan on the rig floor. The commenter noted that the plan can be 
a complex, lengthy, technical document, and thus recommended that a 
copy of the complete well control plan should be available on the rig 
floor for reference, and that a shorter version of the plan (with the 
key well-control steps) should be posted on the rig floor for quick 
reference.
     Response: BSEE does not agree that the changes suggested 
by the commenter are necessary. BSEE believes it is important that the 
completed well-control plan be available (i.e., ``posted'') in the 
specific areas where the personnel doing the work can review and use it 
to confirm any pertinent details of their and other personnel's well-
control duties. If only a summary of the plan were required to be 
posted, there would be some risk that the summary would omit key 
details of which rig personnel need to be aware.
    In addition, BSEE does not believe that it is necessary for a well-
control expert to draft the plan, as long as it describes the specific 
well-control actions that rig personnel need to take, and provides the 
other essential information that the personnel need to know, as 
specified in Sec.  250.710(b). Nor is it necessary to include the 
additional information (e.g., availability of SCCE or a secondary 
relief rig) suggested by the commenter; that information would be more 
appropriate for an Oil Spill Response Plan, but is not relevant to the 
well-control duties of the rig personnel.

What are the requirements for well-control drills? (Sec.  250.711)

    As provided for in the proposed rule, this section consolidates 
requirements for well-control drills from various sections of the 
existing regulations (i.e., Sec. Sec.  250.462, 250.517, 250.617, 
250.1707) and makes the requirements applicable to all drilling, 
completion, workover, and decommissioning operations covered under new 
subpart G. After consideration of the comments submitted on this 
proposed section, BSEE has included the proposed language in the final 
rule without change, except for a minor change to paragraph (a), as 
explained in the following response to comments and in part V.C of this 
document. This change to the proposed language of paragraph (a) will 
help establish better proficiency for personnel using well-control 
equipment.

Comments Related to Proposed Sec.  250.711--Well-Control Drills

    Summary of comments: Some commenters asserted that the proposed 
requirement is overly prescriptive. Some commenters were concerned 
about the stipulation that the same drill could not be repeated 
consecutively. They stated that the nature of drills is to reinforce 
learning objectives and it may be appropriate to repeat a drill until a 
successful outcome is achieved. They also noted that the drills should 
reflect the operation being conducted; certain operations continue over 
an extended period of time, and therefore it may be appropriate to 
repeat the drill for the ongoing operation. Also, certain drills should 
be repeated due to the criticality of upcoming operations.
    One commenter recommended that the type of drills to be run should 
be recommended by a well-control expert and included in the written 
well-control plan. Also, this commenter stated that the operator should 
document lessons learned from drills as well as any need for additional 
or repeat training.
     Response: BSEE wants to ensure that all personnel complete 
drills involved with all relevant aspects of operations. However, BSEE 
recognizes that some drills may be more critical than others and should 
be done on a regular basis. Therefore, based on the comments received, 
BSEE has revised final Sec.  250.711(a) to clarify that a particular 
drill cannot be run consecutively with the same crew. This change will 
help avoid overly narrow training for certain personnel and improve 
proficiency in well-control procedures by a broader set of rig 
personnel without unduly limiting the operator's discretion to schedule 
important drills.
    BSEE agrees that it is useful for an operator to document any 
lessons learned from completed drills and that the operator should take 
appropriate steps to correct any deficiencies or other problems noted 
from past drills. For example, if the operator notes that certain 
personnel did not perform their duties correctly during a drill, it 
should consider scheduling extra drills involving those personnel and 
otherwise ensure that the personnel understand and can perform their 
specific duties, as described in the well-control plan. However, it is 
not necessary to add such specific, prescriptive requirements to the 
rule, because Sec.  250.711(a) already imposes a responsibility on the 
operator to ensure that drills familiarize well operations personnel 
with their roles so that they can perform their well-control duties 
promptly and efficiently. BSEE believes that this performance-based 
requirement, allowing operators to decide the most effective ways to 
structure their drills, is appropriate given that drills may vary from 
rig-to-rig

[[Page 25931]]

according to the specific rig's location and circumstances and the well 
conditions. However, if, as provided by Sec.  250.711(c), BSEE orders a 
drill (in consultation with the operator's onsite representative) 
during an inspection, and BSEE observes any deficiencies, BSEE will 
notify the operator of any deficiencies and appropriate follow-up 
actions, if necessary. If appropriate, BSEE may also require additional 
drills during subsequent inspections.
    BSEE expects the well-control plan and drills, as required by 
Sec. Sec.  250.710 and 250.711, to function together as effective tools 
to help rig personnel understand and efficiently perform their well-
control responsibilities and duties. Accordingly, except with regard to 
the revision described previously in Sec.  240.711(a), no further 
revisions to final Sec.  250.711 are needed.

What rig unit movements must I report? (Sec.  250.712)

    As described in the proposed rule, this section includes language 
similar to former Sec.  250.403 and adds several new requirements for 
reporting rig movements to BSEE. Paragraphs (a) and (b) of the final 
rule address rig movement reporting requirements for all rig units 
moving on and off locations. Paragraph (c) requires notifications to 
BSEE if a MODU or platform rig is to be warm or cold stacked on a 
lease, including information about where the rig is coming from, where 
it would be positioned, whether it would be manned or unmanned, and any 
changes in the stacking location. Paragraph (d) requires notification 
to the appropriate District Manager of any construction, repairs, or 
modifications associated with the drilling package made to the MODU or 
platform rig prior to resuming operations after stacking. Paragraph (e) 
requires notification to the District Manager if a drilling rig enters 
OCS waters as to where the drilling rig is coming from. Paragraph (f) 
clarifies that if the anticipated date for initially moving on or off 
location changes by more than 24 hours, an updated Rig Movement 
Notification Report (Form BSEE-0144) must be submitted to BSEE.
    After consideration of the comments received, and as explained in 
the following responses to comments and in part V.C of this document, 
BSEE has made several revisions to the proposed language in this final 
rule.

Comments Related to Proposed Sec.  250.712--Terminology

    Summary of comments: A commenter noted that there were 
inconsistencies in BSEE's use of various terms for ``rig'' in this 
section and throughout the proposed rule. The commenter noted terms 
used in this section include: ``Barge,'' ``coiled tubing unit,'' 
``drill ship,'' ``jackup,'' ``snubbing unit,'' ``semisubmersible,'' 
``submersible,'' ``wire-line unit,'' ``rig,'' ``rig unit,'' ``MODU,'' 
``platform rig,'' and ``drilling rig.'' The commenter stated that these 
terms do not seem to be used consistently.
     Response: Different sections of the regulations may have 
different requirements for specific types of rigs, and BSEE has used 
different terms to specify what rigs are covered by each specific 
section. In particular, proposed and final Sec.  250.712 expressly 
require reporting of movements by rig units, including MODUs, platform 
rigs, snubbing units, wire-line units used for non-routine operations, 
and coiled tubing units. As a result, no changes to the rig terminology 
are necessary in the final rule. If any operator is unsure as to 
whether a particular section of the rules applies to a particular unit, 
the operator may contact the District Manager for assistance. If future 
experience with these final rules indicates that further guidance is 
needed on the meaning of any terms, BSEE may issue appropriate guidance 
or amend the regulations at that time.

Comments Related to Proposed Sec.  250.712(a)--72-Hour Rig Movement 
Notification

    Summary of comments: Several commenters raised concerns that the 
requirement in proposed Sec.  250.712(a)(2) to notify the District 
Manager 72 hours before the planned movement of a rig--as compared to 
the longstanding requirement for 24-hour advance notification under 
former Sec.  250.403(a)--will result in many inaccurate estimates of 
rig moves, given the potential for plans and schedules to change. Such 
changes are likely to result in multiple reporting adjustments being 
submitted to BSEE. Another commenter stated that the 72-hour notice 
requirement would be cumbersome and expensive for wireline and coiled 
tubing units.
     Response: BSEE agrees with commenters that the proposed 
72-hour notice requirement may result in additional revisions to the 
submitted form, due to the possibility of frequent adjustments to the 
rig movement schedule over that period. A 24-hour notice requirement 
would provide a better, more reliable indication of when a rig will 
actually move and will minimize the need for revisions to previous 
notifications. Accordingly, the final rule retains the requirement of 
24 hours, which was in the pre-existing regulation.

Comments Related to Proposed Sec.  250.712(c)--Stacking of Rigs

    Summary of comments: A commenter recommended that BSEE should 
include an ``escape clause'' under proposed Sec.  250.712(c) so that 
operators who have not expressly provided permission for stacking a 
MODU on their lease would not be required to provide the specified 
information to BSEE.
     Response: BSEE does not believe that it is necessary to 
change the proposed language. BSEE intends that the responsibility for 
reporting the rig movement under this provision falls on the operator 
or lessee on the lease where the rig is working, not the operator or 
lessee where the rig is being moved to for stacking. Thus, if a lessee 
or operator has not given permission for another operator's MODU or 
platform rig to be stacked on its lease, the operator/lessee who holds 
the lease would not be required to provide the information to BSEE, as 
the commenter suggested.

Comments Related to Proposed Sec.  250.712(d)--Notification of 
Construction, Repairs, or Modifications

    Summary of comments: Regarding proposed Sec.  250.712(d)--requiring 
notification of repairs or modifications to the drilling package for 
stacked units--a commenter suggested that BSEE should not assume an 
operator has stacked a rig on the operator's location, but rather 
should want to know if any stacked rig returns to operation and what 
was done to it prior to the commencement of operations. The rig may not 
be resuming operations for the operator who held the contract when it 
was moved. Another commenter requested that BSEE define the components 
of the ``drilling package'' and that, since equipment repairs are 
performed to return the equipment back to specification, the 
requirement to report repairs should be removed. A commenter stated 
that the requirement to notify the District Manager of ``any'' 
construction, repairs or modifications associated with the drilling 
package is ambiguous.
     Response: The information required by this section is 
necessary for planning and response purposes, including planning for 
possible inspections. The term ``drilling package'' is a commonly 
understood industry term and does not require further definition. BSEE 
intends that ``any'' construction, repairs, or modifications should be 
reported. If repairs or modifications were made to the drilling 
package, BSEE could need that information to plan and conduct 
inspections and perform additional reviews to ensure the repaired or

[[Page 25932]]

modified equipment is used as intended. Although BSEE cannot predict in 
advance all potential types of repairs or modifications that may arise, 
BSEE expects a rule of reason, and does not expect every trivial, de 
minimis, repair (e.g., replacing a loose screw) to be reported.

Comments Related to Proposed Sec.  250.712(e)--Rig Entering OCS Waters

    Summary of comments: A commenter asserted that paragraph (e) 
assumes the operator has the rig under contract when it enters OCS 
waters. The commenter suggested that the requirement instead be keyed 
to when a rig is first utilized for well operations after coming from 
an overseas location.
     Response: BSEE disagrees. BSEE expects an operator that 
has a contract on a rig coming from overseas to make the notification 
upon entry of the rig into U.S. waters, so that BSEE has an opportunity 
to inspect or otherwise determine that the rig is suitable, before the 
rig is first utilized on the OCS. Operators should be aware if its 
contract rig is entering OCS waters and where it is coming from.

What must I provide if I plan to use a mobile offshore drilling unit 
(MODU) for well operations? (Sec.  250.713)

    As provided for in the proposed rule, this section includes MODU 
requirements (e.g., fitness and foundation requirements) from former 
Sec.  250.417, and makes the former requirements applicable to all 
operations covered under subpart G. Paragraph (g) of the final rule 
also codifies certain monitoring requirements previously discussed in 
BSEE NTL 2009-G02, Ocean Current Monitoring. This final section is 
revised from the proposed rule as discussed in the comment responses 
for this section and part V.C of this document.

Comments Related to Proposed Sec.  250.713--Platform Types and USCG

    Summary of comments: One commenter suggested that this section 
should also apply to other types of platforms, including multi-purpose 
service vessels. Another commenter recommended that BSEE coordinate 
with United States Coast Guard (USCG) regarding specific operating 
criteria used to analyze structural pipe on deepwater wells and take 
this opportunity to set uniform standards across the OCS. A commenter 
suggested adding the USCG to the provision under proposed Sec.  
250.713(d) regarding documentation of operational limits imposed by a 
classification society.
     Response: Although there may be some benefit to applying 
these requirements to other types of platforms, BSEE does not currently 
have enough data to make that determination. BSEE will need more data, 
and more research needs to be conducted, to justify expanding the scope 
of this section to other vessels and rigs. Similarly, BSEE does not 
have enough information at this time to proceed with the commenter's 
suggestion that we set specific criteria for analyzing structural pipe 
on deepwater wells.
    In addition, BSEE would need to gather more information and to 
further consult with USCG before deciding whether to add USCG to the 
Sec.  250.713(d) requirement for providing documentation on operational 
limits. BSEE may consider addressing these issues in separate 
rulemakings at a later date. In the meantime, BSEE will continue its 
close coordination with USCG in all matters involving BSEE and USCG 
responsibilities.

Comments Related to Proposed Sec.  250.713--Terminology

    Summary of comments: Another commenter asserted that the use of 
inconsistent terminology for ``rigs'' (e.g., unit, rig unit) in this 
section may create confusion and recommended that BSEE review the Part 
250 regulations for how the various terms referring to rigs are used 
and then include appropriate definitions.
     Response: Different sections of the regulations may have 
different requirements for specific types of rigs, and BSEE has used 
different terms to specify what rigs are covered by each specific 
section. However, BSEE agrees with the suggestion that the uses of 
various terms for rigs in this specific section could cause some 
confusion. Accordingly, BSEE made minor changes to this section to 
improve consistency between rig terms (e.g., we replaced ``unit'' with 
``MODU'' in final Sec.  250.713(a)). The suggestion that BSEE review 
all of part 250 regarding the terminology for rigs falls outside the 
scope of this rulemaking. BSEE may review all of part 250 for this 
purpose at a later date.

Comments Related to Proposed Sec.  250.713(a)--Fitness Requirements

    Summary of comments: A commenter suggested that, under proposed 
Sec.  250.713(a), the requirement to provide information demonstrating 
the unit's capability to perform under the most extreme conditions 
(including the minimum air gap for the hurricane season) should apply 
only if appropriate. This commenter noted that dynamically positioned 
rigs, MODUs and multi-purpose supply vessels typically do not stay on 
location during hurricane season.
    Another commenter stated that the requirement to collect and submit 
environmental data to the District Manager after an APD/APM is approved 
would not benefit the MODU or lift boat that is already on location 
under the approved permit and that is collecting the data, and the MODU 
or lift boat could be at risk if it were truly ``unsuitable'' for the 
site conditions where it is gathering the data. The commenter 
recommended that a metocean specialist assess the suitability of the 
MODU or lift boat for the location, applying conservative environmental 
criteria. If there is uncertainty in the metocean criteria that cannot 
be resolved, the environmental data should be gathered before 
mobilizing a MODU or lift boat to the location.
     Response: BSEE agrees that the requirement to submit 
information on the most extreme environmental conditions that the unit 
is designed to withstand only requires information regarding the 
minimum air gap where that is a relevant factor in the unit's design. 
For example, not all MODUs have or require an air gap (e.g., 
drillships). However, BSEE does not believe it is necessary to 
expressly add such a limitation in Sec.  250.713(a), since it is 
already clearly implied by the language stating that the operator is 
only required to submit information about the most extreme conditions 
the ``MODU is designed to withstand.''
    BSEE agrees that environmental data should be gathered before 
mobilizing a MODU to location, although no change to the regulatory 
text is required to make that point. The requirements in Sec.  
250.713(a) have been in place--in former Sec.  250.417(a)--for years 
and BSEE is not aware of any problems occurring because a unit was 
onsite before the data was gathered and submitted. Nor does BSEE 
believe that it is necessary to require a metocean expert to assess the 
suitability of the unit for the environmental conditions under this 
longstanding provision. Furthermore, the District Manager has the 
authority to revoke approval of the permit if data collected during 
operations shows the MODU cannot perform at the proposed location. This 
will help BSEE ensure that the MODU proposed for OCS operations is 
appropriate for the specific location.

[[Page 25933]]

Comments Related to Proposed Sec.  250.713(b)--Foundation Requirements

    Summary of comments: One commenter asserted that Sec.  250.713(b)--
regarding foundation requirements for MODUs and lift boats--should 
apply only to bottom-supported MODUs or lift boats, where a loss of 
foundation is catastrophic, and that BSEE should exclude moored MODUs 
from this requirement. Another commenter suggested adding text to this 
section to state that the District Manager may accept lower-bound and 
upper-bound soil properties, based on regional soil data and developed 
by a knowledgeable geotechnical engineer, in lieu of the requirement to 
submit information on site-specific soil conditions.
     Response: BSEE agrees with the comment that paragraph (b) 
should apply only to bottom-founded MODUs. Accordingly, BSEE revised 
Sec.  250.713(b) to clarify that this provision requires submittal of 
information showing that site-specific soil and oceanographic 
conditions are capable of supporting the proposed bottom-founded MODUs. 
(In addition, as explained later, BSEE has removed lift boats 
altogether from this section of the final rule.)
    However, BSEE does not agree that regional soil data should be 
allowed in place of site-specific soil data. The purpose of the soil 
data requirement in Sec.  250.713(b) is to ensure that the foundation 
at the specific site is actually capable of supporting a bottom-founded 
MODU, and regional soil data may not be sufficient to demonstrate the 
suitability of the soil at that particular site.

Comments Related to Proposed Sec.  250.713(c)--Frontier Areas

    Summary of comments: One commenter asserted that proposed Sec.  
250.713(c) (requiring information about units in frontier areas) and 
(f) (availability of units for inspection) should not apply to lift 
boats. The commenter stated that lift boats are classified as offshore 
support vessels and are regulated by the USCG.
     Response: Commenters raised several jurisdictional and 
technical concerns regarding the applicability of this section to lift 
boats. For example, some of the information, or access to information, 
required by this section may not be available or pertinent for some 
lift boats. Accordingly, BSEE revised the final rule by deleting all 
references to lift boats in Sec.  250.713.

Comments Related to Proposed Sec.  250.713(e)--Contingency Plans

    Summary of comments: Another commenter recommended adding 
provisions to Sec.  250.713(e), which requires contingency plans for 
dynamically positioned MODUs to move offsite in emergencies, in order 
to ensure that the operator has plans to secure the well during planned 
suspensions.
     Response: Requirements for securing a well during any 
interruption, including suspensions, are adequately covered under final 
Sec.  250.720. Therefore, no changes to Sec.  250.713(e) are necessary 
in this regard.

Do I have to develop a dropped objects plan? (Sec.  250.714)

    As provided for in the proposed rule, this new section codifies 
some of the language from BSEE NTL 2009-G36, Using Alternate Compliance 
in Safety Systems for Subsea Production Operations, and is intended to 
help avoid prolonged damage to subsea infrastructure and to assist 
operators and BSEE in responding to a dropped object. This section also 
requires an operator to develop a dropped objects plan and specifies 
certain information and procedures that must be included in the plan. 
This final section is revised from the proposed rule as discussed in 
the comment responses for this section and in part V.C of this 
document.

Comments Related to Proposed Sec.  250.714(c)--Modeling a Dropped 
Object's Path

    Summary of comments: One comment on proposed Sec.  250.714(c)--
requiring floating rigs in areas with subsea infrastructure to model a 
dropped object's path--asserted that modeling the path does not 
significantly reduce the risk associated with a dropped object.
    With regard to proposed Sec.  250.714(e)--requiring operators to 
include in their dropped objects plan ``any additional information 
required by the District Manager''--one commenter recommended that BSEE 
should limit requests for additional information to ``information 
needed to ensure protection of onsite personnel or the environment.'' 
Another commenter asserted that Sec.  250.714(e) is ambiguous and that 
BSEE should clarify it. Another commenter observed that companies 
should have simultaneous operations (SIMOPS) procedures in place.
     Response: BSEE does not agree that there is no potential 
benefit to modeling a dropped object's path. With the continuing 
expansion of subsea infrastructure, BSEE determined that it is 
important for operators to be aware of, and plan for, the potential 
impacts of a dropped object. Having a dropped object plan helps 
increase such awareness and will help operators, and BSEE, to identify 
impacted infrastructure in order to improve responses to a dropped 
object.
    Section 250.714(e) is intended to give District Managers the 
necessary flexibility and discretion to require information as needed 
in specific cases to fulfill the purposes of the regulation. However, 
BSEE has further clarified final Sec.  250.714(e), by stating that a 
District Manager may require additional information as appropriate to 
clarify, update, or evaluate a dropped objects plan. Thus, the District 
Manager may require additional information regarding dropped objects on 
a case-by-case basis, based on unique site or well conditions.
    BSEE currently does not have enough information about SIMOPS to 
warrant including such a requirement in this final rule. However, BSEE 
agrees that SIMOPS may be a tool that operators should consider when 
multiple operations are being conducted at the same time or in 
conjunction with each other. If research or studies or other 
information about SIMOPS become available in the future that warrant 
further revision of this regulation, BSEE may propose such a revision 
in a future rulemaking.

Do I need a global positioning system (GPS) for all MODUs? (Sec.  
250.715)

    As provided for in the proposed rule, this new section codifies 
existing BSEE NTL 2013-G01, Global Positioning System (GPS) for Mobile 
Offshore Drilling Units (MODUs). The GPS requirements for MODUs 
include: Providing a reliable means to monitor and track the unit's 
position and path in real-time if the unit moves from its location 
during a severe storm; installing and protecting the GPS equipment to 
minimize the risk of the system being disabled; having the capability 
of transmitting data for at least 7 days after a storm has passed; and 
providing BSEE with real-time access to the unit's GPS location data. 
This final section is revised from the proposed rule as discussed in 
the comment responses for this section and in part V.C of this 
document.

Comments Related to Proposed Sec.  250.715--Terminology

    Summary of comments: A commenter raised concern about apparent 
inconsistencies in the use of terminology related to rigs in this 
section. The commenter pointed out that in the proposed rule this 
section referred to ``MODUs and jack-ups,'' ``jack-up and moored 
MODUs,'' ``moored MODU or jack-up,'' and ``Rig/facility/platform.'' In 
addition, the

[[Page 25934]]

caption for this section implies that a jack-up is not a MODU.
     Response: BSEE agrees that the proposed rule's terminology 
concerning rigs in this section might cause some confusion. BSEE made 
some minor changes to this section in the final rule to improve 
consistency between rig terms. For example, BSEE has revised the title 
of this section to ``Do I need a GPS for all MODUs?'' and in final 
Sec.  250.715(a), we have replaced ``jack-up and moored MODU'' with 
``MODU.''

Comments Related to Proposed Sec.  250.715--Applicability

    Summary of comments: A commenter suggested that this provision 
should be extended to all MODUs, including dynamically positioned 
MODUs, rather than just moored MODUs. All MODUs moved from the path of 
a storm should be tracked for emergencies.
     Response: BSEE agrees with the commenter that all MODUs 
should be tracked during severe storms, as required by Sec.  
250.715(e). In any event, as previously stated, BSEE has revised final 
Sec.  250.715(a) by deleting the word ``moored.'' In addition, to avoid 
any potential confusion, BSEE revised the title of this section to 
refer to ``all MODUs.''

Comments Related to Proposed Sec.  250.715(a)--GPS Monitoring and 
Tracking

    Summary of comments: Another commenter recommended revising 
proposed Sec.  250.715(a) by removing the phrase ``if the moored MODU 
or jack[hyphen]up moves from its location during a severe storm.''
     Response: BSEE does not agree with the commenter's 
suggestion. The commenter provided no explanation for this 
recommendation. Operators and BSEE will need the GPS data, and thus all 
MODUs must possess GPS systems capable of providing such data to track 
units during severe storm events. Removing the phrase suggested by the 
commenter would require that the GPS systems also be able to monitor 
and track the unit when making normal rig moves under routine 
conditions. Although any GPS system that provides the tracking and 
monitoring data during a severe storm would be able to provide such 
data during a normal move, BSEE does not need access to such data and 
sees no need to require operators to have such a capability. BSEE is 
particularly concerned about MODUs that lose station-keeping or part 
moorings during storms. Thus, BSEE slightly revised the first sentence 
in this section to clarify that BSEE must have real-time access to GPS 
data prior to and during each hurricane season, consistent with the 
language in NTL 2013-G01 that this provision is codifying (see 80 FR 
21519).

Well Operations

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

    As provided for in the proposed rule, this section consolidates 
requirements from various provisions of the existing regulation 
regarding how to secure a well whenever operations are interrupted. 
Paragraph (a) requires that the District Manager be notified when 
operations are interrupted and provides examples of events that would 
warrant interruption of operations (e.g., any observed flow outside the 
well's casing). The requirement to notify the District Manager gives 
BSEE awareness of interrupted operations and an opportunity for an 
appropriate response. Paragraph (a) also requires a negative pressure 
test to ensure wellbore and barrier integrity before removing a subsea 
BOP stack or surface BOP stack on a mudline suspension well. Paragraph 
(a)(2) clarifies that if there is not enough time to install the 
required barriers or other special circumstances occur, the District 
Manager may approve alternate procedures in accordance with Sec.  
250.141. Paragraph (b) of this section requires prior approval by the 
District Manager for displacement of kill-weight fluid from a wellbore 
and/or riser and specifies the information that must be included in an 
APD or APM to seek such approval. This section is unchanged from the 
proposed rule.

Comments Related to Proposed Sec.  250.720(a)--Testing and Verifying 
Barriers

    Summary of comments: Some commenters recommended that the barriers 
required by proposed Sec.  250.720(a), when operations are interrupted 
be tested and verified as effective by an engineer before the BOP is 
removed. One commenter also recommended that the regulation clearly 
require that barriers be installed prior to removing a BOP. This 
commenter asserted that it appears this was intended, but that the 
regulatory language would benefit from additional clarification, 
including clarifying that it applies when a BOP is removed but the rig 
has not yet moved off location.
     Response: BSEE does not agree with the suggested changes. 
It is not necessary to add a requirement to this paragraph for a PE 
verification of a barrier's effectiveness, given that the barriers must 
be tested, according to Sec.  250.720(b)(2), to ensure integrity before 
moving off the well. Nor is any change needed to clarify that the 
barriers must be installed and tested before moving off location; in 
fact, Sec.  250.720(a) already expressly requires that two independent 
barriers must be installed ``[b]efore moving off the well,'' and Sec.  
250.720(b) effectively requires that the barriers be tested before 
removing mud from the riser in preparation for moving off the well.

What are the requirements for pressure testing casing and liners? 
(Sec.  250.721)

    As provided for in the proposed rule, this section incorporates and 
revises certain requirements from former Sec. Sec.  250.423 and 250.425 
for pressure testing casing and liners. Among other things, final Sec.  
250.721 increases the minimum test pressure specification for conductor 
casing (excluding subsea wellheads) from 200 psi, as under the former 
regulations, to 250 psi; requires operators to test each drilling liner 
and liner-lap before further operations are continued in the well and 
provides the parameters for such tests; clarifies that the District 
Manager may approve or require other casing test pressures as 
appropriate to ensure casing integrity; requires that operators follow 
additional pressure test procedures when they plan to produce a well 
that is fully cased and cemented or is an open-hole completion; 
requires a PE certification of plans to provide a proper seal if there 
is an unsatisfactory pressure test; and requires a negative pressure 
test on all wells that use a subsea BOP stack or wells with mudline 
suspension systems. This final section is revised from the proposed 
rule as discussed in the comment responses for this section and in part 
V.C of this document.

Comments Related to Proposed Sec.  250.721--Monitoring and Verification

    Summary of comments: A general comment on this section asserted 
that BSEE should consider improvements to the monitoring and 
verification of makeup/torqueing of casing/tubular connections, under 
this section and Sec.  250.423(c). Similarly, another commenter stated 
that BSEE should focus on ensuring integrity of the casing string and 
recommended doing so by linking minimum casing test pressure to 
formation integrity pressure.
     Response: BSEE does not agree that these suggested changes 
are necessary to ensure proper installation of casing and tubing. BSEE 
already requires a pressure test on the casing seal assembly under 
former Sec.  250.423(b)(3)--now Sec.  250.423(c)--and submittal to BSEE 
of both the test procedures and test results, in order to verify the 
integrity of the

[[Page 25935]]

casing and connections. There is no need for additional language to 
confirm these results.

Comments Related to Proposed Sec.  250.721(a) Through (c)--Liner Lap 
Testing

    Summary of comments: Multiple commenters asserted that testing of 
the liner-lap, as specified in proposed Sec.  250.721(a) through (c), 
is not possible. The commenters recommended instead that the liner-top 
be tested to confirm integrity of the casing.
     Response: BSEE agrees with the comment that the liner lap 
cannot be tested as proposed, since the liner-lap will not actually 
respond to the pressure from such a test, while the liner-top will 
respond to that pressure. Accordingly, testing of the liner-top is 
sufficient to demonstrate the integrity of the well, and BSEE has 
revised final Sec.  250.721(b) and (c) by substituting ``liner-top'' 
for ``liner-laps'' with regard to the testing required to confirm 
integrity.

Comments Related to Proposed Sec.  250.721(a)--Testing of Surface, 
Intermediate and Production Casing

    Summary of comments: Another commenter stated that under proposed 
Sec.  250.721(a)(3)--regarding testing of surface, intermediate and 
production casing--BSEE should allow operators to test the casing to 
either 70 percent of the casing's minimum internal yield pressure (as 
proposed) or to MAWHP plus 500 psi, in order to avoid putting 
unnecessary loads on the casing or cement.
    A commenter claimed that there is no engineering basis for the 
requirement in proposed Sec.  250.721(b) to test formation integrity at 
the liner shoe, if the liner will not be exposed to that amount of 
pressure. The commenter claimed, for example, that casing shoes set in 
salt are not exposed to such pressures.
     Response: BSEE does not agree that the suggested changes 
are needed or appropriate. The requirement for testing casing to 70 
percent of its minimum internal yield pressure is a longstanding 
requirement, formerly in Sec.  250.423(a)(3), and BSEE is not aware of 
any significant problems or concerns with testing to that limit. If an 
operator has any concerns with the testing procedures in a specific 
case, however, the operator may request, and the District Manager may 
approve, other casing test pressures on a case-by-case basis under 
Sec.  250.721(d).
    For the same reasons, BSEE does not agree that the suggested 
changes to Sec.  250.721(b) are warranted. That testing requirement has 
been in place for many years (formerly in Sec.  250.425(a) and (b)) and 
BSEE is not aware of industry raising any concerns with implementing 
that requirement. In any event, any operator that wants to seek 
approval of an alternative test pressure under Sec.  250.721(d) in a 
specific case may do so.

Comments Related to Proposed Sec.  250.721(e)

    Summary of comments: A commenter raised concerns about proposed 
Sec.  250.721(e)--regarding pressure testing for a well that is planned 
for production--stating that the proposed language to ``pressure test 
the entire well to maximum anticipated shut[hyphen]in tubing pressure'' 
is not clearly defined. The commenter asserted that the text is not 
clear as to whether the ``anticipated shut[hyphen]in tubing pressure'' 
is the pressure with a full column of hydrocarbons or the pressure 
after perforating with an underbalanced fluid. The commenter claimed 
that this ambiguity would make implementing this requirement 
problematic when the fluid in the well at the time of pressure testing 
is of a different density than the planned completion fluid. The 
commenter described various risks associated with this situation and 
suggested that BSEE clarify that the testing pressure must not ``exceed 
70 percent of the burst rating limit of the weakest component.''
    Another commenter stated that the existing regulations on testing 
(Sec.  250.423) are fit-for purpose, and that industry's long standing 
practice to test casing to maximum values only with a technical reason 
for doing so is sufficient. The commenter stated that testing to 
maximum anticipated shut-in tubing pressure may do unnecessary harm to 
the cement integrity.
     Response: BSEE agrees that continually pressure testing to 
the maximum anticipated shut-in tubing pressure may put additional 
stresses on the cement and thus potentially affect cement integrity. 
Therefore, as suggested by one of the commenters, BSEE has revised 
final Sec.  250.721(e) by inserting the phrase ``but not to exceed 70 
percent of the burst rating limit of the weakest component'' to help 
ensure long term cement integrity. In addition, as provided by final 
Sec.  250.721(d), if an operator has other concerns about casing test 
pressures, it may seek approval from the District Manager or Regional 
Supervisor for alternative test pressures on a case-by-case basis.

Comments Related to Proposed Sec.  250.721(f)--Pressure Testing Before 
Resuming Operations

    Summary of comments: One commenter recommended that BSEE should 
revise Sec.  250.721(f)--requiring pressure testing of a well before 
resuming operations--to require operators to run pressure tests long 
enough to stabilize the pressure and to hold a constant pressure for 30 
minutes.
     Response: BSEE does not agree that holding a constant 
pressure for 30 minutes is necessary to demonstrate sufficient 
stability to resume operations. Due to well parameters such as, but not 
limited to, thermal effects, fluid compressibility, fluid 
characteristics, and environmental conditions, holding a constant 
pressure for 30 minutes may not be possible. The proposed requirement 
that--if the pressure declines more than 10 percent in 30 minutes--the 
District Manager must approve a PE-certified plan to resolve the 
pressure issue is sufficient to ensure that the well is fit to be 
operated.

Comments Related to Proposed Sec.  250.721(g)--Negative Pressure Test

    Summary of comments: BSEE received multiple comments on proposed 
Sec.  250.721(g), which addressed negative pressure testing of wells 
with subsea BOP stacks or mudline suspension systems. Commenters 
asserted that the negative pressure tests under Sec.  250.721(g)(1) and 
(3), should only be required if hydrocarbons are present. Commenters 
also recommended that Sec.  250.721(g) require two barriers only if 
hydrocarbons are present.
     Response: BSEE disagrees with the comments about testing 
the barriers only if there are hydrocarbons present. BSEE determined 
that ensuring barrier integrity and well stability by performing the 
required tests is important, even if hydrocarbons are not present at 
the time, because geological conditions (e.g., fluid migration) may 
exist that could subsequently result in hydrocarbons entering the well 
if the barriers are not effective. Thus, testing the barriers' 
effectiveness under such conditions will help ensure that hydrocarbons 
will not enter the well at a later date.

What are the requirements for prolonged operations in a well? (Sec.  
250.722)

    As provided for in the proposed rule, this section consolidates and 
clarifies various sections of the existing regulations that established 
requirements for 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. As discussed in 
the

[[Page 25936]]

comment responses for this section and in part V.C. of this document, 
BSEE has revised the language of proposed paragraph (a) in the final 
rule.

Comments Related to Proposed Sec.  250.722--Introductory Paragraph

    Summary of comments: BSEE received a comment on the introductory 
paragraph of Sec.  250.722, which specifies actions that must be taken 
if wellbore operations continue more than 30 days after the previous 
pressure test. The commenter suggested that the introductory text be 
revised to include ``or independent third-party review of the well's 
casing or liner'' as a condition of timing for performing the 
requirements in this section.
     Response: BSEE did not revise this section based on the 
comment. It is not clear from the comment how the independent third-
party would review the well's casing or liner.

Comments Related to Proposed Sec.  250.722(a)--Prolonged Well 
Operations

    Summary of comments: Other commenters raised concerns with proposed 
Sec.  250.722(a), which requires that operations stop as soon as 
practicable, and that the operator must: Evaluate the effects of 
prolonged operations using a pressure test, caliper or imaging tool; 
and report the results, including calculations showing the well's 
integrity is above minimal safety factors, to the District Manager. 
Commenters asserted that calculations that show a well's integrity is 
above the minimum safety factors cannot be performed for a casing 
pressure test, and thus recommended revisions to Sec.  250.722(a)(2) to 
clarify that the report must include calculations showing that the 
well's integrity is above the minimum safety factors only if an imaging 
tool or caliper is used.
     Response: BSEE agrees with the comment that calculations 
that show a well's integrity cannot be performed for a casing pressure 
test. Accordingly, BSEE has revised final Sec.  250.722(a)(2) to say 
that the report must include calculations that show the well's 
integrity is above the minimum safety factors if an imaging tool or 
caliper is used.

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)

    As provided for in the proposed rule, this section consolidates and 
revises requirements from several former sections (i.e., Sec. Sec.  
250.406, 250.518(b), 250.619(b)) regarding additional safety measures 
for operations on a platform that has a producing well or other 
hydrocarbon flow. Among other requirements, this section requires the 
installation of an emergency shutdown station, for the production 
system, near the rig operator's console. This provision helps ensure 
that rig units would be able to shut-in the production system of the 
host facility. For the reasons discussed in the following comment 
responses, the final rule makes no changes to the proposed rule in 
regard to this section.

Comments Related to Proposed Sec.  250.723--Terminology

    Summary of comments: A commenter noted that there are apparent 
inconsistencies in BSEE's use of terms for ``rig'' in this section. The 
commenter noted terms used in this section include: ``coiled tubing 
unit,'' ``lift boat,'' ``drill ship,'' ``jackup,'' ``snubbing unit,'' 
``wire-line unit,'' ``rig unit,'' and ``MODU.'' However, the commenter 
provided no specific suggestions for addressing this issue.
     Response: For the reasons stated in response to similar 
comments on proposed Sec.  250.712, BSEE has determined that no changes 
to the terminology in this section are necessary.

Comments Related to Proposed Sec.  250.723--Definition of ``Platform''

    Summary of comments: Another commenter stated that the term 
``platform,'' which is mentioned in this section's heading, is not 
defined in part 250, and that facilities or rigs may be built and 
operated on gravel islands or installed on bottom-founded offshore 
structures. The commenter recommended that BSEE develop and add a new 
definition of ``platform,'' including facilities on gravel islands or 
bottom-founded structures, to Sec.  250.105.
     Response: This comment recommends adding a new provision 
that was not in the proposed rule, and the commenter did not suggest a 
specific definition for BSEE to consider. BSEE has decided that it is 
not appropriate to include such a new definition in this final rule. 
Various sections of BSEE's current regulations have long used the term 
``platform'' (or similar terms), including former Sec.  250.406, on 
which final Sec.  250.723 is partially based, and BSEE is unaware of 
any significant difficulties by regulated entities in understanding 
that term in connection with that former section. Moreover, since that 
term is used in somewhat different contexts in different provisions, a 
single definition of that term might not be suitable for use in every 
context.\14\
---------------------------------------------------------------------------

    \14\ 14 For example, BSEE has already proposed adding a 
definition of ``fixed platform'' to Sec.  250.105, for use in 
connection with proposed amendments to Sec.  250.108. (See 80 FR 
34113 (June 15, 2015).) While that proposed definition would be 
appropriate for use under the specific circumstances applicable to 
the proposed amendments to Sec.  250.108 (see id. at 31446), it 
might not be as appropriate for defining similar terms in other 
sections.
---------------------------------------------------------------------------

Comments Related to Proposed Sec.  250.723(c)--Lift Boats

    Summary of comments: A commenter suggested that BSEE not include 
lift boats in Sec.  250.723(c)(3), which requires shut-in of producible 
wells when a MODU or lift boat moves within 500 feet of the platform. 
The commenter observed that lift boats are self-powered motor vessels, 
which are more maneuverable than, and not comparable to, a MODU that is 
towed on location.
     Response: BSEE disagrees with the comment about removing 
lift boats from paragraph (c)(3). Even though a lift boat may be more 
maneuverable than a MODU, care must still be taken when any large 
object, such as a lift boat, undertakes any movement near a well with 
producing hydrocarbons. The risk of a collision or other incident that 
could trigger a well-control event cannot be eliminated simply because 
the moving object may be relatively maneuverable.

What are the real-time monitoring requirements? (Sec.  250.724)

    As described in the proposed rule, this new section includes 
requirements for gathering and monitoring real-time well data. The 
proposed section has been revised in the final rule as discussed in the 
comment responses for this section and in part V.B.4 of this document. 
Proposed paragraph (a) has been revised to clarify that it requires 
using an independent, automatic, and continuous monitoring system 
capable of recording, storing, and transmitting data regarding the BOP 
control system, the well's fluid handling system on the rig, and the 
well's downhole conditions. Proposed paragraph (b) has been revised to 
describe some of the required RTM operational capabilities and 
procedures. Proposed paragraph (c) has been revised to require that an 
operator develop and implement an RTM plan, to specify certain 
information that must be included in the plan, and to require that BSEE 
be provided with access to the plan, and to RTM data, upon request.

[[Page 25937]]

Comments Related to Proposed Sec.  250.724--Claims That the RTM 
Requirements are Premature

    Summary of comments: Some comments asserted that any RTM rule would 
be premature until after studies and research on the application of 
such monitoring and analysis to offshore oil and gas operations is 
complete. Specifically, some comments suggested that BSEE take no final 
action on the RTM regulation until after the National Academy of 
Sciences (NAS) Transportation Research Board completes a study on RTM, 
commissioned by BSEE, and releases its final report.
     Response: RTM is not a novel concept or technology, and it 
is currently widely used in many industrial applications, including 
offshore oil and gas development. Several of the industry commenters 
stated that they already have RTM plans and use RTM systems in their 
offshore operations, and acknowledged the value of such programs. In 
addition, based on regular interaction with operators, BSEE is aware 
that many other operators already use RTM capabilities to monitor 
certain aspects of their operations. Thus, BSEE does not agree that it 
is appropriate to delay promulgation of the RTM requirements in this 
final rule until after the completion of the NAS Report, especially 
since compliance with the RTM requirements will not be required until 
three years after publication of the final rule, and the NAS report is 
currently scheduled to be completed in May 2016. (More information on 
the NAS study is available at: https://www.bsee.gov/Technology-and-Research/Technology-Assessment-Programs/Projects/Project-740/.) BSEE 
will carefully consider the NAS report when it is issued, and if BSEE 
concludes that the report warrants any revisions to these final 
regulations, BSEE may propose such changes in a separate rulemaking.

Comments Related to Proposed Sec.  250.724--Concerns About RTM 
Transmission

    Summary of comments: Some comments raised concerns regarding the 
possibility that the transmittal of RTM to an onshore location could 
provide another opportunity for data system attacks, and that this 
increases the need for more cyber security. In addition, some comments 
asserted that the proposal would increase problems with data retention 
and data quality (e.g., availability of bandwidth and upload time), 
although no specifics were provided in those comments.
     Response: Concerns about cyber security, data retention, 
and data quality have been and will continue to be an issue for all 
regulatory programs that require electronic transmission or storage of 
data. However, much rig-based data has long been, and will continue to 
be, transferred to shore without regard to the proposed RTM 
requirements and, in many cases, without being required by any 
regulation. Many effective measures to address cyber security (e.g., 
access controls, encryption, firewalls, intrusion detection), data 
retention, and data quality issues are available, and BSEE is confident 
that the offshore oil and gas industry is aware of and frequently uses 
such measures. Accordingly, such concerns do not justify foregoing the 
expected benefits of the RTM requirements of this final rule.

Comments Related to Proposed Sec.  250.724--Concerns About Compliance 
Timing

    Summary of comments: Some comments requested that, in lieu of the 
proposed requirements, BSEE give operators 5 years from publication of 
the final rule to address BOPs in RTM plans.
     Response: Those comments did not include any specific 
explanation or support for the requested 5-year period for 
incorporating BOP RTM data in such RTM plans. BSEE has reviewed the 
relevant comments and supporting information, and determined that 3 
years will provide sufficient time to implement the final RTM 
requirements for all of the specified data, including data regarding 
the BOP control system, as proposed. Based upon public comments and 
prior consultation with industry, BSEE believes that many operators 
have already implemented some form of RTM for at least some rig 
equipment and operations (e.g., drilling and fluid handling systems); 
thus, modifying (if necessary) such existing RTM programs to include 
the data specified in Sec.  250.724(a), including BOP data, can be 
reasonably accomplished within 3 years.

Comments Related to Proposed Sec.  250.724(a)--Scope of Data To Be 
Monitored

    Summary of comments: Some comments questioned what was meant by the 
proposed requirement that the operator's RTM system must be capable of 
monitoring ``all aspects of'' the BOP control system, the well's fluid 
handling system, and the well's downhole conditions with any installed 
bottom hole assembly tools.
     Response: For clarity and to avoid any potential 
confusion, BSEE deleted the phrase ``all aspects of'' from final Sec.  
250.724(a), which now requires that the RTM system be capable of 
``recording, storing, labeling, and transmitting data regarding'' the 
``BOP control system data . . .,'' the ``well's fluid handling system . 
. .,'' and the ``well's downhole conditions . . . .''

Comments Related to Proposed Sec.  250.724(b)--Concerns About RTM and 
Decision-Making

    Summary of comments: Many commenters asserted that the proposed RTM 
requirements would lead to an erosion of authority of, or shifting 
operational decision-making away from, the rig-site personnel. In 
particular, some commenters claimed that the requirement in proposed 
Sec.  250.724(b)(4) that RTM data be ``immediately transmitted'' to 
onshore personnel who must be in ``continuous contact'' with rig 
personnel implied that BSEE expected onshore personnel to be able to 
override rig personnel in making key operational decisions based on the 
RTM data. The commenters asserted that such intervention could be 
detrimental to the rig personnel's performance of their operational 
duties, as well as their sense of accountability, and thus could 
actually inhibit their responses to unusual data and otherwise degrade 
safety and environmental protection.
     Response: The proposed rule did not intend to, and the 
final rule does not, contribute to an erosion of authority of, or 
shifting of operational decision-making away from, the rig-site 
personnel. The proposed requirement was intended only to ensure that 
RTM data is transmitted onshore and that onshore personnel who have the 
ability to monitor the data and contact rig personnel in the event that 
unusual data warrants discussion with and potential evaluation by rig 
personnel. (See 80 FR 21520.) BSEE intended the proposed rule to ensure 
that onshore personnel could serve as ``another set of eyes'' to 
monitor the data and potentially to assist rig personnel in performing 
their duties, but not to override the key onsite decision makers or 
interfere with rig personnel performing their onsite duties.
    However, to avoid any confusion in this regard, BSEE has revised 
final Sec.  250.724(b) to address the commenters' concerns, while 
staying true to BSEE's original intent. In particular, we have replaced 
the proposed requirement to ``immediately transmit'' the RTM data to 
the onshore location with a requirement to transmit these data as they 
are gathered, barring unforeseeable or

[[Page 25938]]

unpreventable interruptions in transmission. In addition, we have 
replaced the proposed reference to onshore personnel ``who must be in 
continuous contact with rig personnel'' with a new sentence requiring 
that ``[o]nshore personnel who monitor real-time data must have the 
capability to contact rig personnel during operations.''

Comments Related to Proposed Sec.  250.724(b)--Concerns About RTM 
Interruptions

    Summary of comments: A commenter suggested that the proposed 
requirement in Sec.  250.724(b) regarding communications (continuous 
contact) between rig personnel and onshore personnel would result in a 
shutdown of operations at the rig in the event of any interruption, no 
matter how brief or inconsequential, to onshore-rig communications. The 
commenter asserted that such shutdowns, and subsequent restarting of 
operations, would be extremely costly and would create additional risks 
of malfunction during the shutdowns without any corresponding benefits. 
Another commenter also suggested that loss of RTM transmission to 
onshore should not result in a shutdown under proposed Sec.  
250.724(c).
     Response: Nothing in the proposed rule suggested that an 
operator must automatically shutdown, or that BSEE would necessarily 
order a shutdown of operations due to any break, no matter how minor, 
in transmittal of RTM data onshore or in communications between onshore 
and rig personnel. However, although these concerns were not supported 
by the proposed regulatory text, they are addressed by the revisions in 
this final rule to Sec. Sec.  250.724(b) and 250.724(c). As already 
discussed, BSEE has revised final Sec.  250.724(b) to require that 
operators transmit the RTM data as they are gathered, barring 
unforeseeable or unpreventable interruptions in transmission, and that 
operators have the capability to monitor the data onshore, using 
qualified personnel in accordance with an RTM plan, as provided in 
final paragraph (c). Finally, onshore personnel who monitor real-time 
data must have the capability to contact rig personnel during 
operations.
    In addition, as discussed elsewhere in this document, BSEE has 
revised final Sec.  250.724(c) and removed the language that would have 
authorized the District Manager to require other measures during a loss 
of RTM capabilities. These revisions eliminate the language that the 
commenters perceived could have required shutdowns.

Comments Related to Proposed Sec.  250.724(c)--Concerns About Notifying 
BSEE

    Summary of comments: Various commenters raised concerns about the 
practicality of the requirement in proposed Sec.  250.724(c) to 
immediately notify the District Manager if RTM capability is lost. 
Commenters pointed out that there will be brief losses in monitoring 
capability from time-to-time, which are expected and unavoidable. 
However, the operators and the District Managers could be inundated 
with notifications for very short interruptions that are insignificant 
and have no potential consequences.
     Response: BSEE did not intend the proposed rule to require 
notifications for every loss of RTM capability, no matter how brief or 
insignificant the interruption might be. BSEE agrees with the 
commenters that it would be impractical and an unnecessary burden for 
operators and the District Managers if immediate notifications were 
required for every minor interruption. Accordingly, BSEE has removed 
the proposed requirement to immediately notify the District Manager 
every time RTM is interrupted from the final rule. However, BSEE still 
expects to be informed when there is a significant or prolonged loss of 
RTM capability as outlined in the RTM plan, that potentially could 
increase the risk of a well-control event. Thus, as described in more 
detail elsewhere, BSEE has added a provision to the final rule, at 
Sec.  250.724(c), requiring operators to develop an RTM plan that 
includes a description of how the operator will notify the District 
Manager when such a loss occurs.

Comments Related to Proposed Sec.  250.724(c)--Requests To Delete RTM 
Requirements and/or Require RTM Plans

    Summary of comments: Several commenters requested that BSEE delete 
the proposed RTM requirements from the final rule. Some of those 
commenters also suggested that, if BSEE did not delete RTM altogether, 
it should replace at least some of the prescriptive RTM requirements 
with a performance-based requirement for operators to develop their own 
RTM plans (similar to the safety and environmental management system--
SEMS--plans required by BSEE regulations), which would be available to 
BSEE upon request. Some other commenters, who did not expressly urge 
BSEE to require RTM plans, nonetheless relied on the existence of their 
own RTM plans to justify their recommendation that BSEE eliminate RTM 
requirements from the final rule. Some of the commenters who suggested 
that BSEE require RTM plans also suggested specific issues that should 
be covered in such RTM plans (e.g., qualifications for onshore 
personnel; protocols for communications between rig and onshore 
personnel; protocols for handling interruptions in such communications 
and in RTM capabilities; location of onshore monitoring facilities), 
although each plan could be tailored to fit the circumstances 
applicable to each rig operator.
     Response: BSEE agrees with many of the commenters' 
suggestions regarding the potential advantages of a performance-based 
RTM plan requirement. In particular, BSEE agrees that requiring rig-
specific RTM plans could allow operators to optimize their resources to 
better focus on areas or issues that need the most attention. Further, 
the availability of the RTM plans to BSEE would provide extra insight 
into ways in which RTM can be used to improve safety and environmental 
protection. In addition, such plans would provide operators with a more 
flexible, performance-based opportunity to address issues such as what 
to do when RTM capabilities and communications are interrupted.
    Accordingly, BSEE revised the final rule, as requested by some 
commenters, to include a requirement, in final Sec.  250.724(c), that 
operators develop and implement RTM plans and make the plans available 
to BSEE upon request. That provision requires that the RTM plans 
include certain information, such as:
    [cir] Descriptions of how RTM data will be transmitted onshore, and 
the onshore location(s) where the data will be monitored and stored;
    [cir] Procedures for communications between onshore and rig 
personnel;
    [cir] Actions to be taken if such communications or RTM 
capabilities are lost;
    [cir] Procedures for responding to any significant or prolonged 
interruptions of monitoring or communications; and
    [cir] A protocol for notifying BSEE of any significant or prolonged 
interruptions.
    These RTM plan requirements will complement the other RTM 
requirements in Sec.  250.724(a) and (b).

Comments Related to Proposed Sec.  250.724--Miscellaneous Concerns

    Summary of comments: Several comments did not fit into the 
summaries already discussed. These miscellaneous comments include

[[Page 25939]]

assertions: (a) That the RTM requirements will not result in increased 
functionality, reliability and operability of BOPs and that no RTM 
centers are known to reduce incidents and increase safety; (b) that rig 
alarms and visual inspection are more effective than RTM; and (c) that 
the rule requires the gathering of a huge amount of information.
     Response: Some of these miscellaneous comments express 
opinions (e.g., that rig alarms and visual inspection are better than 
RTM; the RTM requirement will not result in increased functionality, 
reliability and operability of BOPs), with no supporting facts or 
explanations and some are largely irrelevant (i.e., this rulemaking 
does not require operators to establish RTM centers). For the reasons 
stated in the proposed rule and elsewhere in this document, BSEE 
expects the use of RTM to improve safety and environmental protection 
significantly and that such improvements will be seen over time. BSEE 
understands that the RTM provisions of this final rule will result in 
more information being gathered, and BSEE took that into account in 
assessing the potential costs and benefits of this rule under E.O. 
12866 and the Paperwork Reduction Act, as discussed in part VIII and in 
the final RIA. For all of the reasons stated in this document and in 
the final RIA, BSEE has determined that the benefits of the final RTM 
requirements, including the value of the RTM information to be 
collected, are appropriate in relation to the potential costs, 
including the burdens associated with collecting RTM information.

Blowout Preventer (BOP) System Requirements

What are the general requirements for BOP systems and system 
components? (Sec.  250.730)

    As provided for in the proposed rule, this section consolidates and 
revises requirements from several sections of the existing regulations 
for design, fabrication, installation, maintenance, inspection, repair, 
testing and use of BOP systems and BOP components. Among other things, 
paragraph (a) of final Sec.  250.730 requires compliance with relevant 
provisions of API Standard 53 and several related industry standards 
and adds a performance-based requirement that the BOP system be able to 
meet anticipated well conditions and still be able to seal the well. 
Paragraph (b) requires that operators ensure that design, fabrication, 
maintenance, and repair of the BOP system is done pursuant to the 
requirements contained in part 250, OEM recommendations (unless 
otherwise directed by BSEE), and recognized engineering practices. 
Paragraph (c) requires operators to use failure reporting procedures 
consistent with specified industry standards and to report failures to 
BSEE. Paragraph (d) requires that if an operator uses a BOP stack 
manufactured after the effective date of this rule, that BOP stack must 
have been manufactured in accordance with API Spec. Q1. Proposed Sec.  
250.730 has been revised in the final rule as discussed in the comment 
responses for this section and in part V.C of this document.

Comments Related to Proposed Sec.  250.730(a)--BOP Design, 
Installation, and Maintenance

    Summary of comments: In response to the language in proposed Sec.  
250.730(a) that operators ``must design, install, maintain, inspect and 
use'' BOP system components, several commenters pointed out that 
operators do not design, install, or maintain BOP systems. Typically, 
drilling contractors select and obtain the equipment from OEMs and have 
the BOP stack built to order in accordance with API Standard 53. These 
commenters recommended revising this section to replace ``design'' with 
``ensure'' or ``select.''
     Response: Although the requirements in Sec.  250.730(a) 
have long been in place under existing regulations (former Sec.  
250.440), BSEE agrees with the comment that operators do not usually 
design, install, or maintain the BOP systems. Therefore, BSEE has 
revised final Sec.  250.730(a), as suggested by commenters, to state 
that lessees/operators must ensure that the BOP system and system 
components are designed, installed, maintained, inspected, tested, and 
used properly to ensure well control. This change addresses the 
commenters' concern, while clarifying that the lessee or operator 
retains overall responsibility for ensuring the BOP system's proper, 
design, installation, maintenance, inspection, testing and use.

Comments Related to Proposed Sec.  250.730(a)--BOP Design 
Responsibility

    Summary of Comments: Some comments asserted that the requirements 
in proposed Sec.  250.730(a) would implicitly impose QA/QC and 
oversight responsibilities for BOP equipment on lessees/operators that 
are infeasible, given that the design, manufacturing and testing of 
such equipment are completed before the contracts between the lessees/
operators and drilling contractors are in place.
     Response: As explained in the previous response, BSEE has 
revised final Sec.  250.730(a) to require that the operators ``ensure'' 
that the equipment is designed, installed, maintained, etc., to ensure 
well control. To the extent that drilling contractors actually perform 
those activities, the contractors will be jointly and severally 
responsible for compliance with this provision.

Comments Related to Proposed Sec.  250.730(a)--MASP

    Summary of comments: Some commenters recommended that BSEE change 
the reference to ``MASP'' in proposed Sec.  250.730(a) (i.e., that the 
working pressure rating of each BOP component exceed the applicable 
MASP) to ``maximum anticipated wellhead pressure'' (``MAWHP''). They 
asserted that there is no industry agreed-upon definition of ``MASP,'' 
but that MAWHP is defined in API Standard 53.
     Response: BSEE does not agree that the recommended change 
is necessary. As a practical matter, for surface BOPs, the MASP is the 
same as the MAWHP; and for subsea BOPs, the MASP, when taken at the 
mudline as required by Sec.  250.730(a), is also the same as the MAWHP. 
BSEE does not agree that use of ``MASP'' will cause any confusion. 
BSEE's existing regulations (e.g., former Sec.  250.448(b)), have long 
used the term ``MASP,'' and BSEE does not believe that the industry 
will have any difficulty in understanding the meaning and use of that 
term in this rule.

Comments Related to Proposed Sec.  250.730(a)--Annular BOPs

    Summary of comments: Several commenters also stressed that annular 
BOPs capable of meeting the specified pressure rating for ``each BOP 
component'' under proposed Sec.  250.730(a) are not currently available 
and are not considered technologically feasible in the near term. They 
suggested that BSEE clarify that this proposed requirement applies only 
to lower stack components (including and below the uppermost ram) and 
that components above the uppermost ram (e.g., annular and LMRP or 
riser connect) should be excluded. Another commenter suggested 
excluding annular BOPs that comply with Sec.  250.738(g), which sets 
procedural requirements for annular BOPs with rated working pressures 
(RWPs) lower than anticipated surface pressure.
     Response: BSEE agrees that annulars may not be able to 
meet the MASP requirements. BSEE is aware that the current design for 
annulars does not match the pressure rating for large ram preventers 
greater than 10,000 psi.

[[Page 25940]]

Annulars are typically used with wellbore pressures less than MASP. An 
annular does not have any locking mechanisms to keep it closed, as do 
pipe rams and blind shear rams, and it will relax and not seal if the 
hydraulic pressure is lost. Thus, a single annular is not commonly used 
for well-control purposes; rather, annulars are commonly used in 
conjunction with other MASP-rated components, such as pipe rams or 
blind shear rams, that can seal the well under MASP. Therefore, 
excluding annulars from the MASP pressure rating requirement will not 
decrease safety. Accordingly, we have revised final Sec.  250.730(a) to 
exclude annulars from the requirement that working pressure rating 
exceed MASP.

Comments Related to Proposed Sec.  250.730(a)--Flowing Conditions

    Summary of comments: Various commenters raised issues regarding the 
requirement in proposed Sec.  250.730(a) that each ram (except casing 
shears/supershears) must be capable of closing and sealing the wellbore 
at all times, including under flowing conditions. Some commenters 
viewed the proposed language as requiring each ram to be assessed 
against an absolute worst-case event (i.e., any conceivable flowing 
conditions), and that it is not realistic to expect a drilling BOP ram 
to close and seal on a high flow-rate well stream. Some comments 
asserted that the ability to test to such extreme worst-case conditions 
does not exist. Various comments asserted that the actual goal of the 
regulation should be for the BOP system as a whole (including both 
annulars and rams) to reliably shut-in the well under ``reasonably 
anticipated'' or ``anticipated'' flowing conditions. Multiple 
commenters emphasized that the industry has demonstrated the capability 
to successfully seal the wellbore under a variety of anticipated 
flowing conditions (with flow checks using an annular BOP). Some 
commenters, however, claimed there are currently no criteria for 
determining anticipated flowing conditions; while other comments 
suggested that anticipated flowing conditions should be defined by the 
OEM.
    Multiple commenters, therefore, asked BSEE to clarify the 
conditions that the equipment must be designed to meet, while other 
commenters specifically asked BSEE to require that the anticipated 
flowing conditions be defined in the APD for the specific operation and 
well conditions.
     Response: BSEE recognizes that a single ram may not be 
capable of closing and sealing the wellbore at all times under all 
possible flowing conditions. BSEE is also aware that testing an 
individual ram component under all possible well conditions is not 
feasible with current testing mechanisms. Accordingly, BSEE has revised 
final Sec.  250.730(a) to clarify that the BOP system, not each ram, 
must be capable of closing and sealing the wellbore at all times under 
``. . . anticipated flowing conditions for the specific well conditions 
. . . .'' If an operator has any questions about the anticipated 
flowing conditions in any specific case, it may request assistance from 
the District Manager.

Comments Related to Proposed Sec.  250.730(a)--Concerns About 
Compliance Date

    Summary of comments: Commenters also raised concerns that 
implementation of proposed Sec.  250.730 would be required within 90 
days of publication of the final rule. They asserted that BOPs 
available today are not designed to close and seal under the worst-case 
flowing conditions that the commenters assumed the rule would require. 
Similarly, various commenters stated that BSEE has not defined testing 
parameters and protocols necessary to meet such scenarios. Thus, 
multiple commenters requested that BSEE significantly extend the 
proposed 90-day implementation period in order to provide time for 
manufacturers to develop new BOPs and for drillers to purchase and 
install such new designs.
     Response: In light of the revisions to final Sec.  
250.730(a) previously described (i.e, the deletion of the requirement 
for each ram to close and seal, and the insertion of ``anticipated'' 
before ``flowing conditions''), BSEE is not changing the compliance 
date for requiring that BOP systems have the capability to close and 
seal the well. BSEE is aware, and several industry commenters have 
stated, that industry has already demonstrated that reasonably 
available existing BOP systems are capable of successfully closing and 
sealing the wellbore under a variety of flowing conditions under the 
existing BOP regulations (former Sec.  250.440). Given the changes to 
the final rule language, and industry commenters' acknowledgment of 
their ability to comply with the similar requirements under the 
existing regulations, BSEE does not anticipate that industry will need 
to make any significant changes to its current or planned BOP systems 
to comply with the final rule.

Comments Related to Proposed Sec.  250.730(a)(2)--Normative References

    Summary of comments: In general, some industry commenters did not 
support the incorporation by reference of the additional standards 
associated with API Standard 53, as listed in proposed Sec.  
250.730(a)(2), since those listed standards are merely normative 
references in API Standard 53. These associated documents are 
manufacturing specifications, and since they are already referenced in 
API Standard 53, the commenters stated that it is redundant to also 
reference them in the regulations. Several major industry commenters 
requested that, if BSEE does reference these documents in the 
regulations, then it should clarify that only the relevant provisions 
of those documents are required to be complied with.
     Response: BSEE recognizes that the industry standards 
listed in Sec.  250.730(a)(2) are normative references within API 
Standard 53. BSEE is including the standards in the regulations, 
however, because they provide certain relevant specifications for BOP 
system components, and are important to compliance with API Standard 53 
itself. As requested by industry commenters, however, BSEE has revised 
final Sec.  250.730(a)(2) to clarify that the BOP system must meet 
those provisions of the listed industry standards that apply to BOP 
systems.

Comments Related to Proposed Sec.  250.730(a)(2)--Standards--Current 
Editions

    Summary of comments: Other commenters stated that the additional 
standards listed in proposed Sec.  250.730(a)(2) are outdated equipment 
manufacturing standards, and that incorporating a specific outdated 
edition renders equipment manufactured prior to the standard, or 
manufactured to earlier versions of the standard, obsolete. They 
asserted that incorporating only API Standard 53, which includes 
updated normative references, and deleting the outdated standards 
listed in paragraph (a)(2), would resolve this issue. Alternatively, 
some commenters suggested that the regulation should allow equipment to 
be used if it complies with the editions of API Standard 53 and the 
associated standards that were in effect at the time the equipment was 
manufactured.
    A commenter also noted that there are significant misalignments 
between API Standard 53 and the current versions of most of these 
associated standards (e.g., accumulator capacity requirements), which 
would make it impossible to

[[Page 25941]]

comply with API Standard 53 and these associated standards. The 
commenter also noted that API Standard 53 and these associated 
standards are currently being revised, and that the API committees 
working on the new editions are aware of these misalignment issues.
     Response: Whenever BSEE incorporates a standard by 
reference in the regulations, it must incorporate a specific edition of 
the standard (see 1 CFR part 51), and compliance is then required with 
the incorporated standard. BSEE proposed to incorporate the most recent 
(Fourth) edition of API Standard 53, which refers to the other 
standards but which--in contrast to Federal regulations--does not 
specify the edition of those other standards to which it refers. Some 
of the associated standards incorporated by reference in Sec.  
250.730(a)(2) are the current versions (e.g., API Spec. 16A and API 
Spec. 16D); other standards have been updated and new editions adopted 
by industry since BSEE developed and issued the proposed rule. BSEE 
understands the industry is also working to update some of the current 
standards. BSEE will evaluate any new editions of the standards as they 
are finalized by industry. If BSEE determines that any such revised 
standards are appropriate for incorporation in this regulation, BSEE 
may do so in a separate rulemaking. In addition, as previously 
discussed, an operator that wishes to use equipment manufactured to a 
more recent edition of the incorporated standard, may ask for approval 
to do so in accordance with Sec.  250.198(c) and Sec.  250.141 or Sec.  
250.142.

Comments Related to Proposed Sec.  250.730(a)(3)--Pipe and Variable 
Bore Rams (VBRs)

    Summary of comments: Commenters raised concerns that the proposed 
requirement in Sec.  250.730(a)(3) (i.e., that pipe rams and VBRs be 
able to close and seal any drill pipe, workstring and tubing) is not 
achievable for tubing with control lines, electric cable, and flat 
packs. Commenters asserted that the interstices between the tubular and 
these ancillary lines become leak paths when the pipe or VBRs are 
closed around the tubing arrangement. In addition, some commenters 
stated that the proposed requirement would be redundant with existing 
dual barrier systems (including annulars), and thus would provide 
negligible additional improvements to safe operations. Commenters 
recommended that tubing with such exterior lines be excluded from the 
proposed requirement. If the requested exclusion from the proposed 
requirement is not adopted, some commenters suggested that BSEE revise 
the rule to allow alternative control measures based on risk 
assessments.
     Response: BSEE agrees with the comments about pipe rams 
and VBRs not being able to close and seal around tubing with exterior 
control lines and flat packs. An annular is the only BOP component 
currently able to seal around tubing with exterior control lines and is 
only used for a low pressure situation, which is usually the case when 
running tubing with exterior control lines. Accordingly, BSEE has 
revised final Sec.  250.730(a)(3) to clarify that pipe rams and VBRs 
are not required to be able to close and seal around tubing with 
exterior control lines and flat packs. In addition, BSEE has determined 
that this exclusion will not have significant safety or environmental 
consequences since Sec. Sec.  250.733(a) and 250.734(a)(1)(ii) will 
require that the shear rams be able to cut and seal tubing with 
exterior control lines in the hole.

Comments Related to Proposed Sec.  250.730(a)(3)--Claimed Conflicts 
With API Standard 53

    Summary of comments: Commenters requested clarification regarding 
the requirement in proposed Sec.  250.730(a)(3) that the pipe rams and 
VBRs be able to close and seal the tubing using the ``proposed 
regulator settings'' of the BOP system. The commenters claimed that 
this language potentially conflicts with API Standard 53. The 
commenters also suggested that the reference to ``regulator settings'' 
should be removed from this provision because such settings are part of 
the BOP control system described in Sec.  250.730(a).
     Response: This regulation does not prescribe any specific 
requirements for regulator settings. BSEE requires only that the 
regulator settings function as designed or as specified in the APD 
submitted to and approved by BSEE. Therefore, BSEE does not believe 
that this provision will cause any conflict or confusion for operators, 
including with respect to API Standard 53, and thus no change or 
further clarification is necessary.

Comments Related to Proposed Sec.  250.730(a)(4)--Approval of BOP 
Changes

    Summary of comments: With regard to proposed Sec.  250.730(a)(4), 
requiring that operations be suspended pending BSEE approval of any 
changes to the BOP or control systems that would alter previously 
approved schematic drawings--some commenters observed that any changes 
to the BOP stack or control system would be made between wells. Thus, 
any changes to the drawings and equipment would be included in the APD 
for the next well. Those commenters recommended deleting that portion 
of Sec.  250.730(a)(4) that would require such suspensions.
     Response: BSEE disagrees with the comment's suggestion 
that changes would always be made between wells. BSEE understands that 
this is usually the case; however, there are circumstances where 
repairs and modifications to the BOP or control system are made at 
other times and not necessarily between wells. Thus, there is no reason 
to revise this provision.

Comments Related to Proposed Sec.  250.730(a)(4)--Schematic Drawings

    Summary of comments: A commenter recommended that BSEE clarify 
Sec.  250.730(a)(4) to specify that the schematic drawings required for 
the BOP and its control system be the same drawings listed in Sec.  
250.731(b)(1) through (10).
     Response: No changes to the proposed paragraph (a)(4) are 
necessary. Under final Sec.  250.730(a)(4), schematic drawings may 
include other schematics (such as those required under Sec.  
250.737(d)(12)) that are not listed in Sec.  250.731(b)(1) through 
(10).

Comments Related to Proposed Sec.  250.730(b)--Lowest Level Practicable

    Summary of comments: A commenter recommended that BSEE revise the 
first sentence in proposed Sec.  250.730(b) to require that the design, 
fabrication, maintenance, and repair of BOP systems reduce risks to the 
lowest level practicable instead of ``according to the requirements of 
this subpart, OEM recommendations, . . . and recognized engineering 
practices'' as proposed by BSEE.
     Response: The requested changes are not necessary. BSEE 
expects these types of activities to utilize recognized engineering 
practices that reduce risks to the lowest level practicable, as already 
required by existing Sec.  250.107(a)(3).

Comments Related to Proposed Sec.  250.730(b)--BOP Design and 
Fabrication

    Summary of comments: Other comments stated that operators do not 
design and fabricate the BOP systems; they select the equipment based 
upon their specifications and capabilities. Accordingly, commenters 
suggested that BSEE should revise the text, replacing ``design, 
fabricate, maintain, and repair'' with ``select, maintain, and 
repair.''
     Response: BSEE agrees with the comments that operators do 
not usually

[[Page 25942]]

design and fabricate the BOP systems. Therefore, BSEE revised this 
paragraph in the final rule to state that an operator must ensure that 
the design, fabrication, maintenance, and repair of its BOP system is 
in accordance with the requirements contained in the part. This change 
will help clarify that the lessee or operator is responsible for 
ensuring the BOP system's proper, design, installation, maintenance, 
inspection, testing and use even if it does not design and fabricate 
the BOP system.

Comments Related to Proposed Sec.  250.730(b)--BOP Repair and 
Maintenance

    Summary of comments: A commenter suggested that repair and 
maintenance should be carried out in accordance with OEM specifications 
and maintenance manuals and the equipment owner's planned maintenance 
procedures. Additionally, a commenter advised that the OEM's 
recommendations for repair and maintenance should include the quantity 
and quality of parts that the owner or operator subsequently uses.
     Response: The suggested changes are unnecessary. As 
previously discussed, the lessee or operator is responsible for 
ensuring that the BOP system is designed, repaired and maintained in 
accordance with the requirements of this final rule, which includes 
ensuring that the BOP equipment is suitable for the conditions under 
which it will be used (see, e.g., Sec.  250.731), as well as with any 
OEM recommendations, which would include OEM specifications and 
maintenance.
    As to the second comment, BSEE expects the equipment to operate as 
designed and to be used under the conditions for which it was designed. 
However, the commenter's suggestion that OEMs should include the 
quantity and quality of parts subsequently used by the operator in the 
OEMs' recommendations for repair and maintenance is beyond the scope of 
this rulemaking, which addresses requirements that must be met by 
operators.

Comments Related to Proposed Sec.  250.730(b)--Recognized Engineering 
Practices

    Summary of comments: Commenters recommended that the phrase 
``recognized engineering practices'' be removed since the phrase is 
vague and undefined.
     Response: The recommended deletion is neither necessary 
nor appropriate. Recognized engineering practices are commonly 
understood to be found in established codes, industry standards, 
published peer-reviewed technical reports or industry RPs, and similar 
documents applicable to engineering, design, fabrication, installation, 
operation, inspection, repair, and maintenance activities.

Comments Related to Proposed Sec.  250.730(b)--Training of Personnel

    Summary of comments: Commenters recommended that BSEE remove the 
proposed requirements for training of repair and maintenance personnel. 
Some commenters observed that OEMs do not publish training, 
qualification, and maintenance recommendations. Others stated that OEM 
maintenance recommendations are one `size fits all', since OEMs do not 
have a clear understanding of how the equipment will be used, 
maintained or preserved. Commenters emphasized that the equipment 
owners are responsible for the condition of the equipment and that they 
should be responsible for defining the skills and training for their 
maintenance personnel. They also noted that operators are already 
required to address training as part of their SEMS program under BSEE's 
SEMS regulations (see Sec.  250.1915), and that the equipment owners 
(e.g., rig contractors) are also establishing training standards for 
their personnel. One commenter recommended that BSEE should implement 
an accredited/licensed training program, to be developed by the 
industry, instead of relying solely on OEMs and recognized engineering 
practices.
     Response: None of the suggested changes are necessary. 
BSEE agrees that the SEMS training requirements are pertinent to 
personnel maintaining, inspecting or repairing BOPs, and BSEE added an 
express reference to those requirements in final Sec.  250.739(d), as 
discussed elsewhere in this document. However, BSEE does not see any 
inconsistency between the requirements in Sec.  250.730(b), for 
training based on OEM recommendations and recognized engineering 
practices, and BOP-related training as part of the SEMS program and 
under Sec.  250.739(d). There is no reason why operators' SEMS training 
programs should not incorporate OEM recommendations and other 
recognized practices.
    In addition, BSEE does not agree that it should require a new 
training program, whether developed by industry, as suggested by the 
commenter, or not. Contrary to the commenter's assumption, BSEE is not 
relying solely on OEM recommendations and recognized engineering 
practices. As explained previously, the SEMS training requirements 
apply to BOP-related training, and those requirements should be 
sufficient without BSEE creating yet another training program.

Comments Related to Proposed Sec.  250.730(b)--Meaning of OEM

    Summary of comments: Some comments questioned the meaning of OEM in 
this provision. They asked if the OEM is the BOP component manufacturer 
or the suppliers of parts used by the component manufacturer. 
Commenters suggested that, if the proposed rule implies that service 
and maintenance personnel must receive training from subcontractors of 
the OEM, it would not be a workable rule. One commenter suggested that 
there would be a severe impact on the availability of personnel 
permitted to carry out maintenance, depending on the definition of OEM.
     Response: BSEE does not agree that any definition of OEM 
is necessary at this time. BSEE expects that where operators have 
relevant recommendations from manufacturers of individual parts of the 
BOP system, as well as recommendations from the BOP component 
manufacturer, they are able to implement both sets of recommendations. 
Conversely, this regulation does not require operators to follow the 
recommendations of OEMs, whether manufacturers of BOP components or 
individual pieces of equipment, if no such recommendations exist. In 
the event an operator has any questions as to the applicability of any 
specific OEM recommendation, it may ask the District Manager for 
assistance.

Comments Related to Sec.  250.730(c)--BOP Failure Reporting Procedures

    Summary of comments: A commenter recommended that BSEE add near-
miss reporting to failure reporting requirements. Commenters also 
suggested that BSEE define ``failure'' and specify the types of failure 
covered by this provision.
     Response: The comment regarding near-miss reporting is 
outside the scope of this rulemaking and the suggested changes are not 
necessary or appropriate at this time.\15\
---------------------------------------------------------------------------

    \15\ BSEE notes, however, that the U.S. Bureau of Transportation 
Statistics has developed (with BSEE's assistance) a voluntary near-
miss reporting system for OCS facilities and operations. More 
information is available at www.SafeOCS.gov.
---------------------------------------------------------------------------

    BSEE agrees, however, with the suggestion that a definition of 
``failure'' would clarify the scope and applicability of this 
provision. Since there are no definitions of ``failure'' in any of the 
industry standards (i.e., API Spec. 6A, API Spec. 16A, or API

[[Page 25943]]

Standard 53) referenced in this provision, BSEE added a general 
definition of ``failure'' in final Sec.  250.730(c)(1).

Comments Related to Proposed Sec.  250.730(c)--Failure Reporting Under 
API Standard 53

    Summary of comments: A commenter asserted that since API Standard 
53 covers failure reporting by the owner of the equipment, regulations 
on this point are not necessary. Since it is covered in API Standard 
53, the commenter presumed that a prudent drilling contractor would 
conduct such follow-up.
     Response: BSEE understands that failure reporting 
requirements are found throughout various voluntary industry standards, 
several of which are incorporated in this provision. As with any 
voluntary standard incorporated into BSEE's rules, that incorporation 
has the intended benefit of making compliance with the standard a 
regulatory requirement, which promotes consistency across the regulated 
community. BSEE is also including additional failure reporting 
requirements in this rule. Such reporting can lead to improved and more 
reliable equipment.

Comments Related to Proposed Sec.  250.730(c)--Manufacturing Standards

    Summary of comments: Some commenters suggested that BSEE only needs 
to reference API Standard 53 in this section, and that BSEE should 
remove the references to API Spec. 6A and Spec. 16A. API Standard 53 is 
an operational document, while API Spec. 6A and API Spec. 16A are 
manufacturing-related failure reporting methods. Alternatively, BSEE 
needs to provide guidelines on the intended use for referencing Spec. 
6A and Spec. 16A.
     Response: No changes to this proposed paragraph related to 
this comment are necessary. BSEE incorporated the failure reporting 
requirements from all three of the industry standards in the proposed 
provision because each standard contains useful reporting procedures 
that the others do not. In addition, the incorporation of the failure 
reporting procedures of API Spec. 6A and API Spec. 16C adds value to 
this provision because those standards apply specifically to equipment 
that is part of a BOP system. BSEE expects that the failure reporting 
procedures of all three standards will complement each other. On the 
other hand, BSEE sees no need to provide guidance on the potential use 
of API Specs. 6A and 16A at this time. As experience and additional 
information are gained under this rule, BSEE will both provide guidance 
and clarification on this rule as necessary, and consider any new 
information it learns in considering whether any adjustments to the 
rule may be warranted.

Comments Related to Proposed Sec.  250.730(c)--Failure Database

    Summary of comments: Some commenters advised BSEE that a group of 
drilling contractors have developed a database for reporting BOP 
failures. These failures are automatically copied to the OEM by the 
database. According to the commenters, this group plans to implement 
the failure reporting database industrywide. Within a year or so, 
according to the commenter, this group may have sufficient data to 
identify problem areas, to collectively focus on these areas until 
design and procedure changes are implemented that will make well-
control equipment even more reliable.
     Response: The commenters recommended no specific changes 
to the rule or other action by BSEE. In any case, it would not be 
appropriate for BSEE to take any action now based on a program that may 
or may not exist in the future. However, BSEE encourages continued 
proactive evaluation by industry of potential failure mechanisms to 
enhance safety and environmental protection offshore.

Comments Related to Proposed Sec.  250.730(c)--Written Failure Report

    Summary of comments: With regard to proposed Sec.  250.730(c)(1), a 
commenter suggested replacing the requirement for a ``written report'' 
of equipment failure to the manufacturer with ``written notification.''
     Response: BSEE agrees that such a change is appropriate. 
This requirement is only the first step in the failure reporting 
process, and a notice at this step is sufficient. A more detailed 
analysis report of the failure will be provided to the manufacturer, as 
well as to BSEE, under final Sec.  250.730(c)(2). Accordingly, BSEE has 
revised final Sec.  250.730(c)(1) to require only a written notice.

Comments Related to Proposed Sec.  250.730(c)--Concerns About Who 
Should Submit Failure Reports

    Summary of comments: Some commenters stated that, since operators 
do not own the BOP equipment, and are not the primary source of failure 
data, failure reports should come from the drilling contractors. 
Therefore, the commenters recommended revising this section to state 
that the operator must ``ensure'' that a failure report is provided to 
the manufacturer.
     Response: BSEE does not agree that these suggested changes 
are necessary. In paragraph (c), BSEE is requiring the operator to 
provide the notifications and handle the interactions with the 
manufacturer because operators are responsible for all activities under 
a lease.

Comments Related to Proposed Sec.  250.730(c)--Failure Investigation 
and Analysis

    Summary of comments: A commenter noted that not every failure 
warrants a full investigation and suggested replacing ``investigation 
and a failure analysis'' in the proposed rule with ``investigation and, 
when required, a failure analysis.'' According to the commenter, major 
failures should be discussed with the OEM and an investigation 
initiated; however, the system would be unsustainable if every 
(including a minor) failure required investigation by the OEM, a third-
party or a combination of both.
     Response: BSEE disagrees with the assertion that the 
failure reporting system would break down if every minor failure 
required investigation. It is possible that even a so-called ``minor'' 
failure could indicate a potentially more serious problem that warrants 
correction, which would otherwise escape attention, if not for the 
investigation of the ``minor'' failure. Since it is not possible to 
know in advance which seemingly minor failures may lead to a ``major'' 
problem, BSEE does not believe that it is appropriate to limit the 
requirement as suggested.

Comments Related to Proposed Sec.  250.730(c)--Timing of Failure 
Analysis

    Summary of comments: A commenter also suggested that a 60-day 
window to complete and submit failure analysis findings is not 
realistic. It often takes 6 months or more for these findings to be 
obtained and approved. Reporting of the analysis results within 60 days 
will potentially lead to narrowing the scope or lessening the intensity 
of the investigation and diminishing its potential value.
     Response: The commenter apparently misinterpreted the 
proposed rule as requiring that the findings of the failure analysis be 
produced within 60 days, when the proposed requirement actually 
provided that the investigation and analysis must be initiated within 
60 days. Nonetheless, BSEE agrees with the commenter that 60 days may 
not be sufficient for an effective failure analysis to be performed. 
However,

[[Page 25944]]

BSEE does not agree with the commenter's suggestion that 6 months or 
more may be necessary to produce the findings of such analysis. There 
is value to concluding the analysis, and providing the results to the 
manufacturer at a reasonably early date after the failure, so that any 
necessary follow up actions can be taken sooner, and thus potentially 
prevent additional related failures from occurring. Accordingly, BSEE 
has revised final Sec.  250.730(c)(2) by modifying the time for 
performing a failure analysis to 120 days.

Comments Related to Proposed Sec.  250.730(c)--Failure Occurrence

    Summary of comments: A commenter suggested that BSEE revise this 
section to reflect only failures that occur when the BOP system is in 
service and not during maintenance periods.
     Response: BSEE does not agree that these suggested changes 
are necessary. In Sec.  250.730(c), BSEE incorporated the failure 
reporting requirements of 3 industry standards, and those standards 
provide enough specificity as to when a failure triggers the need for 
reporting. In any event, a failure may be an indicator of a serious 
problem requiring investigation and potential follow-up action whenever 
the failure occurs.

Comments Related to Proposed Sec.  250.730(c)(2)--Analysis Report

    Summary of comments: Another commenter recommended that BSEE revise 
proposed paragraph (c)(2) by changing ``copy of the analysis'' to 
``results of the investigation.''
     Response: BSEE agrees with the substance of this comment 
and has revised final Sec.  250.730(c)(2) by changing ``copy of the 
analysis'' to ``copy of the analysis report.'' This revision will 
ensure that the results of the analysis, including any recommendations 
for corrective action, are documented and provided to the manufacturer. 
BSEE expects that the analysis report will describe the analysis as 
well as the results, since it is frequently useful to review the 
analysis to determine the adequacy of the results. For the same reason, 
BSEE has revised final Sec.  250.730(c)(2) to require that a copy of 
the analysis report also be provided to BSEE, since it is important 
that BSEE be aware of the results of failure analyses in order to help 
BSEE identify potential trends and, if appropriate, make others aware 
of a potential problem that may require action to prevent similar 
failures or to improve equipment reliability.

Comments Related to Proposed Sec.  250.730(c)(3)--Questions Concerning 
Who Must Notify BSEE of Failures

    Summary of comments: A commenter requested that BSEE clarify 
paragraph (c)(3) regarding who is required to notify BSEE of an 
equipment design change or change in operating or repair procedures; 
i.e., whether it should be the operator or the contractor (the owner of 
the equipment involved in the failure.)
     Response: Paragraph (c)(3) clearly requires the operator 
to report the design changes or modified procedures, unless another 
person covered by the regulatory definition of ``you'' informs the 
operator it has done so.

Comments Related to Proposed Sec.  250.730(c)(3)--Submittal of Failure 
Report to BSEE

    Summary of comments: Some comments questioned why the report of 
equipment changes or procedural changes must be sent to BSEE's 
headquarters office instead of the District Manager.
     Response: BSEE will require that these reports be sent to 
BSEE headquarters in order to ensure that emerging trends occurring 
across various Districts and Regions are recognized early and that 
potentially serious concerns can be addressed in a coordinated and 
uniform way nationwide.

Comments Related to Proposed Sec.  250.730(d)--Scope of API Spec. Q1 
(Quality Control)

    Summary of comments: One commenter asserted that the proposed 
regulation at Sec.  250.730(d) does not clearly define the scope of the 
requirement to implement API Spec. Q1. The commenter requested that 
BSEE clarify whether this requirement only applies to complete BOP 
stacks, or if it also includes any BOP component that is manufactured 
after the implementation of the rule (e.g., a single BOP ram).
     Response: The intent of the provision is that the complete 
BOP stack must be manufactured pursuant to API Spec. Q1, not the 
individual components of the BOP system.

Comments Related to Proposed Sec.  250.730(d)--Reference to ISO 17011

    Summary of comments: Some commenters suggested that the reference 
to ISO 17011 is incorrect and that the actual reference should be to 
ISO 17021. In addition, they suggested that BSEE add ISO 29001 as an 
optional alternative standard. They also noted that ANSI/API Spec. Q1 
8th edition is no longer available from ANSI, and that BSEE should 
incorporate API Spec. Q1 9th edition, as it is the correct edition. In 
addition, other commenters asserted that there is no API standard for a 
BOP stack, and that API Spec. Q1 would apply only to the individual 
components.
     Response: BSEE already incorporates ISO 17011 under 
Sec. Sec.  250.1900, 250.1903, 250.1904, and 250.1922 for 
qualifications of accreditation bodies under SEMS. Incorporating that 
standard here ensures consistency with the SEMS requirements for 
quality management systems. Regarding incorporation of ISO 29001 as an 
optional alternative standard, BSEE generally expects that operators 
are following the industry developed standards, regardless of whether 
the standard is incorporated in the regulations. However, when BSEE 
incorporates a standard in the regulations, compliance with that 
standard is not optional. An operator may request approval from BSEE to 
comply with an alternative standard under Sec.  250.141. BSEE 
recognizes the concerns related to incorporating the most current 
edition of each standard. The issue of incorporation of a newer edition 
was addressed in comment-responses under Sec.  250.198. The change to a 
new edition or removal of a discontinued standard is not automatic and 
requires rulemaking. Operators may request approval from BSEE to follow 
a later edition of a standard under Sec.  250.198(a)(1). BSEE 
recognizes that API Spec. Q1 applies to the manufacture of individual 
components, however, as previously stated, the intent of the provision 
is that the complete BOP stack must be manufactured pursuant to API 
Spec. Q1, not the individual components of the BOP system.

Comments Related to Proposed Sec.  250.730(d)--Applicability of API 
Spec. Q1 (Quality Control)

    Summary of comments: Some comments requested that BSEE clarify this 
provision since ``BOP stacks'' are not ``manufactured;'' i.e., only the 
components are manufactured. In addition, compliance with the API 
standard incorporated by reference should be sufficient; there is no 
need for BSEE to add ISO requirements.
     Response: BSEE recognizes that API Spec. Q1 applies to the 
manufacture of individual components, however, as previously stated, 
the intent of the provision is that the complete BOP stack must be 
manufactured pursuant to API Spec. Q1, not the individual components of 
the BOP system. The incorporation of ISO 17011 ensures the

[[Page 25945]]

manufacturers of the BOP systems follow the quality management system 
required by API Spec. Q1.

Comments Related to Proposed Sec.  250.730(d)(1)--Approval of Other 
Quality Programs

    Summary of comments: With regard to the proposed option under Sec.  
250.730(d)(1) for seeking BSEE approval for BOP equipment manufactured 
under some quality program other than API Spec. Q1, a commenter stated 
that operators are not typically in the business of manufacturing BOPs 
for their operations. Instead, they typically select a MODU/Rig with a 
BOP as part of the equipment package. Therefore, these requirements 
should be placed upon the drilling contractor when applying for their 
license to operate in the U.S.
    Another commenter asserted that proposed Sec.  250.730(d)(1) would 
allow for potential approval of an alternative quality program (instead 
of API Spec. Q1) for the manufacture of BOP equipment, but that the 
path for obtaining such approval does not appear to be available to 
contractors (unless sponsored by an operator).
     Response: Section 250.730(d) is applicable to operators/
lessees in the same way that most of the requirements in existing part 
250 are applicable. Ultimately, the operator/lessee is responsible for 
compliance with these requirements. As is common practice under the 
regulations, however, operators may contract with others for the 
performance of many of the required actions. In that case, the 
operator/lessee and the person (contractor) actually performing that 
activity are jointly and severally responsible for compliance with the 
applicable requirement. (See Sec.  250.146(c).) The actions required by 
Sec.  250.730(d) are no different.

Comments Related to Proposed Sec.  250.730(d)(1)--Request for 
Alternative Quality Programs

    Summary of comments: Commenters also noted the proposed rule refers 
to approval of alternatives under Sec.  250.141, which is granted by 
District Managers and Regional Supervisors, but requires that the 
request be submitted to the Chief, Office of Offshore Regulatory 
Programs (OORP). The commenter noted that, even if approval by the 
Chief of OORP is obtained, the accepted alternative would not appear to 
be binding on other District Managers or Regional Supervisors.
     Response: BSEE agrees with the comment and revised final 
Sec.  250.730(d) to require operators to send the requests to use an 
alternative quality assurance program to the Chief of OORP and not to 
submit the request under Sec.  250.141.

What information must I submit for BOP systems and system components? 
(Sec.  250.731)

    As provided for in the proposed rule, this section consolidates and 
revises requirements from various former sections for including BOP 
information in APDs, APMs or other submittals to BSEE. Among other 
things, paragraphs (a) and (b) require submission of a complete 
description and schematic drawings of the BOP system. Paragraph (c) 
requires submission of a certification by a BAVO: That test data 
demonstrates the BOP shear ram(s) will shear the drill pipe as 
required; that the BOP was designed, tested, and maintained to perform 
under the anticipated maximum environmental and operational conditions; 
and that the accumulator system has sufficient fluid to operate the BOP 
system without assistance from the charging system. Paragraph (d) 
requires additional certification by a BAVO regarding the design and 
functionality of BOPs used in certain circumstances (e.g., subsea 
BOPs); while paragraph (e) requires descriptions of the autoshear, 
deadman, and EDS systems on subsea BOPs. Paragraph (f) requires a 
certification that the required MIA Report has been submitted within 
the preceding 12 months. BSEE has revised proposed paragraphs (c) and 
(d) of this section in the final rule as discussed in the comment 
responses for this section.\16\
---------------------------------------------------------------------------

    \16\ Any information submitted to BSEE should identify any 
confidential commercial or proprietary information. Any confidential 
or proprietary information will be protected consistent with the 
Freedom of Information Act (5 U.S.C. 552) and DOI's implementing 
regulations (43 CFR part 2); section 26 of OCSLA (43 U.S.C. 1352); 
30 CFR 250.197, Data and information to be made available to the 
public or for limited inspection; and 30 CFR part 252, OCS Oil and 
Gas Information Program.
---------------------------------------------------------------------------

Comments Related to Proposed Sec.  250.731--Concerns About Prescriptive 
Requirements

    Summary of comments: BSEE received a comment stating that this 
section is overly prescriptive on certain issues, including accumulator 
sizing, testing, BOP configurations, and QA/QC oversight.
    Another commenter claimed that this section would be unnecessary 
given that effective verification processes are already in place, and 
that the additional verifications required by this rule would not 
increase the safety of operations or the reliability of equipment.
     Response: BSEE disagrees with the comment that this 
section is overly prescriptive. The specific information required to be 
submitted with APDs, APMs and other submissions is necessary to help 
BSEE make informed decisions in the approval process by providing a 
clear understanding of the BOP system, equipment and operations. These 
provisions essentially set performance-based goals for the operators 
and verifiers, and several of the descriptions of processes and 
equipment that must be verified are broad enough to allow the persons 
doing the verification some flexibility to decide whether, under the 
specific circumstances, it is the equipment or process that should be 
verified.
    BSEE also disagrees with the comment indicating that these 
verification requirements are unnecessary. BSEE believes that these 
certification and verification provisions will serve as a useful tool 
for BSEE and the industry to better ensure--as compared to the current 
rules and industry practices--that equipment and processes function as 
intended to protect safety and the environment.

Comments Related to Proposed Sec.  250.731(a)--BOP System Connections

    Summary of comments: A commenter noted that Sec.  250.731(a)--
requiring descriptions of BOP systems--does not address how the devices 
along the BOP stack are connected, and that there is no mention of 
capping or containment points along the BOP stack. The commenter 
suggests that the BOP system description should address technology that 
enables better containment and is integrated with that system. 
Locations along those devices at which containment and capture 
equipment may be attached should also be included in the system 
description.
     Response: BSEE disagrees with the commenter that capping 
or containment points should be included in this provision. It is 
unclear from the comment what devices, technology, and shortcomings the 
commenter would propose including in Sec.  250.731(a). In any case, 
source control and containment requirements are adequately covered 
under final Sec.  250.462, as described elsewhere in this document.

Comments Related to Proposed Sec.  250.731(a)(7) Through (9)--
Calculations

    Summary of comments: Another commenter observed that the 
calculations required in paragraphs Sec.  250.731(a)(7) through (9) 
should demonstrate that there is adequate pressure available to operate 
each item, especially shear rams. The commenter suggested adding 
information to the rule

[[Page 25946]]

that confirms this is the purpose for conducting the calculations, and 
suggests that the calculations should take into account the actual 
planned sequence of BOP operation for deadman, autoshear, and any 
emergency disconnect programmed operations.
     Response: BSEE disagrees with the suggestion that we 
include the purpose for conducting the calculations, and specifying 
that the calculations must take into account the planned sequence. BSEE 
will review the volume and pre-charge accumulator calculations required 
by paragraphs Sec.  250.731(a)(7) and (9), regardless of sequence, to 
determine that they are adequate to operate all of the required BOP 
functions specified in Sec. Sec.  250.734(a)(3) and 250.735(a) without 
assistance from the charging system.

Comments Related to Proposed Sec.  250.731(c)--Verification of Shearing 
Test Data

    Summary of comments: Commenters questioned the requirement in 
proposed paragraph Sec.  250.731(c)(1) for verification of test data on 
shearing capabilities. Since a test facility to simulate subsea 
conditions for shear testing does not exist, the requirement for shear 
testing at water depth implies the BOP is in an environment that 
simulates the required water depth (instead of on the surface, where 
shear tests are currently performed). The commenters asserted that 
there is a risk of damaging equipment when carrying out shearing tests 
under these conditions. The current industry practice is to apply 
proven calculation methods to surface shear test data and relevant 
maximum allowable working pressure conditions. The commenters claimed 
that if shear tests must be performed under subsea conditions, all of 
the past shear test data will be irrelevant, and that the time and 
effort to re-test will likely shut down the GOM for a considerable 
time. The commenters requested that BSEE revise this requirement to 
allow supporting engineering calculations instead of test data for 
shear capability.
    Another commenter recommended that the equipment manufacturers 
should demonstrate shearing capability and provide shearing data 
instead of operators having to do so.
     Response: BSEE agrees that there are technological 
limitations with testing facilities to simulate subsea conditions. BSEE 
currently allows, and will continue to allow, operators to use 
calculations to help verify shearing at water depth. In fact, this 
provision expressly references final Sec.  250.732, which clearly 
provides that calculations are used in conjunction with testing to 
demonstrate that the pipe can be sheared at the well. Therefore, no 
revision to paragraph Sec.  250.731(c)(1) is warranted.

Comments Related to Proposed Sec.  250.731(c)(2)--Most Extreme 
Anticipated Conditions

    Summary of comments: Most of the comments concerning paragraph 
Sec.  250.731(c)(2) were related to the requirement for verification 
that the BOP has been designed, tested and maintained to perform under 
the ``most extreme anticipated conditions.'' Commenters expressed 
concerns that the term is undefined and asked whether this phrase 
refers, for example, to the worst-case discharge or a kick. Commenters 
also stated that shearing and sealing on flowing wells at worst-case 
discharge rates is not a typical drilling BOP testing scenario, and the 
commenters described how testing to verify BOP capabilities is commonly 
performed. Commenters also pointed out potential hazards from testing 
for worst-case discharges. Commenters suggested that BSEE's emphasis 
should be on early detection and correct shut in procedures. A 
commenter asserted that none of the BOPs currently in use would meet 
the ``most extreme anticipated conditions'' requirement, and that OEMs 
do not qualify BOP components under flowing conditions. Commenters 
recommended that the requirement should be to ``ensure the BOP is 
designed, tested, and maintained to perform under the anticipated 
conditions of the well.''
     Response: As previously discussed, BSEE has revised 
paragraph Sec.  250.731(c)(2) by replacing ``to perform at the most 
extreme anticipated conditions'' with ``to perform under the maximum 
conditions anticipated to occur at the well.'' This change clarifies 
this requirement by relying on reasonably predictable, site-specific 
conditions instead of hypothetical worst-case conditions. In any event, 
if an operator has any questions about the maximum anticipated 
conditions in any specific case, it may request assistance from the 
District Manager.

Comments Related to Proposed Sec.  250.731(c)(3)--Accumulator Systems

    Summary of comments: The primary concern raised by commenters 
regarding paragraph Sec.  250.731(c)(3) was that there appeared to a 
conflict between the requirement for the accumulator systems, on the 
one hand, and API Standard 53, as well as the current work industry is 
undertaking to update the specifications, on the other. Commenters were 
also concerned that this requirement may impact compliance with API 
Specs. 16A and 16D. Commenters suggested that BSEE revise this section 
to require the accumulator system to have sufficient fluid, as defined 
by Sec.  250.734(a)(3) for subsea accumulators and Sec.  250.735(a) for 
surface accumulators, to function the BOP system without assistance 
from the charging system. Other commenters suggested that BSEE revise 
this provision to refer to the accumulator volume test in API Standard 
53.
     Response: BSEE does not agree that the suggested changes 
to paragraph Sec.  250.731(c)(3) are necessary given that, as discussed 
elsewhere, BSEE has revised the final accumulator requirements of Sec.  
250.734(a)(3) for subsea accumulators and Sec.  250.735(a) for surface 
accumulators to more closely align with API Standard 53. Those 
revisions are consistent with recommendations made by some of these 
commenters.

Comments Related to Proposed Sec.  250.731(d)(1)--Verification of BOP 
Design

    Summary of comments: Several of the comments on proposed paragraph 
Sec.  250.731(d)(1) raised concerns with the requirement for 
verification that the BOP stack is designed for the specific equipment 
on the rig and for the specific well design. Commenters asserted that 
the BOP stacks are not designed for specific equipment; they are 
selected in consideration of such equipment, which is designed to meet 
the RWP conditions for the site. Also, BOP stacks are not moved from 
rig to rig, they are part of the rig equipment and selected to suit the 
rig design and capabilities. Commenters suggested that BSEE revise this 
provision to require the BOP stack be suitable for use with the 
specific equipment on the rig, instead of designed for the equipment.
     Response: BSEE does not agree that it is appropriate to 
remove the reference to ``designing'' the BOP stack. The commenters 
appear to be interpreting that term unnecessarily restrictively. BSEE 
believes that the process described by the commenters for how BOP 
stacks are put together with regard to the equipment on the rig is 
effectively what BSEE intended by ``designed.'' BSEE does agree, 
however, with the commenters that the BOP stack must be suitable for 
use with the specific equipment on the rig. Accordingly, BSEE has 
revised final Sec.  250.731(d)(1) by inserting ``and suitable'' after 
the word ``designed.''

[[Page 25947]]

Comments Related to Proposed Sec.  250.731(d)--Independent Verification

    Summary of comments: A commenter recommended that BSEE revise 
proposed Sec.  250.731(d) in order to require independent verification 
of all OCS operations requiring a BOP (rather than just the operations 
specified in the proposed rule), since the purposes of independent 
verification are not unique to subsea BOPs, surface BOPs on a floating 
facility, or BOPs operating in a HPHT environment. The commenter 
recommended that BSEE revise the rule in this way and then reconsider, 
after several years, whether the program is working effectively and 
delivering results, or whether it should be scaled back.
     Response: BSEE does not agree that the requested change is 
appropriate at this time. The verifications required in paragraphs 
Sec.  250.731(a) through (c) are already applicable to all BOPs. 
Paragraphs Sec.  250.731(d) through (f) only apply to BOPs used in 
certain situations because BSEE determined that those situations 
present higher risks than the other situations in which BOPs are used. 
The certification and/or verification requirements in paragraphs Sec.  
250.731(d) through (f) are specific to the equipment, systems or 
procedures that are related to such risks. BSEE does not believe those 
same concerns apply equally to the BOP situations described in 
paragraphsSec.  250.731(a) through (c).

Comments Related to Proposed Sec.  250.731(e)--Subsea BOP Descriptions

    Summary of comments: Regarding the proposed requirement in 
paragraph Sec.  250.731(e) that subsea BOP descriptions include a 
description of the EDS, commenters recommended that BSEE add ``if 
installed'' after ``EDS systems.''
     Response: BSEE does not agree that this change is 
appropriate. BSEE already recognizes that an EDS system is not 
installed or necessary on every rig with a subsea BOP, and Sec.  
250.731(e) is not intended to require descriptions for EDS systems that 
are not present and not otherwise required by the regulations (see 
Sec.  250.734(a)(6)).

Comments Related to Proposed Sec.  250.731(f)--MIA Report

    Summary of comments: A commenter suggested that the MIA report 
certification required by Sec.  250.731(f) is equivalent to the 
certification in the APD. The commenter suggested that the regulation 
be revised to consider either an MIA or an APD certification submitted 
within the past 12 months as sufficient. The commenter also asserted 
that the regulation does not identify who issues the certification.
     Response: This comment is vague and unclear. The MIA 
certification required in paragraph (f) must be included in the 
applicable APD or APM, but BSEE is not aware of any duplication between 
this requirement and any other certification requirement. BSEE does not 
specify who must provide the certification in paragraph Sec.  
250.731(f); so any appropriate person acting on behalf of the operator/
lessee may do so.
    Summary of comments: Many commenters recommended that BSEE revise 
or delete Sec.  250.731(f) as duplicative or unnecessary and 
burdensome. Some commenters requested that BSEE clarify whether this 
certification is required only if an APD has not been submitted in the 
previous 12 months. Commenters suggest that, if it is in addition to an 
APD submitted within the prior 12 months, it appears to be an 
unnecessary time and expense burden.
    Other commenters stated that this report is unnecessary, asserting 
that all of the requested information is already reported in the APD/
APM and the BOP and Well Compatibility Certificate.
     Response: BSEE does not agree that paragraph Sec.  
250.731(f) should be deleted or revised for any of the reasons 
suggested by the commenters. As required by Sec.  250.731, a 
certification statement as described in paragraph (f) must be included 
each time an APD or APM is submitted. Therefore, if multiple APDs/APMs 
are submitted within a 12 month period, each one must include a 
certification statement that an MIA Report was completed within the 12 
months preceding that APD/APM. However, the regulation does not require 
that a certification be submitted every 12 months separately from an 
APD/APM. Nor does it require that an MIA Report be completed or 
submitted every time an APD or APM is submitted.
    In addition, BSEE disagrees that the requested information (i.e., a 
certification statement regarding completion of an MIA Report) is 
already required to be submitted with an APD. Section 250.731(f) itself 
establishes that requirement. BSEE is unaware of any BOP and Well 
Compatibility certificate, as mentioned by the commenter, that is 
currently applicable and duplicative of Sec.  250.731(f).

Comments Related to Proposed Sec.  250.731(c) and (d)--BAVOs

    Summary of comments: Several commenters highlighted the fact that 
BAVOs do not currently exist and that BAVOs cannot be ``approved'' by 
BSEE until after the effective date of the final rule (i.e., 3 months 
after publication); therefore, compliance with the proposed Sec.  
250.731(c) and (d) certification requirements within 3 months, as 
proposed, would not be possible. Some commenters claimed this could 
result in a bottleneck that would effectively become a moratorium on 
OCS drilling. Given the other demands of the proposed rule, some 
commenters asserted that 3 years is a more feasible timeline for 
implementation of this requirement. Other commenters, however, 
requested that the BAVO certification requirements should not go into 
effect until 12 months after the initial BAVO list is published.
     Response: As previously discussed in part V.C of this 
document, BSEE has revised the final rule to extend the compliance 
dates for certain provisions, including those that require the use of a 
BAVO. Under the final rule, operators' APD will not be required to 
submit BAVO certifications under Sec.  250.731 until one year from the 
date when BSEE publishes a list of approved organizations. BSEE 
anticipates that most of the current independent third-parties 
currently used by industry could become BAVOs; thus, one year will be 
sufficient for operators to make use of a BSEE-developed list of BAVOs 
suitable for this rulemaking.
    Summary of comments: A commenter asked if BSEE approval as a 
verification organization is open for any company that applies.
     Response: Any verification organization that seeks 
approval and submits the information specified in Sec.  250.732(a) to 
BSEE may be considered by BSEE for approval as a BAVO.
    Summary of comments: A commenter suggested that BSEE should allow 
use of current verification companies whenever a BAVO is not available.
     Response: Under Sec.  250.732, BSEE will not require the 
use of BAVOs until one year after BSEE establishes a BAVO list. After 
that occurs, there will not be any need to use other verification 
companies. BSEE expects many existing independent third-parties and 
verification companies to become BAVOs.
    Summary of comments: Some commenters asserted that the requirements 
to use BAVOs for certification could create conflicts of interest and 
render the third-party neutrality concept ineffective. That is, if BSEE 
approves the verification organization, and the operators/contractors 
are required to hire them, neither BSEE nor the BAVO nor the

[[Page 25948]]

operators would be independent of each other.
    A commenter asserted that BAVOs provide BSEE with selective powers 
not generally associated with a regulatory organization in a free 
market system. Commenters recommended that BSEE remove/delete all 
references to BAVOs due to potential legal implications and restriction 
of trade.
     Response: BSEE disagrees with the suggestion that the BAVO 
approach will compromise third-party neutrality or effectiveness or is 
otherwise impermissible. To the contrary, approval of verification 
organizations by BSEE will ensure that the BAVOs are independent of the 
parties whose crucial equipment and processes the BAVO will review and 
evaluate. Other regulatory regimes throughout the world use similar 
systems.
    Summary of comments: Some commenters also asked how BAVOs will work 
and what specific factual situations BAVOs would or would not be able 
to certify or verify under Sec. Sec.  250.731(c) and (d) and 250.732 
(e.g., how will a BAVO be able to verify that a stack has not been 
compromised from previous service?).
     Response: These comments seek answers to hypothetical 
questions about how the rules may be implemented in very specific 
factual situations. It would be premature and speculative for BSEE to 
attempt to do so. A BAVO will need to certify or verify the matters 
specified in Sec. Sec.  250.731 and 250.732, but those rules do not 
prescribe exactly how the BAVO must perform those tasks. Rather, the 
purpose of BSEE evaluating and approving verification organizations to 
serve as BAVOs is to ensure that they are knowledgeable and capable 
enough to perform these tasks without BSEE needing to prescribe in 
great detail how to do so under a very specific factual scenario.

What are the BSEE-approved verification organization (BAVO) 
requirements for BOP systems and system components? (Sec.  250.732)

    As provided for in the proposed rule, this new section creates a 
process for BSEE to identify BAVOs and sets out various situations that 
require verification or a report by a BAVO. Paragraph (a) clarifies 
that BSEE will develop and maintain a list of BAVOs on its public 
website, and that compliance with the BAVO-related provisions of the 
rule will not be required until 1 year after BSEE issues that list. 
Paragraph (a) also specifies the information (regarding qualifications) 
that applicants for inclusion on the BAVO list must submit; while 
paragraph (b) lists the types of actions (e.g., shear testing) for 
which an operator must submit BAVO verification. Paragraph (c) of this 
section requires additional BAVO verifications for BOPs and related 
equipment associated with wells in an HPHT environment. Paragraph (d) 
requires an operator to submit to BSEE an annual MIA report prepared by 
a BAVO. These BAVO actions will help BSEE ensure that BOPs will perform 
as necessary to protect safety and the environment from losses of well 
control. BSEE has revised certain provisions of the proposed rule in 
final Sec.  250.732 as discussed in the comment responses for this 
section and in part V.C of this document.

Comments Related to Proposed Sec.  250.732--Existing Quality Control 
Systems

    Summary of Comments: Many comments asserted that operators already 
have adequate systems in place for quality control (e.g., voluntary 
compliance with API Spec. Q1 or similar standards), to verify 
repeatability of testing, and/or to comply with existing requirements 
under BSEE's regulations for SEMS programs (including a requirement for 
SEMS program audits). Commenters suggested that these systems 
adequately address many of the same items subject to BAVO verification 
under proposed Sec.  250.732, and thus, that BAVO verification of 
similar issues is unnecessary and overly burdensome.
     Response: BSEE does not agree that the BAVO-related 
requirements of Sec.  250.732 are unnecessary; nor does BSEE agree that 
those requirements will not provide additional value, to justify the 
burdens on the operators, compared to existing voluntary industry 
practices and BSEE's other regulatory requirements. Third-party 
consultants hired by the operator for quality control, to confirm 
equipment testing repeatability, or for a SEMS audit do not address the 
specific BOP and well-control issues required by the present rule. 
Quality control and equipment testing repeatability are, as stated in 
the comments, addressed by several voluntary industry standards. While 
compliance with industry standards that are not incorporated in the 
regulations is voluntary, the BAVO verifications required by the final 
rule will document compliance with key regulatory requirements for 
ensuring that BOPs will perform as needed to protect safety and the 
environment. For example, the final rule requires verification of shear 
testing, pressure integrity testing, and related calculations for 
verifying that the equipment is suitable for the conditions under which 
it will operate.
    In addition, while BSEE appreciates the value of operators' 
existing quality control programs, including those based on API Spec. 
Q1 or similar standards, BSEE cannot rely on such voluntary programs to 
provide the information or assurances that BSEE needs. As explained in 
the proposed rule, Sec.  250.732 is necessary to ensure that BSEE 
receives accurate information regarding BOP systems so that BSEE may 
ensure the system is appropriate for the proposed use. In particular, 
the verification and documentation of such information by a BAVO would 
enhance BSEE's review of the information in APDs and APMs. (See 80 FR 
21509, 21522.) BSEE believes that the importance and complexity of BOP 
systems warrant a thorough and regular assessment of the systems and 
verification that design, installation, maintenance, inspection, and 
repair activities for such systems are documented and traceable. The 
BAVO-related provisions in Sec.  250.732 will serve this purpose, 
through independent engineering reviews to ensure that required testing 
is effective at ensuring the equipment will perform as designed under 
the conditions to which it will be exposed. (See 80 FR 21509.) 
Voluntary compliance with industry standards alone cannot provide BSEE 
with such assurances.
    Similarly, BSEE believes the SEMS regulations are an important step 
toward building an offshore safety culture that includes oil and gas 
companies as well as their employees and contractors, and the SEMS 
rules will result in substantial safety and environmental protection 
improvements over time. However, the SEMS requirements are very 
different from, and serve different purposes than, the BAVO-related 
requirements. The SEMS regulations focus on creating internal safety 
and environmental management systems that will foster safety and 
environmental protection by ensuring that offshore personnel comply 
with policy and procedures identified in a facility's SEMS plan. The 
SEMS rules lay out largely performance-based elements that the SEMS 
plan must address in areas such as hazards management, inspections and 
maintenance, training, and quality assurance and mechanical integrity 
of critical equipment. (See Sec.  250.1901.) However, the SEMS rules do 
not prescribe specific technical requirements that the plans must 
ensure are met. Nor is BSEE routinely informed of the specific results 
from actual implementation of the SEMS plan at a rig.

[[Page 25949]]

    By contrast, BAVO verifications or reports under Sec.  250.732 will 
provide BSEE with important information regarding, among other things: 
Actual shearing capabilities (through recognized testing protocols and 
analyses), and pressure integrity testing (see Sec.  250.732(b)); 
comprehensive review of the BOP system demonstrating the performance 
and reliability of the equipment; and annual reports by the BAVO on 
mechanical integrity for BOPs used in certain high risk environments. 
BSEE needs the information that BAVOs will verify or create in order to 
ensure that effective and appropriate well-control equipment and 
procedures are actually in place to prevent or minimize future well-
control events. BSEE cannot get that kind of information through 
operators' voluntary compliance with either industry standards or the 
SEMS regulations.
    However, in response to commenters' suggestions that BSEE allow the 
continued use of independent third-parties to perform verifications (as 
required under provisions of the existing regulations that are being 
replaced by these final rules),\17\ and to comments requesting 
additional time to comply with the BAVO requirements, BSEE has revised 
Sec.  250.732(a) of the final rule. The revised paragraph will require 
that an independent third-party, meeting the same criteria as specified 
in former Sec.  250.416(g)(1), perform the same functions that a BAVO 
must perform until such time as the operator uses a BAVO to perform 
those functions (i.e., no later than 1 year after BSEE publishes a list 
of BAVOs).
---------------------------------------------------------------------------

    \17\ Former Sec. Sec.  250.416(e) and (f), 250.515(c) and (d), 
250.615(c) and (d), and 250.1705(c) and (d) require verifications of 
various aspects of drilling, completion, workover and 
decommissioning operations, respectively. Those requirements are 
superseded and replaced by the requirements of final Sec.  
250.731(c) and (d).
---------------------------------------------------------------------------

Comments Related to Proposed Sec.  250.732(a)--Timing of Compliance 
With BAVO Requirements

    Summary of Comments: Many comments asserted a need for sufficient 
time to comply with the BAVO-related requirements after BSEE issues a 
list of BAVOs. Specifically, multiple comments addressed the need for 
time to select a BAVO and to have the BAVO implement the required 
verifications. These comments raised essentially the same concerns 
previously discussed with regard to BAVO certifications as required by 
Sec.  250.731.
     Response: BSEE, as previously explained, has revised the 
final rule to extend the time required to comply with the requirements 
to utilize a BAVO until one year after BSEE publishes a list of BAVOs. 
BSEE has determined that this will provide enough time for operators to 
select a BAVO and for the BAVO to perform the required verifications. 
In the interim, for the reasons previously discussed, BSEE has revised 
final Sec.  250.732(a) to require operators to use an independent 
third-party to provide the certifications, verifications, and reports 
that a BAVO must provide after the requirements to use a BAVO become 
effective.

Comments Related to Proposed Sec.  250.732(a)--General Comments on 
BAVOs

    Summary of Comments: Multiple comments raised the following issues: 
(a) BSEE is restricting industry's choice of third-parties by requiring 
use of a BAVO; BSEE should provide industry with the opportunity to 
comment on the intended detailed work scope for a BAVO; (b) industry 
must be provided with a means of recourse to BSEE on decisions made by 
BAVOs where there is a difference of opinion regarding the application 
or interpretation of a rule or standard; and (c) some of the proposed 
requirements imply that the BAVO may make recommendations on how to 
improve the fabrication, installation, operation, maintenance, 
inspection, and repair of operator equipment.
     Response: Concerning the comments on BSEE restricting 
industry's choice of third-parties by requiring use of a BAVO, BSEE is 
aware that the requirement to use BAVOs will impose some limits on the 
choices of third-parties. However, that is an unavoidable feature of 
any requirement that depends on the use of a third-party having 
relevant qualifications necessary to perform specific tasks, whether 
BSEE determines who meets those qualifications or the operators make 
those decisions themselves. In addition, for the reasons stated in the 
proposed rule, BSEE determined that it is necessary for each BAVO 
performing the important safety and environmental tasks specified in 
Sec. Sec.  250.731 and 250.732 to be technically qualified, experienced 
and capable of performing the functions necessary for BSEE and the 
public, as well as the operators, to be sure that the BOP systems and 
equipment will function as intended. Therefore, in its oversight role, 
it is necessary that BSEE make the first decisions as to which third-
parties are eligible to be used for these purposes, rather than leaving 
that decision entirely to the operators whose equipment and processes 
must be evaluated and verified to be suitable and capable of performing 
their intended functions.
    In any case, BSEE will publish a list of BAVOs so that choices will 
be available to operators. BSEE expects that there will also be enough 
listed BAVOs that operators will be able to base their choices between 
BAVOs on various factors, such as experience, price, availability, and 
access to appropriate technology. After the initial BAVO list is 
published, BSEE will continue to evaluate other verification 
organizations that apply for approval as BAVOs and will refresh or 
supplement the list from time to time as necessary to ensure that 
choices continue to be available to operators.
    Concerning the suggestion that BSEE should provide industry with 
the opportunity to comment on the detailed scope of the work that BSEE 
intends BAVOs to perform, the final rule, in Sec. Sec.  250.731 and 
250.732, provides the scope of the certifications and verifications 
that BAVOs must perform. As to how a BAVO will perform each specific 
task for a specific facility, the BAVO and the operator employing the 
BAVO will work together to determine the precise nature and execution 
of the work. BSEE expects that the BAVOs and operators will establish 
these parameters through the contracting process.
    Concerning the comments that industry should have a means of 
recourse to BSEE on decisions made by BAVOs where there is a difference 
of opinion regarding application or interpretation of a rule or 
standard, several means exist for BSEE to resolve such differences of 
opinion. In the first place, BSEE expects the BAVO and the operator to 
communicate with each other and attempt to resolve any differences of 
opinion in a mutually acceptable way. However, if necessary, the 
operator may refer requests for an interpretation of a specific 
regulation, or a standard incorporated in the regulations, to BSEE for 
assistance. In addition, if it appears that there is a broader need for 
an interpretation to guide BAVOs and operators, BSEE will consider 
issuing a NTL, an Information to Lessees and Operators, or a similar 
notice of interpretation or guidance, as appropriate.
    BSEE disagrees with the comments suggesting that the proposed 
requirements imply that the BAVO may make recommendations on how to 
improve the fabrication, installation, repair, etc., of operator 
equipment. The rule does not state or imply that a BAVO must or should 
make recommendations to an operator with respect to the equipment. 
However, BSEE does expect

[[Page 25950]]

the BAVO process to help, over time, the industry to improve the 
performance of the equipment and to develop more and better testing 
protocols. (See 80 FR 21509.)

Comments Related to Proposed Sec.  250.732(a)(1) Through (7)--Criteria 
for BAVOs

    Summary of Comments: Multiple comments asserted that the criteria 
used to evaluate the technical knowledge of the BAVOs must be 
established in advance and be more detailed than the proposed criteria. 
A commenter also suggested that industry should be consulted in helping 
to identify qualified candidates. However, other commenters recommended 
that the regulation expressly require BAVOs to be independent of 
equipment manufacturers and operators.
     Response: BSEE disagrees with the comments calling for 
more detailed BAVO criteria. Proposed Sec.  250.732(a)(1) through (6) 
(renumbered as Sec.  250.732(a)(3)(i) through (vi) in the final rule) 
specified the criteria that BSEE would apply in evaluating the 
qualifications, caliber, and technical knowledge of each verification 
organization before deciding whether it should be approved. The 
commenters on this issue provided no additional detailed criteria for 
BSEE to apply in evaluating verification organizations, and BSEE sees 
no reason to add more criteria at this time.
    In addition, BSEE disagrees with the suggestion that industry 
should be consulted in helping to identify BAVO candidates. As 
explained in the proposal, the purpose of the BAVO concept is to ensure 
that BOP equipment is monitored during its lifecycle by an 
``independent third-party'' to verify compliance with the regulations, 
OEM recommendations, and recognized engineering practices. (See 80 FR 
21522.) As explained in the proposed rule, a potential BAVO must apply 
to BSEE for approval, and must submit specific information and 
documentation demonstrating its qualifications and experience, as 
provided in Sec.  250.732(a)(1) through (7). (See id. at 21510, 21522.) 
BSEE will then evaluate that specific information to determine whether 
the verification organization is qualified to carry out the BAVO-
related tasks listed in Sec.  250.732(b) through (d) and in other 
sections. If BSEE determines, based on the information submitted and 
BSEE's understanding of the specific tasks BAVOs must perform, that an 
organization is qualified to perform those task, BSEE will add that 
organization's name to the BAVO list.

Comments Related to Proposed Sec.  250.732(b)(1)(i)--BOP Shearing Tests

    Summary of Comments: Multiple commenters raised concerns with the 
proposed requirement in Sec.  250.732(b)(1)(i) for shearing tests that 
demonstrate the BOP will shear the drill pipe and any electric-, wire-, 
and slick-line to be used in the well. They asserted that many rigs do 
not currently have shearing capability that would conform to that 
requirement and cannot obtain such equipment within the 3 months 
provided by the proposed rule for compliance. As a result, many 
drilling operations could be shutdown. They requested that BSEE extend 
the requirement for shearing the exterior control lines (e.g., wire-
line) to 5 years.
     Response: BSEE agrees that more time may be necessary to 
allow installation on all BOPs of shear rams capable of shearing 
electric-, wire-, slick-lines to be used in the hole. However, BSEE 
does not agree that 5 years is necessary for compliance with this 
requirement. Although 5 years might be appropriate if no technology 
capable of meeting this requirement existed, BSEE is aware that some 
technology to meet this requirement already exists (and thus does not 
need to be newly developed after promulgation of this rule). 
Nonetheless, BSEE understands that significantly more than 90-days will 
be needed for all operators to obtain, modify (if necessary to meet 
specific circumstances), and install the technology. Therefore, BSEE 
has revised Sec. Sec.  250.732(b)(1)(i) and 250.734(a)(1)(ii) in the 
final rule to extend the compliance date for demonstrating that the BOP 
can shear electric-, wire-, or slick-line until 2 years after 
publication of the final rule. This extended compliance date will allow 
sufficient time for operators to acquire and install appropriate 
equipment without causing any rig downtime.

Comments Related to Proposed Sec.  250.732(b)(1)(ii)--BOP Shearing 
Tests

    Summary of Comments: One comment was received on proposed Sec.  
250.732(b)(1)(ii), requiring a demonstration that the operator's shear 
testing at a facility that meets generally accepted quality assurance 
standards. The commenter stated that ``generally accepted quality 
assurance standards'' needs to be clarified, and recommended that BSEE 
provide examples of this requirement (e.g., ISO 9001).
     Response: BSEE does not believe that revisions to the 
regulatory text are needed in response to this comment. The proposed 
language in Sec.  250.732(b)(1)(ii) is intentionally general and 
performance-based so as to leave operators free to use testing 
facilities that meet generally accepted quality assurance standards. 
BSEE believes that operators are capable of identifying such standards, 
but if future experience under this provision demonstrates that 
operators need guidance to identify such standards, BSEE may provide 
appropriate guidance at a later date.

Comments Related to Proposed Sec.  250.732(b)(1)(v)--BOP Shearing 
Capacity

    Summary of Comments: Several commenters requested that BSEE revise 
proposed Sec.  250.732(b)(1)(v)--regarding demonstration of the 
shearing capacity of the BOP--to clarify that the demonstration must be 
specific to the drill pipe to be used in the well.
     Response: BSEE disagrees with the suggested change to 
specify that this requirement applies only to the drill pipe used or to 
be used in the well, since that point is already stated in Sec.  
250.732(b)(1)(i), and the same limitation is implied throughout Sec.  
250.732(b)(1).

Comments Related to Proposed Sec.  250.732(b)(1)(vi)--BOP Shearing Test 
Results

    Summary of Comments: Several commenters requested that BSEE revise 
the proposed requirement in Sec.  250.732(b)(1)(vi) that ``all [shear] 
testing results'' be provided to BSEE by changing ``all'' to 
``relevant.''
     Response: BSEE agrees with the commenter and has revised 
final Sec.  250.732(b)(1)(vi) by replacing ``all'' testing results with 
``relevant'' testing results. This change will ensure that the testing 
data provided to BSEE is applicable and relevant to the specific shear 
testing issues covered by Sec.  250.732(b)(1) and that other, non-
relevant testing results, which could cause confusion, are not 
submitted.

Comments Related to Proposed Sec.  250.732(b)(1)(iv)--Off-Center Pipe 
Shearing

    Summary of Comments: Multiple commenters stated that proposed Sec.  
250.732(b)(1)(iv)--regarding off-center pipe shearing--was inconsistent 
with proposed Sec.  250.734(a)(16), which requires operators to install 
shear rams that center drill pipe during shearing no later than 7 years 
from the publication of the final rule. One suggestion was to revise 
Sec.  250.732(b)(1)(iv) as follows: ``Ensures that the test 
demonstrates off-center pipe shearing capability within

[[Page 25951]]

the time period referenced in Sec.  250.734(a)(16)(i).''
     Response: BSEE disagrees with the comment about the 
inconsistencies between the compliance timeframes for the two 
referenced sections. The requirement in Sec.  250.734(a)(16) to center 
the drill pipe while shearing is important to help increase shearing 
capabilities and ensure effective shearing in an emergency. However, as 
discussed elsewhere, BSEE has determined that additional time is needed 
for such technology to continue to be developed, produced, acquired and 
installed, and thus proposed 7 years as a reasonable time to comply 
with that requirement. (See 80 FR 21510.) By contrast, the technology 
to perform off-center shearing is already in widespread use, and there 
is no reason to postpone the adoption of the testing requirements for 
that technology.

Comments Related to Proposed Sec.  250.732(b)(1)(iii)--Shear Test 
Documentation

    Summary of Comments: Several commenters stated that the requirement 
of Sec.  250.732(b)(1)(iii)--for documenting that the shear testing 
provides a reasonable representation of field applications--should be 
in accordance with current industry standards only. This includes 
shearing the drill pipe with zero wellbore pressure and zero tension. 
The commenter asserted that there is a safety risk when shearing a 
drill pipe in the lab with high pressure in the wellbore and flowing 
conditions.
     Response: BSEE does not agree with the commenter that a 
change is necessary to Sec.  250.732(b)(1)(iii). BSEE understands that 
the technological capabilities of shear testing are limited; however, 
BSEE also recognizes that advancements have been made to improve 
testing capabilities to better simulate field applications. Therefore, 
BSEE has not made any changes to this paragraph. BSEE expects all shear 
testing to be done in a safe manner to ensure personnel safety.

Comments Related to Proposed Sec.  250.732(b)(2)(ii)--Pressure 
Integrity Testing

    Summary of Comments: Several commenters stated that the proposed 
requirement in Sec.  250.732(b)(2)(ii) that pressure integrity testing 
demonstrate that the equipment will seal at the RWP of the BOP 
pressure, should be revised because it could create potential 
confusion. One commenter also said that the test pressure should be 
MASP/MAWHP, or the RWP of the sealing preventer above the uppermost 
shear ram, whichever is lower.
     Response: BSEE disagrees with the comment that this 
paragraph is unclear or confusing as written. BSEE also disagrees with 
the recommended changes to this provision. The testing described in 
Sec.  250.732(b)(2)(ii) is performed at a testing facility, while the 
commenter's suggested language apparently contemplates testing 
conducted on a rig.

Comments Related to Proposed Sec.  250.732(b)(3)--Calculations--MASP

    Summary of Comments: One comment was received from multiple 
commenters that the proposed requirement in Sec.  250.732(b)(3) for 
calculations include shearing and sealing pressures that are corrected 
for MASP should be revised. The comment stated that MASP/MAWHP should 
be limited to the RWP of the preventer above the uppermost shear ram, 
because it is not possible to have more than the RWP of the preventer 
above the shear ram.
     Response: BSEE disagrees with the commenter's recommended 
revision. The requirements of Sec.  250.732(b)(3) only apply to 
calculations identifying the sealing pressure for all pipe to be used 
in the well. The calculations are to be used to determine the 
applicability and use of the shearing components; it is the operator's 
responsibility to determine how the calculations are applied to the 
specific components on the rig. Therefore, no changes are necessary to 
this paragraph.

Comments Related to Proposed Sec.  250.732(c)--Facility Access

    Summary of Comments: Multiple commenters requested that BSEE revise 
Sec.  250.732(c) with regard to a BAVO having access to any facility 
associated with the BOP system during the review process. The comments 
requested that BSEE change the wording of ``access to any facility'' to 
``access to documentation.'' The comments asserted that this provision 
was too broad and implies that BAVOs have law enforcement rights.
     Response: BSEE disagrees. BAVOs must have access to the 
relevant facilities in order to perform the testing and certification 
functions necessary to ensure that BOPs function as intended to prevent 
well-control events. There is no basis for the suggestion that 
requiring operators to provide facility access to the BAVO--which the 
operator has retained to perform these functions on its behalf--confers 
any law enforcement authority on the BAVO.

Comments Related to Proposed Sec.  250.732(c)(2)--Verification of BOP 
System Testing

    Summary of Comments: One commenter suggested that the proposed 
requirement in Sec.  250.732(c)(2)--for verification that designs of 
the BOP system and individual components have been proven in a testing 
process that demonstrates the equipment's reliability in a way that is 
repeatable and reproducible--be cross-referenced to appropriate 
validation testing required in industry specifications (e.g., API 
Specs.16A/16C/16D).
     Response: BSEE disagrees with the commenter's suggestion 
that we reference specific industry standards in Sec.  250.732(c)(2). 
This paragraph is setting general requirements and is intended to be 
broad enough to allow for flexibility in verifying the component 
designs without limitation to any specific existing standard(s).

Comments Related to Proposed Sec.  250.732(c)(4)--API Spec. Q1

    Summary of Comments: One commenter suggested that quality control 
and assurance mechanisms referred to in Sec.  250.732(c)(4) require 
compliance with API Spec. Q1.
     Response: BSEE disagrees with the commenter's suggestion 
to reference specific industry standards in Sec.  250.732(c)(4). This 
paragraph sets general requirements and is intended to be broad enough 
to allow for flexibility in verifying that the fabrication, manufacture 
and assembly of BOP components and the BOP system use appropriate 
quality control and assurance mechanisms, without limiting the choices 
of such mechanisms.

Comments Related to Proposed Sec.  250.732(c)(4)--Quality Control and 
Assurance

    Summary of Comments: One industry commenter stated that the 
proposed requirement in Sec.  250.732(c)(4) that quality assurance and 
control mechanisms cover ``all contractors, subcontractors, 
distributors, and suppliers at every stage'' is overly broad and 
undefined. The commenter asserted that complying with such a broad 
requirement would take many years. The commenter suggested that BSEE 
revise this provision to read: ``The quality control, assurance 
requirements and material documentation specified by the industry 
standard(s) for the components and systems.''
     Response: BSEE does not agree. The commenter provided no 
explanation or support for its opinion or its recommended changes to 
the rule.

[[Page 25952]]

Therefore, BSEE has no basis to adopt the commenter's recommended 
change.

Comments Related to Proposed Sec.  250.732(d)--MIA Report

    Summary of comments: Multiple comments stated that the requirement 
in proposed Sec.  250.732(d) for an annual MIA report for subsea BOPs, 
BOPs used in HPHT environments, and surface BOPs on floating facilities 
would be redundant and unnecessary and would not increase the safety or 
reliability of BOP equipment. The comments asserted that each item to 
be included in the MIA report is already covered by the operators' SEMS 
plans, as required by BSEE's SEMS rules, or by operators' compliance 
with API Standard 53 requirements. Commenters also noted that the 
proposed rule requires adherence to OEM training recommendations that 
do not exist.
     Response: BSEE does not agree that the MIA reporting 
requirement is redundant or unnecessary. As previously discussed, 
although some of the technical issues that must be covered in an MIA 
report under Sec.  250.732(d) are related to certain issues that must 
be addressed in SEMS plans, there are also many differences between the 
contents of the MIA reports and SEMS plans. The primary purpose of the 
MIA report is to provide BSEE with the technical information that BSEE 
needs to carry out its responsibilities under OCSLA and part 250. By 
contrast, the purpose of the SEMS plans is to help the OCS industry and 
workforce to build a stronger safety culture and to improve safety and 
environmental performance through compliance with the policies and 
procedures in those plans.
    Similarly, while there are some matters covered in an MIA report 
that are also covered under API Standard 53, there are significant 
differences and certain types of information required in the MIA report 
are not covered by API Standard 53.
    The comment that the proposed rule would require compliance with 
non-existent OEM training recommendations does not warrant any change 
to the final regulation. It is already clear that Sec.  250.732(d)(6) 
only requires compliance with any OEM training requirements that 
actually exist.
    Summary of comments: Some comments asserted that proposed Sec.  
250.732(d)(6)--regarding verification in the MIA report that training 
for BOP personnel meets OEM requirements--would require adherence to 
OEM training recommendations that do not exist.
     Response: The proposed rule did not, and the final rule 
does not, state that an operator must provide training to BOP personnel 
that meets OEM training recommendations or requirements that do not 
exist; nor does BSEE intend that provision to be interpreted in that 
way. Accordingly, BSEE has modified final Sec.  250.732(d)(6) to 
clarify that training must include ``any applicable'' OEM requirements.

What are the requirements for a surface BOP stack? (Sec.  250.733)

    As provided for in the proposed rule, this section combines and 
revises several sections of the former regulations that established 
technical requirements for surface BOP stacks and related equipment. 
Paragraph (a) of this section specifies the point at which the surface 
BOP stack must be installed, sets minimum requirements for numbers and 
types of key surface stack components and equipment (e.g., remote-
controlled BOPs that include annulars, blind shear rams, and pipe 
rams), and specifies the shearing or closing and sealing capabilities 
that such equipment must have. If the blind shear ram could not cut 
electric-, wire-, or slick-lines under MASP an alternative cutting 
device must be on the rig floor during operations that can cut the wire 
before closing the BOP. Paragraph (b) sets additional requirements and 
related compliance dates for surface BOPs on floating production 
facilities. Paragraphs (c) and (d) establish requirements for choke and 
kill lines. BSEE has revised certain provisions in proposed Sec.  
250.733 in the final rule as discussed in the comment responses for 
this section and in part V.C of this document.

Comments Related to Proposed Sec.  250.733(a)--Risks of Manual Cutting 
Device

    Summary of comments: A commenter was concerned that BSEE may have 
underestimated the risks (of a fire or explosion) associated with using 
a separate manual cutting device as an alternative cutting device, 
under proposed Sec.  250.733(a)(1), during an emergency well-control 
situation where hydrocarbon vapors may be present on the rig floor. 
This commenter was also concerned that the speed and effectiveness of 
closing-in a well would be compromised by using a single blind shear 
ram and manual cutting device. Thus, this commenter asked that BSEE 
consider requiring a more robust, automated redundant blind shear ram 
closure system for all surface BOP systems.
     Response: BSEE does not agree with the recommended changes 
to the requirements for the alternative cutting device specified in 
paragraph Sec.  250.733(a)(1). This provision will be a substantial 
improvement over the current regulations, which do not impose any 
requirements for cutting any electric-, wire-, or slick-line. BSEE is 
evaluating additional shearing rams for surface BOPs and other advanced 
technology that may be capable of severing everything in the hole; 
however, more research and data are needed before BSEE decides whether 
technology such as that recommended by the commenter should be added to 
the rules. If research or study reports or other information becomes 
available to BSEE that warrants additional requirements, BSEE may 
propose such a revision in a future rulemaking.

Comments Related to Proposed Sec.  250.733(a)--Prescriptiveness of 
Requirements

    Summary of comments: Two commenters claimed that the proposed 
requirements in Sec.  250.733(a) would be too prescriptive; i.e., that 
ram placements and configurations should be established by the operator 
based on a risk assessment.
     Response: BSEE does not agree with the suggested changes 
to paragraph Sec.  250.733(a). This provision does not specify where 
the rams are to be placed and how they should be configured. Moreover, 
this paragraph simply restates the longstanding requirements of prior 
Sec.  250.441(a), which describes the type of BOP components that must 
be in the BOP stack, but not how they must be configured.

Comments Related to Proposed Sec.  250.733(a)--Compliance Timing

    Summary of comments: A commenter recommended that BSEE revise the 
compliance dates for implementation of the requirements under paragraph 
(a), suggesting 3 years (rather than the proposed 3 months) to comply 
and recommending that an annual status report be submitted to BSEE 
until the rig is in compliance.
     Response: BSEE agrees that an extension of the proposed 3-
month (from publication of the final rule) compliance date for Sec.  
250.733(a)(1) is warranted for certain elements, although the 3 years 
recommended by the commenter is unnecessary. As previously discussed 
(see part III of this preamble), BSEE is aware that some current 
technology is available to shear tubing with exterior control lines; 
accordingly, the effective date for shearing such tubing has been 
extended

[[Page 25953]]

to 2 years (from publication of the final rule) in order to allow 
operators to acquire and install (and, if necessary, to develop new or 
alternative) equipment to meet the requirements. However, the commenter 
provided no support for modifying the compliance date for any other 
elements of Sec.  250.733(a), nor is BSEE aware of any basis for doing 
so. Therefore, BSEE has not revised the compliance date for the 
remainder of Sec.  250.733(a).

Comments Related to Proposed Sec.  250.733(a)(1)--Shearing Requirements

    Summary of comments: Commenters asked BSEE to confirm that it 
intended to propose the exclusions from the blind shear ram shearing 
requirements in proposed Sec.  250.733(a)(1) for ``tool joints, bottom 
hole tools, and bottom hole assemblies that include heavy-weight pipe 
or collars.'' Although excluded in the regulatory text, the exclusions 
were not discussed in the preamble to the proposed rule.
     Response: BSEE understands that there is no such 
technology currently available that can shear such equipment. 
Additionally, if all of the shearing capability requirements of this 
rule are met, there is no need for the equipment to be able to shear 
equipment at the bottom of the hole. Accordingly, the proposed and 
final regulatory text for paragraph (a)(1) correctly excluded shearing 
requirements for tool joints, bottom hole tools, and bottom hole 
assemblies that include heavy-weight pipe or collars from shearing 
requirements was intended and was correctly included in the proposed 
rule, as well as in the final rule. The omission of any discussion of 
those exclusions in the preamble description of proposed Sec.  
250.733(a)(1) was inadvertent.

Comments Related to Proposed Sec.  250.733(a)(1)--Shearing Under MASP

    Summary of comments: A commenter was concerned about the proposed 
requirement that if the blind shear rams are unable to cut ``any 
electric-, wire-, or slick-line under MASP,'' an alternative cutting 
device must be used. The commenter asserted that the word ``any'' in 
that context is open-ended. The commenter suggested that the operator 
should be able to demonstrate that its blind shear rams can cut the 
lines intended for use rather than ``any'' possible lines.
     Response: BSEE does not agree with the commenter's 
apparent concern about paragraph Sec.  250.733(a)(1). The commenter did 
not fully explain its concerns, but BSEE assumes the commenter believed 
the provision required that the ram be capable of shearing any possible 
line. However, the proposed (and final) regulatory text simply refers 
to the electric-, wire-, or slick-line ``that is in the hole,'' not to 
hypothetical lines that are not in the hole.

Comments Related to Proposed Sec.  250.733(a)(1)--Shear Rams

    Summary of comments: Another commenter recommended adding language 
to paragraph Sec.  250.733(a)(1) to the effect that if the BOP stack 
has dual shear rams, and the lower shear ram can shear all drill pipe, 
then the upper shear ram only needs to seal against MASP, not to exceed 
the RWP of the preventer located directly above the shear ram.
     Response: BSEE does not agree with adding the language the 
commenter suggested. Since Sec.  250.733(a)(1) does not require dual 
shear rams to be used in a surface BOP stack, the commenter's suggested 
language appears to involve a hypothetical scenario outside the scope 
of the rule.

Comments Related to Proposed Sec.  250.733(a)(2)--Exterior Control 
Lines

    Summary of comments: Commenters recommended adding more exclusions 
to the proposed requirement that the pipe rams be able to close and 
seal on the tubular body of any drill pipe, workstring, and tubing 
under MASP. Specifically, the commenters asked that BSEE exclude pipe 
bodies with exterior control lines. Commenters emphasized that closing 
a ram preventer on tubing and exterior control lines (e.g., flat packs) 
is not currently achievable, nor is it a realistic expectation for the 
near future. The commenters claimed that since it is not possible to 
comply with this provision, the industry would be shut down in the Gulf 
of Mexico. Commenters suggested use of a risk assessment to identify 
additional mitigation measures or requiring the shear ram to be able to 
shear and seal the tubular with the items attached to the outside of 
the pipe.
     Response: As previously discussed, BSEE agrees that pipe 
rams currently cannot completely seal around tubing with exterior 
control lines. An annular is the only BOP component able to seal around 
tubing with exterior control lines and is only used for a low pressure 
situation, which is usually the case when running tubing with exterior 
control lines. Accordingly, BSEE has revised final paragraph (a)(2) to 
clarify that pipe rams are not required to seal tubing with exterior 
control lines and flat packs.

Comments Related to Proposed Sec.  250.733(a)--Pipe Rams and MASP

    Summary of comments: Another commenter recommended removing the 
requirement from Sec.  250.733(a) that pipe rams must be able to close 
and seal under MASP, since Sec.  250.730(a) already establishes that 
the BOP (including pipe and variable bore rams) must have an RWP 
greater than MASP, and thus the two provisions would effectively be 
redundant.
     Response: BSEE is not revising paragraph (a) as the 
commenter suggested. The capability of pipe rams to close and seal 
under MASP is important because the MASP predicts the highest pressure 
to be encountered at the surface of the well and is used in ensuring 
that BOPs can function as intended. Although Sec.  250.730(a)(3) 
establishes essentially the same requirement for all BOPs, reiterating 
the requirement in Sec.  250.733(a)(2) for surface BOPs emphasizes the 
importance of this capability without imposing any additional burden on 
the operator.

Comments Related to Proposed Sec.  250.733(b)--Surface Dual Shear Rams

    Summary of comments: Several commenters asserted that BSEE should 
not require dual shear rams on surface BOPs on any floating production 
facility. Other commenters requested that BSEE conduct a full risk 
assessment of the impact of such a dual shear ram requirement before 
making it part of a final rule. They asserted that the negative 
consequences (related to weight, height and other structural limits on 
the facility) of adding such capabilities might increase rather than 
reduce risks.
    Other comments stated that the rule is not clear about the 
requirements for existing floating production facilities with surface 
BOP stacks. Some recommended that BSEE allow ``grandfathering'' for 
existing and under-construction facilities, since the proposed 
requirements could create feasibility issues or additional costs that 
could make continued activity on such rigs economically unviable. Some 
commenters also recommended that BSEE allow operators to submit a risk 
assessment for each existing floating facility to determine whether the 
facility needs dual shear rams to reduce risk and allow those 
facilities to ``opt-out'' of the requirement (as provided in API 
Standard 53).
     Response: BSEE disagrees with the suggestions that the 
dual shear ram requirement for surface BOPs on floating production 
facilities be

[[Page 25954]]

eliminated from the final rule altogether. As indicated in the proposed 
rule, Sec.  250.733(b) is consistent with BSEE policy that surface BOPs 
on floating production facilities (like subsea BOPs) generally present 
higher risks than surface BOPs on fixed facilities. (See 80 FR 21522.) 
In addition, BSEE believes that overall performance of shearing 
equipment must improve over the longer term to ensure that the 
equipment can successfully shear a drill stem in an emergency. (See 80 
FR 21509.) BSEE also believes that the industry is already moving 
toward eventual use of dual shear rams in surface BOPs on new floating 
production facilities.
    For the same reasons, BSEE disagrees with the recommendation that 
BSEE do a risk assessment to justify the dual shear ram requirement or 
allow operators with surface BOPs on floating facilities to opt-out of 
the requirement if they perform a risk assessment. BSEE already 
addressed the latter suggestion in the proposed rule in connection with 
the dual shear ram requirement for subsea BOPs, and stated that an 
operator whose circumstances make the dual shear ram requirement 
infeasible can seek approval for alternative equipment or procedures 
under current Sec.  250.141. (See 80 FR 21509-21510.)
    However, BSEE understands several of the practical concerns related 
to applying the dual shear ram requirement to existing facilities. For 
example, BSEE agrees that the dual shear ram requirement, if applied to 
existing floating production facilities, or facilities under 
construction or in advanced stages of development, potentially could 
have negative personnel safety and structural impacts due to the added 
weight of the dual shear ram equipment and to the height and structural 
limits of those facilities. Accordingly, BSEE has revised final 
paragraph (b)(1) to apply the dual shear ram requirements to surface 
BOPs that are ``installed'' on floating facilities 3 years after 
publication of the final rule.\18\ In effect, this means that surface 
BOPs on floating production facilities that exist now, or facilities 
that are installed on the OCS in the near-term, will not need to meet 
the dual shear ram requirement unless those BOPs are removed or 
replaced 3 or more years after the rule is published.\19\ This 3-year 
compliance period will give the industry adequate time to plan, design, 
and develop surface BOP equipment that can meet the dual shear ram 
requirement on new floating production facilities.
---------------------------------------------------------------------------

    \18\ The revised language of final Sec.  250.733(b)(1) also 
clarifies that existing floating production facilities do not need 
to retrofit or replace their BOPs in order to meet the dual shear 
requirement in 5 years, as the proposed language might have implied 
by its cross-reference to the dual shear ram requirement for subsea 
BOPs in proposed Sec.  250.734(a)(1), which included a 5-year 
compliance date for those subsea BOPs.
    \19\ The requirement that surface BOPs installed 3 or more years 
after publication of the final rule must comply with the 
requirements of Sec.  250.734(a)(1) does not extend the 5-year 
compliance date for dual shear rams as specified in Sec.  
250.734(a)(1). Specifically, any surface BOP installed between 3 
years and 5 years after publication of the final rule must comply 
with the dual shear ram requirement no later than 5 years after 
publication of the final rule; any surface BOP installed 5 or more 
years after publication of the final rule must comply with the dual 
shear ram requirement when the surface BOP is installed.
---------------------------------------------------------------------------

    Final Sec.  250.733(b)(1) reasonably balances the practical 
concerns related to requiring dual shear rams on BOPs at existing 
floating facilities, or those to be constructed in the near-term, with 
the importance of improving the capabilities of surface BOPs on such 
facilities in the longer term. In fact, existing floating production 
facilities generally are less likely to have an event requiring a dual 
shear ram BOP, given that the majority of such facilities are located 
in depleted fields, with lower pressures due to ongoing production from 
those fields.\20\
---------------------------------------------------------------------------

    \20\ In addition, there are large amounts of offset well data 
for those existing facilities in depleted fields (due to the 
multiple wells previously drilled into the same geologic formations 
and reservoirs), which allows for better prediction of drilling 
parameters. Similarly, because of the prior production of the 
reservoirs at such facilities, the reservoir parameters and 
characteristics are generally well established.
---------------------------------------------------------------------------

Comments Related to Proposed Sec.  250.733(b)(2)--Dual Bore Risers

    Summary of comments: Comments on Sec.  250.733(b)(2) focused on the 
meaning of the proposed requirement for dual bore risers on existing 
facilities. Commenters requested clarification that existing facilities 
currently using single bore strings may continue to do so. They noted 
that there are currently many single bore risers being used 
successfully on existing facilities, which should not be required to 
install new dual bore riser systems. Some commenters argued that this 
would present significant feasibility issues, with substantial economic 
consequences, but without significant safety benefits. A commenter also 
suggested that there are other safety precautions (such as dual 
barriers) that can improve safety without converting single bore risers 
to dual bore. In addition, some comments recommended changing the 
terminology from ``dual bore riser configuration'' to ``dual casing 
configuration'' to better align with the terminology used in industry.
     Response: BSEE does not agree that it is necessary to 
revise the dual bore riser requirements in paragraph Sec.  
250.733(b)(2). The commenters' concerns apparently are based on the 
misinterpretation that BSEE intended to require that all single bore 
risers be converted to a dual bore riser configuration. That was not 
BSEE's intention, as is evident from a careful reading of the proposed 
rule. The language in proposed, and now final, Sec.  250.733(b)(1) 
applies only to risers installed after the effective date of the final 
rule (i.e., 90 days from the date the final rule is published). If any 
operator already has existing plans to install a single bore riser 
after the final rule takes effect, the operator should contact BSEE 
and, if necessary, may request approval for alternative compliance 
under Sec.  250.141.
    BSEE also has not made the requested change from ``dual bore 
riser'' to ``dual casing'' since ``dual bore riser'' is an established 
and well-understood industry term.

Comments Related to Proposed Sec.  250.733(b)(2)--Most Extreme 
Conditions

    Summary of comments: Another commenter recommendation was to change 
the requirement to design for the ``most extreme'' conditions to a 
requirement to design for ``anticipated'' operating and environmental 
conditions. A commenter also requested that BSEE clarify that 
monitoring of the annulus between the risers means monitoring for 
pressure during operations.
     Response: BSEE agrees with this comment and has revised 
Sec.  250.733(b)(2) by removing the term ``most extreme'' and replacing 
it with ``maximum anticipated,'' and added to paragraph Sec.  
250.733(b)(2)(i) that the riser must be monitored for pressure during 
operations.

Comments Related to Proposed Sec.  250.733(c)--Side Outlet Valves

    Summary of comments: A commenter recommended deleting the proposed 
requirement for side outlet valves to hold pressure in both directions, 
stating that there is no scenario under which these valves would see 
pressure in a surface application. The commenter asserted that this 
requirement for two-way valves should only apply to subsea BOPs and 
recommended that BSEE should revise the text for surface BOPs to only 
require that side outlet valves be able to hold pressure from the 
direction of flow.

[[Page 25955]]

     Response: BSEE does not agree with these comments. BSEE 
understands that side outlet valves are already in use and on surface 
BOPs are normally designed to hold pressure from both directions. Thus, 
there is no factual basis to revise this provision.

Comments Related to Proposed Sec.  250.733(d)--Remote-Controlled Valve

    Summary of comments: A commenter emphasized that, in an emergency 
case, a remote-controlled valve on a kill-line is easier and faster to 
access and operate. The commenter recommended that BSEE require that 
the valve on such lines be capable of both remote and manual operation 
if power for a remotely operated valve is not available, instead of the 
proposed language allowing the operator to use either a manual valve or 
remotely controlled valve.
     Response: BSEE disagrees with the suggested change. Due to 
the functions and intended use of the kill line, remote operation is 
not necessary, although the operator has the option to use both manual 
and remote operated valves.

Comments Related to Proposed Sec.  250.733(e)--Hydraulically Operated 
Locks

    Summary of comments: Commenters raised several concerns about the 
proposed requirement to install hydraulically operated locks on surface 
BOP stacks. Some commenters suggested deleting the requirement 
altogether; others suggested only requiring hydraulic locks on all 
surface BOPs on HPHT wells. Commenters asserted that this technology is 
not available for a majority of surface BOP systems and that there is 
no technical basis to require hydraulically operated locks on all 
surface BOPs. Commenters suggested, as an alternative, revising the 
requirement to ensure that BOP ram locks are in working order and 
accessible. Some commenters asserted that, while hydraulically operated 
locks remove the operator from the vicinity, and thus may provide more 
protection for some rig personnel than manually operated locks, they 
are not as reliable as manual locks, which are simpler in design.
    Commenters also pointed out that, in a catastrophic well-control 
incident, the ability to charge or recharge the hydraulic closing unit 
may be lost. In addition, commenters also raised concerns regarding the 
timing and costs related to the proposed requirement, stating that 
compliance within 3 months would not be achievable for rigs that do not 
already have hydraulically operated locks and the necessary control 
systems. Commenters stated that, depending on the timing of the 
requirement, manufacturing, delivery, and installation of this 
equipment could lead to downtime for drilling rigs with surface BOPs. 
Commenters stated further that OEMs would not have the inventory on 
shelves to fulfill orders within 90 days.
    Some commenters suggested an effective date 3 years after 
publication of the final rule, while others suggested that 5 years 
would provide enough time to design and manufacture any new components, 
procure and install, and obtain testing and verification by a BAVO. One 
commenter suggested that, if BSEE extends the compliance date, it could 
require an annual status report to BSEE until rigs are in compliance.
     Response: BSEE has deleted proposed Sec.  250.733(e) from 
the final rule, since final Sec.  250.735(g) adequately addresses the 
locking requirements for surface BOPs, and the circumstances covered by 
proposed Sec.  250.733(e) do not warrant an additional requirement at 
this time. As described later in this document, BSEE has also revised 
final Sec.  250.735(g) based on comments concerning both proposed Sec.  
250.733(e) and proposed Sec.  250.735(g).

Comments Related to Proposed Sec.  250.733(f)--BOP Repair Certification

    Summary of comments: One commenter objected to the proposed 
requirement that a BAVO certify that it has reviewed repairs to a 
surface BOP in an HPHT environment and that the BOP is fit for service, 
pointing out that this provision is redundant with proposed Sec.  
250.738(b). Other commenters raised other concerns with, and requested 
other changes to, proposed Sec.  250.733(f), including claiming that 
the proposed regulation inappropriately places the primary 
responsibility for verifying repairs on the BAVOs, instead of the 
operator.
     Response: BSEE agrees that proposed Sec.  250.733(f) would 
be redundant with Sec.  250.738(b); therefore, BSEE has deleted 
paragraph (f) from Sec.  250.733 in the final rule.

What are the requirements for a subsea BOP system? (Sec.  250.734)

    As described in the proposed rule, this section combines and 
revises provisions of former sections that established requirements for 
subsea BOP systems. Paragraph (a) requires dual shear rams and 
specifies the shearing requirements as well as requirements for the BOP 
control system, subsea accumulator capacity, ROV intervention 
capabilities, personnel training, and certain BOP equipment and 
capabilities. Paragraph (b) establishes procedural and testing 
requirements for resuming operations after operations are suspended to 
make repairs to the subsea BOP system. Paragraph (c) sets out APD 
requirements related to drilling a new well with a subsea BOP. BSEE has 
revised certain provisions in proposed Sec.  250.734 in the final rule 
as discussed in the comment responses for this section and in parts 
V.B.2, V.B.5, and V.C of this document.

Comments Related to Proposed Sec.  250.734--Risk-Based Approach

    Summary of comments: Commenters stated that proposed Sec.  250.734 
uses overly prescriptive language, similar to the language used in the 
proposed BOP surface stack requirements. They also asserted that the 
proposed rule would increase the minimum equipment requirements beyond 
API Standard 53 and seek to introduce one-size-fits-all configurations. 
Commenters suggested re-writing the proposed rules with a risk-based 
approach that would enable BSEE to create a set of rules that could 
meet the desired intent without creating a number of unintended side 
effects. They assert that a risk-based approach would also be more 
suited to the constant evolution of drilling processes and would 
encourage technological innovation and efficiency.
     Response: BSEE recognizes the advantages and disadvantages 
of both approaches and understands that each approach can be effective 
and appropriate for specific circumstances. As explained in the 
proposed rule, this rulemaking uses a hybrid approach incorporating 
prescriptive requirements, where necessary, as well as many 
performance-based requirements. (See, e.g., 80 FR 21509.) BSEE believes 
that this provision, as promulgated in the final rule, strikes the 
appropriate balance between prescriptive and performance-based 
requirements. The final provision is intended to ensure that subsea BOP 
systems include, at a minimum, certain types of components and 
processes that, based on BSEE's experience and analyses of past 
incidents, will help prevent future blowouts. However, Sec.  250.734(a) 
does not mandate a one-size-fits-all approach. To the contrary, the 
final rule allows operators to exceed the prescribed requirements 
(e.g., to use more than the required 5 remotely-controlled, 
hydraulically operated BOPs) if the operators wish to do so. Nor does 
this provision mandate the use of any manufacturer's equipment or 
otherwise discourage the development of new and better technology that 
will meet or exceed the requirements of the rule.

[[Page 25956]]

BSEE expects equipment manufacturers, operators and others to continue 
exploring and developing new, more efficient ways to meet these 
requirements.

Comments Related to Proposed Sec.  250.734(a)--Device Connections

    Summary of comments: A commenter asserted that the table in Sec.  
250.734(a)--listing requirements for operating with a subsea BOP--does 
not address connections between devices in the BOP stack, or 
methodologies for disconnection and/or reassembly or capping or 
containment points on those devices. The commenter stated that BSEE 
must address points of connection between the devices and capping and 
containment points to reduce the uncertainty of the procedures used in 
the event of failure. The commenter recommended that BSEE include a new 
section describing equipment and/or devices used to connect each 
component in the BOP stack, and a separate section describing capping 
and containment points and methods at all such locations on the BOP 
stack.
     Response: BSEE disagrees with the commenter that capping 
or containment points should be included in this section and has not 
made the suggested changes to paragraph (a). Containment requirements 
are covered adequately under proposed and final Sec.  250.462.

Comments Related to Proposed Sec.  250.734(a)--MASP

    Summary of comments: Some commenters questioned BSEE's use of MASP 
in this section, asserting that MASP is not the appropriate industry 
term for subsea BOPs. They recommended using MAWHP, as defined in API 
RP 96 and API Standard 53.
     Response: As previously explained in connection with 
similar comments on Sec.  250.730, MASP must be defined for the 
specific operation, and for a subsea BOP, the MASP must be taken at the 
mudline, as explained in Sec.  250.730(a). For subsea BOPs, MASP taken 
at the mudline is the same as MAWHP. BSEE uses the term MASP in its 
existing regulations and disagrees with the suggestion that it would 
cause confusion in this context.

Comments Related to Proposed Sec.  250.734(a)--Compliance Timing

    Summary of comments: Multiple commenters expressed concerns about 
the compliance dates associated with this section and provided examples 
of why an extended compliance date is necessary. The aspects of the 
provisions that were of most concern included the lack of technology 
needed for shearing flat packs, slick-line, and other exterior control 
lines; procurement of additional accumulators needed for the closure of 
dual shear rams; installation of ram position indicators; and pipe 
centering capabilities. Although many commenters suggested that a 5-
year implementation timeframe would be acceptable, others suggested 
longer timeframes for certain provisions.
     Response: BSEE agrees that there are some provisions in 
Sec.  250.734(a), and other sections of this rule, for which operators 
will need more time for compliance than proposed. Accordingly, the 
final rule extends the compliance dates for specific requirements under 
paragraph (a)(1) as well as for the specific requirements under 
paragraphs (a)(1)(ii), (a)(3)(iii), (a)(15), and (a)(16)(i). More 
detailed discussion of the extended compliance timeframes is provided 
in part III of this preamble.

Comments Related to Proposed Sec.  250.734(a)--Surface Casing Setting 
Point

    Summary of comments: A commenter stated that proposed Sec.  
250.734(a) was unclear as to what conditions would lead the District 
Manager to require an operator to install a subsea BOP before reaching 
the surface casing setting point. This commenter asserted that 
prematurely installing a subsea BOP and shutting in on a kick before 
installation of surface casing would increase the risk of broaching to 
the seafloor.
     Response: BSEE clarified final Sec.  250.734(a) by stating 
that the subsea BOP system must be installed before conducting 
operations if the well is already deepened beyond the surface casing 
setting point. Other situations that might require installation of the 
BOP below the conductor casing will be decided on a case-by-case basis 
by the District Manager. It would be premature to speculate on specific 
circumstances that would warrant such a decision, but the District 
Manager would certainly take into account whether installation of the 
BOP is likely to cause a broach or other increased hazard. If an 
operator has any concerns or questions about a specific factual 
scenario, it may contact the appropriate District Manager for 
assistance.

Comments Related to Proposed Sec.  250.734(a)(1)--Compliance Timing

    Summary of comments: A commenter observed that while BSEE proposed 
requiring a second blind shear ram for some BOPs, the rule would also 
allow 5 years for operators to implement this critical safeguard. 
Another commenter stressed that given the importance of dual blind 
shear rams to offshore drilling safety, all current and future blowout 
preventers should be equipped with these devices, and BSEE should 
reduce the time required for compliance with this provision.
     Response: As provided in the proposed rule (see 80 FR 
21509-21510), BSEE agrees that the dual shear ram requirements are 
important to improving safety and environmental protection, consistent 
with recommendations arising from the Deepwater Horizon incident. 
However, the existing regulations did not require dual shear rams. BSEE 
believes that operators generally follow API Standard 53 regarding when 
dual shear rams should be used, based on the BOP classification. BSEE 
is aware that not all subsea BOPs have dual shear rams yet, and that 
acquiring and installing such equipment presents significant practical, 
technical and economic challenges. Accordingly, as discussed previously 
in the proposed rule (see 80 FR 21511) and this document, BSEE 
determined that 5 years is an appropriate timeframe for operators to 
obtain and install the necessary equipment for all subsea BOPs.

Comments Related to Proposed Sec.  250.734(a)(1)--Dual Shear Rams

    Summary of comments: Commenters raised various concerns about the 
proposed requirement for dual shear rams and the placement of BOPs. A 
commenter stressed that OEM equipment limitations restrict shear and 
seal capability of blind shear rams, and suggested that the regulations 
follow section 7.6.11.7.11 of API Standard 53, which states that ``[i]f 
a single ram is incapable of both shearing and sealing the drill pipe 
or tubing in use, the emergency and secondary systems shall be capable 
of closing two rams; one that will shear and one that will seal 
wellbore pressure.''
     Response: BSEE does not believe that one shear ram can 
ensure the ability of a subsea BOP to shear a drill string in the event 
of a potential emergency. The various investigations of the Deepwater 
Horizon incident recommended increasing the shearing capabilities of 
the BOP, including the use of dual shear rams on subsea BOPs. BSEE 
determined that use of dual shear rams would increase the likelihood 
that a drill string can be sheared, and ensures the well can be shut in 
and secured, by requiring that a shearable component is opposite a 
shear ram. BSEE also determined that merely requiring compliance with 
API Standard 53, which includes a procedure for

[[Page 25957]]

``opting-out'' of the dual shear ram provision, cannot provide the same 
level of assurance. (See 80 FR 21510-21511.) If there are unique 
circumstances that prevent the use of dual shear rams, operators would 
be able to apply for the use of alternative procedures or equipment 
under existing Sec.  250.141.

Comments Related to Proposed Sec.  250.734(a)(1)--Existing Wells

    Summary of comments: A commenter remarked that the requirements in 
this section are reasonable for new wells, but that it may be 
appropriate to allow 4[hyphen]ram BOPs on some existing wells with 
older wellheads. The commenter also said that the use of heavier/taller 
BOP stacks may potentially induce higher bending moments on the 
wellhead and BOP stack that will reduce the overall safety provided by 
the BOP.
     Response: BSEE disagrees with the comment about allowing a 
4-ram BOP on existing wells with older wellheads. BSEE determined that 
a 5-ram BOP is appropriate due to the high potential of a significant 
well-control event, including at facilities with older wellheads. 
However, if there are unique circumstances (such as a concern with 
potentially higher bending moments on some older wellheads) that might 
warrant the use of a 4-ram BOP for a specific well, operators would be 
able to apply for the use of alternative procedures or equipment under 
existing Sec.  250.141.

Comments Related to Proposed Sec.  250.734(a)(1)--Shear Ram Placement

    Summary of comments: Commenters asserted that the proposed 
requirement for the placement of non-sealing shear rams below the 
sealing shear rams conflicts with API Standard 53. Some comments 
suggested that BSEE revise paragraph (a)(1) to provide that any non-
sealing shear ram must be installed below at least one sealing shear 
ram. Others recommended that the operators use a documented risk 
assessment to establish the fixed ram configuration as provided by API 
Standard 53. A commenter noted that there are rigs where 3 shear rams 
with casing shears are installed between two blind shear rams and in 
many instances the casing shear in the middle is the best 
configuration. Another commenter noted that it may be preferable to 
have a casing shear ram in between two sets of blind shear rams.
     Response: BSEE agrees with the commenter about requiring 
that any non-sealing shear ram must be installed below at least one 
sealing ram. This provides flexibility for sealing the well after 
shearing with non-sealing shear rams. The pipe can fall in the hole if 
not hung off, or the pipe can be lifted clearing the upper sealing ram. 
Accordingly, BSEE has revised final paragraph (a)(1)(ii) to read 
``[a]ny non-sealing shear ram(s) must be installed below a sealing 
shear ram(s).''
    However, BSEE is not requiring a risk assessment by the operator as 
the method for determining the order of the minimum requirements for 
one blind shear ram and one shear ram. If multiple redundant shearing 
rams are included, BSEE recommends a risk assessment, but one is not 
required. If there are unique circumstances that indicate that some 
configuration other than those specified in this paragraph may be 
warranted, operators would be able to apply for the use of alternative 
procedures or equipment under existing Sec.  250.141.

Comments Related to Proposed Sec.  250.734(a)(1)(i)--Exterior Control 
Lines

    Summary of comments: Some commenters recommended adding an 
exclusion from the pipe ram sealing requirement in paragraph (a)(1)(i) 
for sealing on pipe with exterior control lines and umbilicals 
attached.
     Response: As discussed previously in this document, BSEE 
agrees with the comment about pipe rams not being able to seal around 
tubing with exterior control lines and flat packs. An annular is the 
only BOP component able to seal around tubing with exterior control 
lines and an annular is usually used for a low pressure situation, 
which is usually the case when running tubing with exterior control 
lines. Thus, BSEE revised paragraph (a)(1)(i) in the final rule to 
exclude tubing with exterior control lines and flat packs from the pipe 
ram sealing requirement, but requiring that (within 2 years) the shear 
rams be able to cut and seal the tubing with exterior control lines in 
the hole.

Comments Related to Proposed Sec.  250.734(a)(2)--Dual-Pod Control 
System

    Summary of comments: Commenters stated that the proposed rule 
prescriptively dictates that all subsea BOPs must have a dual-pod 
control system. They asserted that API Standard 53 adequately addresses 
redundancy of these systems without requiring all subsea BOPs to have 
dual-pod controls. A commenter also asserted that this provision would 
tie the industry to the prescribed current methodology without room to 
change or improve, and suggested that BSEE revise Sec.  250.734(a)(2) 
to require subsea BOPs to ``[h]ave a fully redundant subsea control 
system to ensure proper and independent operation of the BOP system.''
     Response: BSEE agrees with the comments suggesting that 
the proposed requirement for dual-pod controls could have proven unduly 
restrictive, and that requiring redundant pod controls would provide 
more flexibility and room for improvement while providing at least as 
much protection as the proposed language. Accordingly, BSEE has revised 
final Sec.  250.734(a)(2) by replacing ``dual pod control system'' with 
``redundant pod control system.'' This change will also align the pod 
requirement in the regulations with the language of API Standard 53.

Comments Related to Proposed Sec.  250.734(a)(3)--Fast Closure of BOP 
Components

    Summary of comments: Commenters asked BSEE to clarify the 
requirements under proposed paragraph Sec.  250.734(a)(3), related to 
``fast closure of the BOP components'' and ``operate all critical 
functions.'' They indicated that BSEE did not define the terms ``fast 
closure'' and ``critical functions'' in the rule, noting that these 
terms are defined in API Standard 53.
     Response: Although the API Standard 53 definition of 
``fast closure'' is one appropriate way to understand this term, it is 
not the only possible appropriate way. Thus, BSEE does not believe it 
is necessary to limit the meaning of ``fast closure'' in the 
regulations to the API Standard 53 definition. However, BSEE agrees 
with the commenter about the possibility of confusion and the need to 
define ``critical functions.'' Accordingly, BSEE revised final Sec.  
250.734(a)(3)(i) to specify that the critical functions are to 
``[o]perate each required shear ram, ram locks, one pipe ram, and 
disconnect the LMRP.'' These critical functions are the same as those 
defined in API Standard 53.

Comments Related to Proposed Sec.  250.734(a)(3)(i)--Subsea Accumulator 
Capacity

    Summary of comments: Commenters also questioned the proposed 
requirement in Sec.  250.734(a)(3)(i) for additional subsea accumulator 
capacity in case of the loss of power fluid connection to the surface. 
They emphasized that if there is a loss of the power fluid connection 
to the surface, then there also will probably be a loss of control from 
the surface. In that case, there would be no logical reason to require 
accumulator capacity to operate all choke and kill outlet valves.

[[Page 25958]]

     Response: BSEE agrees with the comment and has removed the 
reference to choke and kill side outlet valves, replacing it with a 
reference to ram locks, in final Sec.  250.734(a)(3). This change is 
also consistent with the operations of critical functions.

Comments Related to Proposed Sec.  250.734(a)(3)(iii)--Dedicated 
Independent Accumulator Bottles

    Summary of comments: Commenters requested clarification of the 
intent and scope of the requirement in proposed Sec.  
250.734(a)(3)(iii) for ``dedicated independent'' accumulator bottles, 
located subsea for the autoshear, deadman, and EDS systems. Commenters 
asserted that this is a major deviation from API Spec. 16D and API 
Standard 53, which allow surface accumulator bottles to contribute to 
the EDS sequence. Complying with the proposed requirement would mean 
locating additional accumulator bottles on the subsea BOP stack, which 
commenters stated would pose practical and technical concerns due to 
inherent space limitations for subsea BOP systems, and could also 
exceed the capacities of the BOP crane, BOP frame, rig substructure, 
and BOP carts. Also, commenters asserted that more subsea accumulator 
bottles could both impede the ROV from seeing areas of the stack 
critical to troubleshooting during abnormal situations and create 
additional leak paths. In addition, commenters noted that the extra 
accumulator bottles would have to be removed each time the BOP is 
serviced, increasing safety risks from handling the bottles. As an 
alternative to the proposed requirement, commenters suggested that BSEE 
require one subsea accumulator bank, to be shared by autoshear, 
deadman, EDS, acoustic and other critical functions, as provided by API 
Standard 53.
    Commenters also expressed concerns about the proposed timeframe (3 
months from publication of the final rule) for complying with the new 
accumulator requirements, given design and engineering issues and 
potential problems with acquiring and installing sufficient accumulator 
bottles and related equipment. Most of those commenters stated that 5 
years would be an appropriate timeframe for overcoming those problems.
     Response: BSEE agrees with many of the commenters' 
concerns, and has revised final Sec.  250.734(a)(3) to clarify that 
subsea BOP accumulators must have enough capacity to provide pressure 
for critical functions, as specified in final Sec.  250.734(a)(3)(i), 
and must have accumulator bottles that are dedicated to, but may be 
shared between, autoshear and deadman functions. The final rule does 
not require dedicated capacity for the EDS. These clarifications would 
eliminate most of the concerns about having to locate additional 
bottles subsea. BSEE also agrees that the proposed timeframe for 
compliance would be inadequate, even for the revised subsea accumulator 
requirements, given the need to design, develop, and implement 
solutions to the potential structural and engineering problems 
associated with acquiring, storing, and installing new accumulator 
bottles and related equipment. Accordingly, after review of the 
comments, BSEE has revised the compliance date for the accumulator 
requirements in paragraph (a)(3)(iii) to 5 years after publication of 
the final rule, as suggested by several commenters. This change also 
corresponds to the proposed (now final) 5-year compliance date for the 
final dual shear ram requirements, which likely would be the first time 
that the new subsea accumulator requirements would be needed in the 
event of an emergency. Thus, extending the compliance date for Sec.  
250.734(a)(3)(iii) would not adversely affect safety or the environment 
compared to the proposed rule. For a more detailed discussion of the 
accumulator revisions, see part V.B.2 of this document.

Comments Related to Proposed Sec.  250.734(a)(3)(ii)--Subsea 
Accumulator Capability

    Summary of comments: Commenters requested clarification of the 
requirement in proposed Sec.  250.734(a)(3)(ii) for subsea accumulator 
capability to deliver fluid to each ROV function. A commenter 
recommended that BSEE allow alternative options, such as independent 
accumulator bottles to supply the hydraulic power. Commenters noted 
that these systems can be used in conjunction with the ROV flying 
leads. Commenters also suggested that, instead of being required for 
ROVs, the primary purpose of subsea accumulator bottles should be to 
deliver fluid under pressure to provide fast closure of the components 
in an emergency situation. Also, commenters asserted that ROVs 
themselves should be able to recharge the bottles to perform other 
functions if necessary.
     Response: BSEE does not agree that the suggested changes 
to Sec.  250.734(a)(3)(ii) are necessary. This provision does not 
specify or limit the methods or devices that could be used to provide 
the necessary fluid to each ROV function. The ROVs must be capable of 
receiving the fluid from the accumulator, but BSEE is not restricting 
the use of other options, such as sand units. The rule simply requires 
that the subsea BOP have the capability of delivering the fluid to each 
ROV function.

Comments Related to Proposed Sec.  250.734(a)(4)--ROV Intervention 
Capability

    Summary of comments: Commenters raised several concerns with the 
proposed requirement that subsea BOPs must have ROV intervention 
capability. Some commenters emphasized that the primary purpose of ROV 
intervention capability (hot stab) should be to secure the well and 
unlatch the LMRP, if required. The commenters claimed that the proposed 
new requirements for ROVs will require considerably more ROV panels and 
functions. This will add leak points and test points, thus reducing the 
overall reliability of the system, reducing the availability of ROV 
access, reducing access for maintenance activities on the stack, and 
increasing the complexity of the BOP system. The commenters asserted 
that this will lead to increased maintenance costs. They also indicated 
that it will result in extra time and safety risks for ROV operators 
(i.e., from firing the wrong function due to the increased number of 
ROV functions). Commenters also asserted that, due to likely equipment 
delivery delays, implementation of this regulation would require 
extended periods of downtime for operating rigs. Commenters noted that 
this paragraph exceeds the critical functions provisions in API 
Standard 53. These commenters recommended that BSEE revise this 
provision to refer to API Standard 53 for defining critical functions 
for ROV capabilities.
     Response: BSEE agrees with the comment that the proposed 
rule would require adding significant new ROV functions, and that API 
Standard 53 provides an appropriate description of critical ROV 
functions (such as opening and closing each shear ram, and LMRP 
disconnect). Limiting the number of functions required for the ROVs 
will significantly decrease the possibility of creating new leak paths, 
help reduce complexity of the BOP system, and minimize any rig downtime 
for equipment changes. Accordingly, BSEE revised final Sec.  
250.734(a)(4) to limit the ROV functions to the critical functions 
which are now specified in that paragraph, and which is consistent with 
the definition of critical functions in API Standard 53.

[[Page 25959]]

Comments Related to Proposed Sec.  250.734(a)(5)--ROV Crew Training

    Summary of comments: A commenter requested that BSEE clarify 
whether the proposed requirement for maintaining ROVs and having a 
trained ROV crew on each rig is intended to impose requirements over 
and above those of the existing requirements of subparts O and S of 
part 250.
     Response: The personnel training requirements of Sec.  
250.734(a)(5), which include applicable training requirements for 
subparts O and S, apply to the ROV crew training required by Sec.  
250.734(a)(5). Section 250.734(a)(5) potentially goes go beyond subpart 
O, however, in that it also requires that personnel authorized to 
operate an ROV must have a comprehensive knowledge of BOP hardware and 
control systems. The training provisions for SEMS under Sec.  250.1915 
require operators to establish a training program so that all personnel 
are trained in accordance with their duties and responsibilities to 
work safely and are aware of potential environmental impacts. This 
provision sets out specific training requirements for the ROV crew. 
There are no inconsistencies between Sec.  250.734(a)(5) and subparts O 
and S. Accordingly, BSEE made no changes to the final rule based on 
this comment.

Comments Related to Proposed Sec.  250.734(a)(5)--ROV Crew Training

    Summary of comments: While several commenters supported the 
proposed requirements for maintaining an ROV and training the ROV crew, 
some recommended that training of ROV pilots on stabbing into an ROV 
intervention panel should not be limited to simulators, as suggested by 
the proposed rule; real-world, on-the-job training is also valuable. 
Thus, one commenter also suggested changing ``simulator training'' to 
``competence training.''
     Response: BSEE agrees with the comment about the value of 
on-the-job training, but notes that Sec.  250.734(a)(5)'s requirement 
for simulator training does not preclude other, additional training 
methods, including on-the-job training; thus, no change to regulatory 
language is warranted in this regard. Nor did the commenter provide any 
other reason to replace simulator training with ``competence 
training.''

Comments Related to Proposed Sec.  250.734(a)(5)--ROV Crew Requirements

    Summary of comments: A commenter recommended several revisions to 
Sec.  250.734(a)(5), including: Changing the proposed requirement that 
the ROV crew must ``examine all ROV related well-control equipment'' to 
requiring that the ROV crew ``must be familiar with all ROV related 
equipment''; revising the requirement that the ``ROV crew must be in 
communication with designated rig personnel'' to the ``ROV crew must be 
able to be in constant communication with designated rig personnel''; 
and changing ``shutting in the well during emergency operations'' to 
``carrying out appropriate tasks during emergency operations.''
     Response: BSEE agrees with the comment suggesting that the 
phrase ``shutting in the well during emergency operations'' be changed 
to ``carrying out appropriate tasks during emergency operations,'' and 
made that revision in the final rule. This will ensure that the ROV 
crew is able to conduct many different tasks, instead of just shutting 
in the well, during emergency operations. The other suggested changes 
would not substantively change or improve the requirements for ROV crew 
capabilities.

Comments Related to Proposed Sec.  250.734(a)(6)(iv)--Emergency 
Functions

    Summary of comments: Commenters suggested that the emergency 
functions requirement in proposed Sec.  250.734(a)(6)(iv) should be 
operations-specific and not a blanket order to close both casing shear 
and blind shear rams in all situations. Some commenters recommended 
using an operational risk assessment to determine the optimum emergency 
sequence for the specific operation, stating that the sequential 
shearing requirement is too prescriptive and the prescribed method in 
the proposed rule may not be the safest approach.
     Response: BSEE does not agree that any changes to Sec.  
250.734(a)(6)(iv) are needed based on this comment. The only 
requirement for sequencing in paragraph (a)(6)(v), does not specify any 
particular sequencing of emergency functions; it only requires a 
sufficient delay after beginning closure of the lower shear ram before 
the upper ram begins closure. The specific sequencing of emergency 
functions should be developed by the operator based on safety 
considerations.
    Summary of comments: One commenter recommended that BSEE remove the 
requirement that each emergency function must close dual shear rams. 
The commenter stated that since the sealing shear ram is required to 
shear the same tubulars as the non-shearing ram, closing both rams in 
all cases does not provide an advantage. However, another commenter 
supported the proposed requirement to close a minimum of two shear 
rams, one of which must seal the well, stating that it will increase 
the availability of all the emergency BOP functions. Another commenter 
also supported the proposed requirement and stated that the sequencing 
will help ensure that at least one of the shear rams will seal.
     Response: BSEE disagrees with the comment about removing 
the requirement that each emergency function must close two shear rams. 
The autoshear/deadman systems are used as a ``last case'' scenario to 
operate specific BOP components, are not performed by rig personnel, 
and are set to activate independently under certain operating criteria. 
BSEE is requiring both shear rams to close for these emergency 
functions in order to increase the effectiveness of those emergency BOP 
systems.

Comments Related to Proposed Sec.  250.734(a)(6)(iv)--Emergency 
Functions

    Summary of comments: Commenters stressed that requiring that each 
emergency system must always close dual shear rams in sequence will 
reduce the operating capability of the rigs due to the reduced 
operating radii induced by such a rule. They stated that the purpose of 
the EDS is to release the vessel from the well to save lives; if this 
can be done without polluting, that is a bonus, but the focus is on 
saving lives first. Commenters asserted that the operations at the 
time, together with the weather conditions, etc., should dictate what 
EDS sequence is used, not a prescriptive rule.
     Response: BSEE agrees that the primary focus of the EDS, 
and many other well control systems, is to save lives in addition to 
preventing environmental harm. The sequencing of the dual shear rams 
should be set by the operator to function in a reasonable timeframe. If 
the emergency functions are being activated, then the well-control 
situation has been analyzed by the rig personnel and the options to 
control the well have become limited to the emergency functions. These 
provisions are intended to ensure the safety of the crew and prevent 
pollution, and therefore require that the emergency functions utilize 
all of the appropriate components to assist in securing and moving off 
the well. Thus, no revision to the rule is needed in response to this 
comment.

[[Page 25960]]

Comments Related to Proposed Sec.  250.734(a)(6)(v)--Sufficient Delay

    Summary of comments: Commenters requested that BSEE specify the 
longest period that will be considered ``sufficient delay'' for closing 
the upper ram, and suggested that ``sufficient delay'' should be the 
time required to detect the failure of the lower shear ram to hold 
pressure. The upper shear ram should then be required to close as soon 
as possible upon the failure to close the lower shear ram.
     Response: BSEE does not specify the timing associated with 
the sequencing in paragraphs (a)(6)(iv) through (vi). The precise 
sequencing and timeframes for each BOP component to function should be 
set by the operator based on the specific circumstances (e.g., an 
operator may choose to use a risk assessment to determine the optimal 
timeframes).

Comments Related to Proposed Sec.  250.734(a)(6)(vi)--Emergency Control 
Systems

    Summary of comments: A commenter noted that this paragraph would 
result in additional complexity due to the necessary addition of a 
timing circuit; this results in less reliability and possibly more 
failures of the shearing circuit. It also requires more stack mounted 
accumulators, which are also more likely to fail and render the shear 
rams inoperable. A commenter suggested that BSEE revise paragraph 
(a)(6)(vi) by adding, ``[e]mergency disconnect systems are allowed to 
be activated manually, but once activated must lead to a failsafe 
state.'' Commenters asked for clarification of the intent of paragraph 
(a)(6)(vi) and raised concerns about the reference to the ``logic'' of 
the emergency system potentially preventing the next step in the 
sequence.
     Response: BSEE agrees with the commenter that the control 
system for the emergency functions should be fail-safe once activated, 
and has revised final paragraph (a)(6)(vi) by removing the phrase ``and 
the logic must provide for the subsequent step to be independent from 
the previous step having to be completed'' and replacing it with the 
phrase ``once activated.'' This change would allow the systems to be 
fail-safe without the addition of a timing circuit as suggested by this 
comment.

Comments Related to Proposed Sec.  250.734(a)(7)--Acoustic Control 
Systems

    Summary of comments: Commenters raised concerns about unintended 
consequences of this provision, which requires demonstration that an 
acoustic control system will function in the proposed environment and 
conditions, asserting that if a failure of the acoustic system results 
in mandatory repairs for the BOP stack, then operators will be 
encouraged to reduce the emergency capability of the rig by removing 
the acoustic system. Commenters recommended that, if operators install 
an acoustic system, it should be treated as a redundant system allowed 
under Sec.  250.738(o) or that BSEE should allow the operators to 
assess the risks of continuing without the acoustic system and act 
accordingly. A commenter noted that acoustic systems have good 
potential for secondary, emergency control of the BOP, but that their 
reliability is not fully established. Thus, according to the commenter, 
there is a need to conduct a trial of the acoustic systems to evaluate 
their full potential and BSEE should not penalize the operator if the 
system fails to perform.
     Response: BSEE agrees that the operator should not be 
penalized if it has already voluntarily decided to install an acoustic 
system on the rig but does not use the system; however, if the operator 
chooses to use an acoustic control system, the operator must meet the 
requirements of Sec.  250.734(a)(7) to demonstrate that the system is 
functional. Accordingly, BSEE has revised final Sec.  250.734(a)(7) by 
replacing the word ``install'' with ``use,'' which will clarify that an 
operator need not demonstrate the functionality of the acoustic system 
unless the operator uses that system as an additional emergency control 
measure (in addition to the required autoshear, deadman and EDS 
systems). In any case, the commenter's concern that a failure to 
demonstrate the functionality of the acoustic system would result in 
mandatory repairs to the BOP stack (and thus would encourage removal of 
the acoustic system) is unfounded; nothing in this provision requires 
or suggests that the BOP stack would need to be pulled for repairs if 
that demonstration cannot be made. Additionally, an operator may 
contact the appropriate District Manager, who can address any questions 
about the use of an acoustic control system on a case-by-case basis.

Comments Related to Proposed Sec.  250.734(a)(8)--Enable Buttons

    Summary of comments: Commenters observed that not all BOP control 
panels use enable buttons. Many older surface and subsea control 
systems are manually controlled, which does not permit the use of 
enable buttons; however, these require two-handed operation of the 
critical functions. They also noted that API Standard 53 addresses two-
handed operation, but not enable buttons. The commenter recommended 
that BSEE remove the proposed requirement for enable buttons from this 
section or add references to the relevant provisions in API Standard 
53.
     Response: BSEE agrees with the comment that there are 
other options, besides enable buttons, to ensure two-handed operation 
for critical functions on the control panels. Accordingly, BSEE has 
revised final Sec.  250.734(a)(8) to state that ``[y]ou must 
incorporate enable buttons, or a similar feature, on control panels to 
ensure two-handed operation for all critical functions.'' This change 
would provide the flexibility to allow for other options besides enable 
buttons.

Comments Related to Proposed Sec.  250.734(a)(11)(ii)--Critical BOP 
Equipment

    Summary of comments: Commenters recommended that BSEE revise this 
proposed provision to clarify the meaning of ``critical BOP equipment'' 
consistent with API Standard 53. The commenters also noted that the 
term ``competent person'' is defined in API Standard 53 as: ``person 
with characteristics or abilities gained through training, experience, 
or both, as measured against the manufacturer's or equipment owner's 
established requirements.'' These commenters also recommended changing 
the language in proposed paragraph (a)(11)(ii), requiring a 
``comprehensive knowledge of BOP hardware and control systems,'' to ``a 
knowledge of BOP hardware and control systems commensurate with their 
responsibilities.'' A commenter also suggested that established 
guidelines are needed for measuring comprehensive knowledge of BOP 
hardware and control systems, and that additional time beyond the 
proposed 90 days for compliance is needed if testing or certain 
training classes are required. Another commenter advocated that BSEE 
require the equipment owner to establish minimum requirements for 
personnel authorized to operate critical BOP equipment.
     Response: BSEE does not agree that any changes to this 
paragraph are appropriate based on the comments. Section 250.734(a)(11) 
is essentially a performance-based requirement, and several of the 
changes suggested by commenters would unnecessarily confine operators 
in deciding how best to meet the goals established by this provision. 
Thus, BSEE has decided not to define the term ``critical BOP

[[Page 25961]]

equipment;'' however, the discussions of critical BOP equipment in API 
Standard 53 could be used by an operator as a guide to understanding 
the scope of critical equipment.
    Similarly, BSEE does not agree that the other suggested changes to 
paragraph (a)(11)(ii) are appropriate because such changes could 
unnecessarily limit the scope of the required personnel knowledge. BSEE 
does not expect that the ``comprehensive knowledge'' required by Sec.  
250.734(a)(11)(ii) would necessarily include knowledge of BOP hardware 
and control systems that are so far outside the scope of an 
individual's current or potential responsibilities that there is no 
reasonable possibility that the individual would ever be called on to 
operate such equipment; however, BSEE believes it is important that all 
personnel operating critical BOP equipment understand how their 
specific responsibilities fit within the BOP system as a whole. Overly 
narrow understanding of the whole system, including hardware and 
controls, could result in personnel not understanding the importance of 
their own duties to the success of the system in preventing a blowout.
    BSEE also does not agree that the compliance timeframe for this 
paragraph should be changed. Commenters provided no factual basis for 
such a change. In addition, BSEE expects BOP operating personnel to be 
familiar with their responsibilities and to be trained in accordance 
with the applicable requirements of 30 CFR part 250, subparts O and S 
(e.g., 250.1503(a)). Ensuring the competency of rig personnel to 
perform their assigned duties is also consistent with current industry 
standards (see, e.g., API RP 75).
    BSEE also does not agree with the suggestion that the 
responsibility for compliance with Sec.  250.734(a)(11) should be 
transferred from the facility operator to some ``equipment owner'' who 
may not be familiar with the specific circumstances under which the BOP 
equipment will be used.

Comments Related to Proposed Sec.  250.734(a)(12)--Riser Fluid 
Displacement

    Summary of comments: Commenters noted that the proposed requirement 
that fluid in the riser be displaced with seawater before the riser is 
removed did not include an exception for emergency or unplanned LMRP 
disconnects in which the fluid in the riser would not be displaced. 
Commenters suggested displacing the riser fluid using a closed 
volumetric visual control systems to observe fluid gains and losses.
     Response: BSEE is not revising paragraph (a)(12). BSEE 
expects that operators will plan for riser displacement as appropriate 
and based on safety factors. BSEE expects the operator to take whatever 
appropriate action is needed in an emergency situation to ensure safety 
of workers and protection of the environment.

Comments Related to Proposed Sec.  250.734(a)(13)--Well Cellars

    Summary of comments: Commenters requested clarification of the 
proposed requirement to install a BOP stack in a well cellar when in an 
ice scour area. The commenters seek to ensure that this would only 
require that the well cellar be deep enough to ensure that the lower 
BOP stack--but not the lower stack and LMRP--is enclosed. Another 
commenter observed that this proposed requirement is addressed in, and 
would conflict with, the proposed Arctic OCS rule; thus, it should be 
removed from this rulemaking.
     Response: BSEE has not made any changes to Sec.  
250.734(a)(13). The commenter did not specify how this provision 
conflicts with the proposed Arctic OCS rule. It is BSEE's expectation 
that the top of the BOP stack (not including the LMRP) must be set 
below the deepest possible ice scour depth. The LMRP can be 
disconnected from the BOP stack and would be removed if the rig has to 
move off location, leaving just the BOP stack in place.

Comments Related to Proposed Sec.  250.734(a)(14)(iii)--Fail-Safe 
Valves and Side Outlets

    Summary of comments: Commenters recommended adding to the proposed 
provision in paragraph (a)(14)(iii)--regarding valves used in side 
outlets for choke lines and kill lines--that the valves must be fail-
safe. Another commenter recommended revising paragraph (a)(14)(iv) to 
require installation of the side outlet below the lowest sealing shear 
ram instead of below each sealing shear ram.
     Response: No changes to Sec.  250.734(a)(14)(iii) are 
necessary regarding the valves being fail-safe. BSEE understands that 
these valves are already fail-safe closed. However, BSEE agrees with 
the comment about paragraph Sec.  250.734(a)(14)(iv) and has revised 
final paragraph (a)(14)(iv) by replacing ``each'' sealing ram with 
``the lowest'' sealing ram to allow more flexibility for component 
placement.

Comments Related to Proposed Sec.  250.734(a)(15)--Gas Bleed Line

    Summary of comments: Regarding the proposed requirement to install 
a gas bleed line with valves for the annular preventer, commenters 
noted that many existing annular BOPs do not have a side outlet. They 
asserted that every valve and every outlet added to the BOP systems 
increases potential leak paths and reliability concerns. A commenter 
proposed that, if BSEE did not remove this section, it should be re-
worded to pertain only to the uppermost annular preventer.
    Another commenter emphasized that, because the upper annular is 
traditionally the working annular, the bleed valves are typically 
installed below the upper annular. Other commenters asserted that 
adding another set of gas bleed valves under the lower annular would 
require additional pilot lines and valves per pod, and that spare pilot 
lines and valves are limited and may be needed for higher priority pipe 
ram or shear ram functions. This commenter requested that BSEE clarify 
the technical reason for adding a set of gas bleed valves under the 
lower annular in this situation.
    Commenters also requested additional time to install the gas bleed 
line and valves. Commenters asserted that the lead times for 
engineering, component procurement and installation of an additional 
valve for gas relief under the lower annular would preclude compliance 
with the rule within 90 days.
     Response: BSEE agrees with several of these comments, and 
has revised final Sec.  250.734(a)(15) to clarify that if a subsea BOP 
has dual annulars, the gas bleed line must be installed below the upper 
annular. BSEE has also removed the proposed requirement to install gas 
bleed lines on each annular. These revisions should eliminate or 
minimize commenters' concerns about space issues, reliability, and 
addition of possible failure points. BSEE also agrees that it will take 
more than the proposed 90 days to install the required gas bleed lines 
and valves, and revised the compliance date for paragraph (a)(15) to 2 
years after publication of the final rule. Extending the compliance 
date will provide adequate time for installation of the gas bleed line 
and valves while avoiding any rig downtime.

Comments Related to Proposed Sec.  250.734(a)(16)--BOP System 
Capabilities

    Summary of comments: Commenters criticized the prescriptive 
language in

[[Page 25962]]

proposed Sec.  250.734(a)(16)(i) through (iii), and questioned whether 
the intent is to require that shear rams must be able to sever the 
pipe, and seal the pipe, regardless of where the pipe is within the 
bore. The commenters said that if this is what BSEE wants to achieve, 
then the regulation should state that.
    Commenters also asked why, if the pipe does not need to be 
centralized to shear it, require centralization of the pipe? Commenters 
noted that not all OEMs require a mechanism for centering tubulars, and 
that centralization can be achieved via the geometry of the blade 
design.
    A commenter suggested that the proposed text steers technology 
development in a specific direction which may inhibit development of 
other technologies. On the other hand, another commenter stated that 
BSEE explicitly notes that this requirement is designed to encourage 
further technological development, driving safety improvements beyond 
current industry practice.
     Response: No changes to Sec.  250.734(a)(16) are necessary 
based on these comments. BSEE understands that some rams may be capable 
of shearing on the rams' cutting edges, without centralizing the pipe. 
However, it is safer to have the pipe centered while shearing in order 
to optimize shearing capabilities and reduce risk by ensuring that the 
pipe to be sheared is across the shearing surfaces. It is not BSEE's 
intention to inhibit applicable technological advancements, however; in 
fact, BSEE believes this performance-based requirement will encourage 
development and use of technology to center the pipe while shearing. 
Moreover, nothing in this requirement expressly or implicitly 
discourages development of other new technologies to improve shearing 
capabilities and decrease risk. Any operator that wishes to do so, may 
seek approval from the District Manager or Regional Supervisor under 
Sec.  250.141 for use of any alternative equipment or procedures that 
are at least as protective as this requirement.

Comments Related to Proposed Sec.  250.734(a)(16)(ii)--Ability To 
Mitigate Compression

    Summary of comments: A commenter asserted that the proposed 
requirement that the subsea BOP have the ``ability to mitigate 
compression'' of the pipe stub is too vague. The commenter asserted 
that the critical factor is the ability of the BOP to accept the pipe 
stub and suggested that BSEE revise the rule to reflect that.
     Response: BSEE has not made any changes to Sec.  
250.734(a)(16)(ii) based on the comment. Mitigating the compression of 
the pipe stub would allow for the pipe stub to be accepted between the 
shear rams and would not interfere with the shearing functions.

Comments Related to Proposed Sec.  250.734(a)(16)(iii)--Batteries

    Summary of comments: Commenters suggested revising this paragraph 
to require ``subsea control system batteries'' instead of ``subsea 
electronic module batteries in the BOP control pods,'' noting that 
there are other batteries used in BOP equipment (e.g., an acoustic pod, 
a deadman system).
     Response: BSEE has not made any changes to Sec.  
250.734(a)(16)(iii) based on the comment. BSEE understands that the 
subsea electronic module is an important component to ensure 
operability of the subsea BOP. However, the commenter did not provide 
any support for its requested change, and BSEE currently lacks enough 
information to justify such a change.

Comments Related to Proposed Sec.  250.734(b)(1)--BAVOs

    Summary of comments: Commenters observed that, since this section 
requires a verification report from a BAVO ``documenting the repairs to 
the BOP and that the BOP is fit for service,'' it cannot be implemented 
until BSEE approves a suitable number of organizations to serve as 
BAVOs.
    Commenters also asserted that the operator should have primary 
responsibility for certifying the required documentation, and that the 
BAVO should support such certification by verifying the information 
provided by the operator. Other commenters recommended changing the 
requirement to use a BAVO to a requirement to use an ``independent 
third-party.''
     Response: As previously discussed, BSEE has revised the 
compliance date for the use of a BAVO to one year after BSEE publishes 
a list of BAVOs. Part III of this document provides a more detailed 
discussion of this compliance date.
    In addition, as previously discussed, this and the other BAVO-
related provisions do not eliminate or transfer the operator's 
regulatory responsibilities to the BAVO; the operator is responsible 
for ensuring compliance with Sec.  250.734(b). As explained earlier in 
this document, BSEE has decided that it is necessary that BSEE review 
and determine the qualifications of organizations that will perform 
this verification function.

Comments Related to Proposed Sec.  250.734(b)(2)--BOP Testing

    Summary of comments: Regarding the proposed requirement to re-test 
the BOP, including the deadman or lower stack ROV intervention 
functions, upon relatch after subsea BOP repairs, a number of 
commenters stressed that when the LMRP is retrieved, it is not 
necessary to re-test those functions. They asserted that the deadman 
and ROV systems were tested on the surface and subsea upon initial 
installation and that, after repair, if the systems are tested on the 
surface before redeployment, a re-test after re-latching should not be 
required. They also stated that API Standard 53 does not specify re-
testing under such circumstances. The commenters stated that subsea 
testing of the deadman system with a dynamically-positioned rig is a 
high consequence operation, and the more times the test is performed, 
the higher the probability a station-keeping incident will occur. They 
also stated that these tests would lead to additional unnecessary wear 
on blind shear rams and reduction of overall system reliability.
    Some commenters agreed, however, that if any part of the deadman or 
ROV systems is dismantled, repaired, or affected as part of the BOP 
repair, then it would be prudent to verify functionality of these 
systems upon re-latching. Commenters recommended that BSEE revise this 
section to change re-testing of the deadman and ROV intervention 
functions to re-testing of any functions affected during the repair.
     Response: BSEE intends that, if the BOP stack is pulled 
for repair to any part of the BOP system, testing must be completed 
before resuming operations. However, BSEE agrees with several of the 
points made by the comments; thus, BSEE has revised final Sec.  
250.734(b)(2) to state that, upon relatch of the BOP, an operator must 
perform an initial subsea BOP test in accordance with Sec.  
250.737(d)(4), including testing the deadman. 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. These revisions will effectively 
limit the scope of the re-testing requirement--and therefore the 
potential negative consequences from excessive wear caused by re-
testing--by requiring comprehensive re-testing of all BOP components, 
including ROV functions, only when repairs exceed 30 days. For all 
repairs lasting 30 days or less, this revised provision would require 
less extensive re-testing; for example, re-testing under this situation 
would not

[[Page 25963]]

need to cover all ROV intervention functions and would require 
retesting of only one set of rams (instead of all rams).
    In addition, the commenters' concern about the possibility that re-
testing would increase the probability of a dynamically-positioned rig 
going off-station is minimized by the fact (as discussed later in this 
document with regard to proposed Sec.  250.737(d)(13)) that many rigs 
already have updated BOP control systems that allow power to other 
systems, including dynamic positioning systems, to remain on during 
deadman testing.

What associated systems and related equipment must all BOP systems 
include? (Sec.  250.735)

    As provided for in the proposed rule, this section combines and 
revises provisions from several sections of the existing regulations 
and consolidates system and equipment requirements applicable to all 
BOPs. Those requirements cover accumulator systems, control station 
locations, choke and kill line installation, and remotely-operated 
locking devices for sealing rams on surface BOPs (except pipe or 
variable bore rams that already have non-hydraulically operated locks). 
BSEE has revised certain provisions of proposed Sec.  250.735 in the 
final rule as discussed in the comment responses for this section and 
in parts V.B.2 and V.C of this document.

Comments Related to Proposed Sec.  250.735(a)--Surface Accumulator 
System

    Summary of comments: Multiple commenters suggested that the 
accumulator system volume capacity requirements of proposed Sec.  
250.735(a) contradict the analogous provisions of API Standard 53 and 
API Spec. 16D, that the proposed capacity requirements are not 
achievable, and that the proposed language is so ambiguous that 
operators could not understand the rule's intent. Multiple commenters 
stated that the proposed requirement that surface accumulators must 
provide 1.5 times the volume of fluid capacity necessary to close and 
hold closed all BOP components against MASP (the 1.5 times volume 
capacity requirement) could effectively force the elimination of some 
BOP components from existing BOP systems, and thus either reduce the 
number of redundant controls or require operators to install additional 
equipment.
    Several commenters asserted that the proposed requirements would 
increase the number of accumulator bottles needed, would require 
upgraded accumulator system controls, and would significantly increase 
costs. Also, the commenters asserted that the extra weight from 
additional bottles, given limited deck space availability, could cause 
structural issues with the rig. Further, the commenters asserted that 
this additional equipment would require additional maintenance and 
potentially render the systems less reliable. For certain older rigs, 
the commenters stated that the additional requirements could force the 
removal of the rigs from service.
    For such reasons, multiple commenters recommended deleting the 
proposed 1.5 times volume capacity requirement and requiring instead 
that surface accumulator sizing meet the specifications of API Standard 
53 or API Spec. 16D (since the methods discussed in API Spec. 16D are 
also included in API Standard 53).
     Response: BSEE agrees with several of the commenters' 
concerns. BSEE has decided to revise final Sec.  250.735(a) by deleting 
the 1.5 times volume capacity requirement for all surface accumulators 
and instead requiring that all accumulator systems (including those 
servicing subsea BOPs) meet the sizing specifications of API Standard 
53. This revision will not degrade safety or environmental protection 
compared to the proposed requirement. BSEE has determined that the 
methods for calculating the necessary fluid volumes and pressures in 
API Standard 53 provide an acceptable amount of usable fluid and 
pressure to operate the required components, while still ensuring--as 
required by Sec.  250.735(a)--that accumulators have enough charge to 
remain at least 200 psi above the pre-charge pressure, without 
recharging, even after operating all BOP functions. This provides a 
sufficient margin of error to prevent any safety or environmental harm 
from failure of pressure to the BOP and is also consistent with API 
Standard 53.

Comments Related to Proposed Sec.  250.735(a)--API Standard 53

    Summary of comments: Some comments stated that Sec.  250.735(a) is 
inconsistent with API Standard 53 in other ways; for example, API 
Standard 53 does not require accumulator regulators on subsea BOP 
stacks to be supplied by rig air.
     Response: This regulation does not require that subsea 
accumulators be supplied by rig air. It merely imposes certain 
requirements ``if'' subsea accumulators are supplied by rig air. BSEE 
understands that rig air is used for surface accumulators and not 
subsea. In addition, as discussed elsewhere in this document, BSEE has 
made several revisions to final Sec.  250.735(a) to align the rule more 
closely with API Standard 53.

Comments Related to Proposed Sec.  250.735(a)--Surface Accumulator 
System

    Summary of comments: Multiple commenters expressed concern with the 
requirement in proposed Sec.  250.735(a) that the accumulator system be 
able to supply pressure to operate all BOP functions, and to shear pipe 
as the last step in the BOP sequence, without assistance from a 
charging unit. They asserted that this provision would increase the 
number of accumulator bottles needed and would require upgraded 
accumulator system controls and that costs associated with the 
additional bottles would be significant. The commenters also stated 
that the extra weight from additional bottles, given limited deck space 
availability, could cause structural issues with the rig.
     Response: BSEE agrees with the commenters' concerns about 
the proposed requirement that the accumulator system be able to operate 
all BOP functions, with the blind shear ram being last in the sequence, 
and still have enough pressure to shear pipe and seal the well. 
Accordingly, BSEE has revised Sec.  250.735(a) by replacing ``all BOP 
functions'' with ``the BOP functions as defined in API Standard 53.'' 
Revising the BOP functions in response to the comments to align with 
API Standard 53, in conjunction with the revisions to the fluid 
capacity volume requirements previously discussed, will eliminate or 
significantly reduce the commenters' concerns about the costs 
associated with the additional bottles. In particular, because the 
final rule requires that the accumulator bottles be able to operate the 
BOP functions as defined by API Standard 53, fewer accumulator bottles 
should be needed (as compared to the proposed requirement), as the 
commenters indicated. This, in turn, will minimize (as compared to the 
proposed rule) the potential impacts on the rig structure that could 
have resulted from the extra weight of additional bottles as well as 
the potential impacts on operations and safety from storage of the 
bottles in the limited deck space available.
    For the same reasons, BSEE has also removed the phrases ``with the 
blind shear ram being the last in the sequence'' and ``enough pressure 
to shear pipe and seal the well with . . .'' from final Sec.  
250.735(a). Removing these phrases will eliminate the impression

[[Page 25964]]

that the proposed language would have mandated that the blind shear ram 
be the last step in the BOP sequence. In addition, BSEE agrees that the 
proposed language regarding sequencing of the blind shear ram is not 
necessary, as long as the accumulator is able to provide sufficient 
volume to operate all the required BOP functions under MASP.

Comments Related to Proposed Sec.  250.735(a)--Surface Accumulator 
System

    Summary of comments: A commenter recommended changing ``surface 
accumulator system'' to ``main accumulator system.'' The commenter 
asserts that this will ensure that other surface accumulators (e.g., 
for the diverter system) are not included and will allow for subsea 
accumulators that are used by the main control system (e.g., LMRP 
mounted) to be included on subsea stacks.
     Response: BSEE agrees that proposed Sec.  250.735(a) could 
have resulted in confusion about the types of accumulator systems to 
which the requirements applied. Accordingly, BSEE has revised final 
Sec.  250.735(a) by replacing ``surface accumulator system'' with 
``[a]n accumulator system (as specified in API Standard 53).'' This 
revision will help clarify that the accumulator system requirements of 
paragraph (a) are applicable to either a surface or subsea BOP system 
(as discussed in API Standard 53).

Comments Related to Proposed Sec.  250.735(b)--Automatic Backup to the 
Primary Accumulator Charging System

    Summary of comments: Commenters stated that this proposed 
paragraph--which would require ``an automatic backup to the primary 
accumulator-charging system''--was unclear. They requested 
clarification on the meaning of the phrase ``automatic backup to the 
primary accumulator charging system.'' They asked BSEE to answer 
several questions about the meaning of this phrase in several specific 
factual situations; e.g., whether, assuming a charging system is an 
electric-driven pump, the automatic backup requirement would apply if 
the electric-driven pump is also capable of being powered from the 
emergency bus instead of the primary power generation from the rig.
    Commenters also claimed that, if the proposed requirement for an 
automatic power source is intended to require a second complete pumping 
unit, the time needed to procure and install such equipment would 
preclude compliance within the proposed 90 days. Other commenters 
recommended that BSEE delete paragraph (b) altogether and instead 
simply reference API Standard 53 and API Spec. 16D.
     Response: No changes to the requirements for an automatic 
backup to the primary accumulator charging system in Sec.  250.735(b) 
are necessary. In fact, the requirements in Sec.  250.735(b) have been 
in place--in former Sec.  250.443(a)--for years, and BSEE is not aware 
of any problems occurring because of confusion about the automatic 
backup to the primary accumulator charging system. Nor is it necessary 
to incorporate API Spec. 16D into paragraph (b). This regulation 
requires minimum capabilities, and if compliance with API Spec. 16D or 
other industry standards meets these minimum requirements, there is no 
reason why an operator could not follow that standard.

Comments Related to Proposed Sec.  250.735(e)--Kill Line

    Summary of comments: Multiple commenters stated that the placement 
of the term ``kill line'' in proposed Sec.  250.735(e) was confusing 
and recommended that BSEE refer to the language in API Standard 53 
instead.
     Response: BSEE agrees that proposed Sec.  250.735(e) was 
not clear. Accordingly, BSEE has revised Sec.  250.735(e) to clarify 
that the kill line must be installed beneath at least one well-control 
ram, and may be installed below the bottom ram. This clarification will 
avoid confusion related to the fact that many BOP stacks use a test ram 
(which is not a well-control ram) in the bottom-most part of the BOP.

Comments Related to Proposed Sec.  250.735(g)--Hydraulically Operated 
Locking Devices

    Summary of comments: Multiple commenters urged that this 
provision--regarding hydraulically operated locks installed on BOPs 
with sealing rams (i.e., pipe rams/VBRs or blind shear rams)--
distinguish between surface and subsea BOP stacks. Some commenters 
noted that locking devices for ram-type BOPs are already addressed in 
Sec.  250.733(e). Some commenters indicated that surface stacks can use 
manual locks, while subsea BOP stacks should use hydraulic locks. Other 
commenters observed that since most surface stacks do not use hydraulic 
rams, installation of hydraulic locks in compliance with this provision 
would require 3 years from publication of the final rule, while other 
commenters stated that the proposed requirement (and proposed Sec.  
250.733(e)) would be unduly costly. One commenter recommended that BSEE 
replace the proposed requirement for hydraulic locks with a requirement 
for remotely-operated locks.
     Response: BSEE agrees with several of the observations 
made by the commenters. In particular, BSEE agrees that the purpose of 
the proposed rule--to ensure that sealing rams on surface BOPs, as well 
as subsea BOPs, can be locked promptly and with minimal risk to rig 
personnel--can be effectively achieved with various kinds of locking 
devices appropriate to each type of BOP (surface or subsea) and to each 
type of sealing ram. For subsea BOP sealing rams, hydraulic locks will 
continue to be appropriate, since those rams are already required to be 
hydraulically operated (under both former Sec.  250.442(a) and new 
Sec.  250.734(a)(1)) and since existing locking devices for those rams 
are also hydraulically operated.
    For surface BOPs, however, other locking devices can achieve the 
same purpose as hydraulic locks with no incremental loss of personnel 
safety or environmental protection. As suggested by one of the 
commenters, other types of remotely-controlled locks could also ensure 
that sealing rams can be locked without exposing rig personnel to 
unnecessary risk. BSEE has determined that any remotely-controlled lock 
(whether or not hydraulically operated) is appropriate for blind shear 
rams on surface BOPs. This requirement will help prevent potential 
blowouts and reduce the risk of personnel having to be in or near a 
potentially hazardous area during an emergency event by making it 
unnecessary for them to manually operate manual locks.
    By contrast, pipe rams and VBRs on surface BOPs can be safely and 
effectively locked manually, as they have been under former Sec.  
250.443(f), or remotely. BSEE is not aware of any well-control incident 
that was directly related to failure of a surface BOP manual lock; nor 
is BSEE aware of any personnel safety incident resulting from operation 
of a manual lock on pipe rams or VBRs. Thus, given the past 
effectiveness of manual locks, BSEE has determined that it is not 
necessary at this time to require hydraulic or other remotely-
controlled locks on surface BOP pipe rams/VBRs.
    Accordingly, BSEE has revised final Sec.  250.735(g) to distinguish 
between surface and subsea BOPs, and to provide operators with more 
flexibility in their choice of locking mechanisms for sealing rams on 
surface BOPs. Specifically, the final rule will require hydraulic locks 
for all subsea BOP sealing rams, remotely-operated locks for surface 
BOP blind shear rams, and

[[Page 25965]]

manual or remotely-controlled locks on surface BOP pipe rams/VBRs.
    In addition, BSEE understands that the requirement to install 
remotely-controlled locks (whether or not hydraulically operated) on 
surface BOP blind shear rams would take significantly more time than 90 
days from publication of the final rule, due to the need to procure 
enough of the necessary equipment as well as to practical and 
logistical problems with installation. For example, as implied by the 
commenters, installation of hydraulic locks on BOP surface stacks that 
do not have hydraulic rams would take substantially more time because 
hydraulic systems to control the locks in those cases will also need to 
be added to the BOP stack. BSEE also agrees that failure to install 
hydraulic or other remotely-controlled locks by the proposed compliance 
date could result in significant rig downtime. Accordingly, BSEE has 
determined that 3 years after publication of the final rule is an 
appropriate timeframe for acquiring and installing all of the necessary 
systems and equipment to meet the requirement for surface BOP blind 
shear rams, and has revised the compliance date in final Sec.  
250.735(g)(2) accordingly.

What are the requirements for choke manifolds, kelly-type valves, 
inside BOPs, and drill string safety valves? (Sec.  250.736)

    As provided for in the proposed rule, this section reflects a 
combination of provisions from several sections of the existing 
regulations that established technical requirements for choke 
manifolds, kelly valves, inside BOPs, and drill string safety valves. 
This final rule makes several revisions to the former requirements with 
respect to choke manifolds and kelly-type valves. BSEE has revised 
certain provisions of proposed Sec.  250.736 in the final rule as 
discussed in the comment responses for this section and in part V.C of 
this document.

Comments Related to Proposed Sec. Sec.  250.736(a) Through (c)--API 
Standard 53

    Summary of comments: A commenter recommended that BSEE revise 
proposed Sec.  250.736(a) to rely on API Standard 53 for the design and 
operation of the choke manifold. The commenter also suggested that BSEE 
delete proposed paragraphs (b) and (c) because the matters they cover 
would already be covered by the reference to API Standard 53 in 
paragraph (a).
    Another commenter asked whether it was BSEE's intent, in proposed 
Sec.  250.736(b), that all choke manifold components, including valves 
downstream of the chokes, be rated for the full working pressure of the 
BOP stack.
     Response: BSEE disagrees with the recommended revisions to 
Sec.  250.736(a) through (c). These paragraphs describe general 
requirements for the choke manifold. Nearly identical requirements have 
been in place for many years (formerly in Sec.  250.444), and BSEE is 
not aware of industry raising any prior concerns with implementing 
those longstanding requirements. With regard to paragraph (b), the need 
to ensure that all choke manifold components are able to withstand the 
wellbore pressures that they will encounter is as important under this 
final rule as it was under the existing regulation. Nonetheless, if an 
operator has any questions about the meaning of this longstanding 
requirement, it can ask the District Manager for assistance.

Comments Related to Proposed Sec.  250.736(d)--Kelly Valves

    Summary of comments: Commenters recommended that BSEE revise this 
paragraph to clarify that it only applies to rigs that operate with 
kelly valves. One commenter asserted that proposed Sec.  250.736(d)(1) 
requires the use, ``during all operations,'' of ``a kelly valve 
installed below the swivel'' even though kelly valves are no longer in 
widespread use in offshore drilling operations. Similar comments 
claimed that kelly valves are seldom used and have limited applications 
in OCS operations because almost every rig on the OCS now uses drill 
pipe instead of kelly valves. For that reason, one commenter 
recommended that BSEE delete proposed paragraphs (d)(2) and (3), since 
these provisions are obsolete. Similarly, some commenters asserted that 
the methodology required in proposed paragraph (d)(3) has been rendered 
obsolete by the proven use and operation of top drives.
     Response: BSEE agrees with the comments about the limited 
application of kelly valves and has revised final Sec.  250.736(d)(1) 
by replacing the references to kelly valves with the phrase 
``applicable [k]elly-type valves as described in API Standard 53.'' For 
the same reason, BSEE has deleted paragraphs (d)(2) and (3) from final 
Sec.  250.736. BSEE has determined that the reference to API Standard 
53 specifications for kelly-type valves in paragraph (d)(1) renders 
paragraphs (d)(2) and (3) unnecessary.

Comments Related to Proposed Sec.  250.736(d)(4)--Top-Drive Systems

    Summary of comments: Commenters stated that proposed paragraph 
(d)(4)--requiring a strippable kelly-type valve on a top-drive system 
with a remote-controlled valve--is more specific than API Standard 53, 
and that BSEE should simply reference API Standard 53.
     Response: BSEE disagrees with the comments suggesting 
changes to Sec.  250.736(d)(4). This provision has been in the existing 
regulations for many years (i.e., in former Sec.  250.445(d)) and BSEE 
does not believe that incorporating API Standard 53 would improve 
safety or environmental protection as compared to the former 
regulations and this final rule. In addition, BSEE is unaware of prior 
industry concerns associated with the equipment required by this 
longstanding requirement. Thus, there is no need to add the reference 
to API Standard 53 suggested by the commenter.

What are the BOP system testing requirements? (Sec.  250.737)

    As provided for in the proposed rule, this section combines and 
revises various BOP testing requirements from the existing regulations. 
Paragraph (a) reorganizes and consolidates the pressure testing 
frequency requirements for drilling, workovers, completions, and 
decommissioning. Paragraph (b) requires certain pressure test 
procedures while paragraph (c) clarifies the duration of the pressure 
tests. Paragraph (d) further clarifies testing procedures for various 
situations and equipment (e.g., stump testing, initial subsea testing, 
ram and annular testing). BSEE has revised certain provisions of 
proposed Sec.  250.737 in the final rule as discussed in the comment 
responses for this section and in parts V.B.6 and V.C of this document.

Comments Related to Proposed Sec.  250.737(a)(1)--Installation BOP Test

    Summary of comments: A commenter requested clarification that 
proposed Sec.  250.737(a)(1) only requires a full BOP pressure test 
upon an initial installation, not subsequent installations following 
repairs or unplanned pulls. The commenter mentioned that studies have 
demonstrated that most faults are discovered during function testing; 
based on these findings, function testing is more valuable than 
pressure testing in measuring operability of the system.
     Response: The language requiring a pressure test when a 
BOP is installed is the same as the longstanding language in former 
Sec.  250.447(a) and requires no

[[Page 25966]]

clarification at this time. There is no change in the meaning or intent 
of that requirement, now located in Sec.  250.737(a)(1). In addition, 
BSEE is aware that BOP failures during pressure testing happen, and 
therefore it is important to pressure test to help verify the integrity 
of the BOP system to ensure it can function as intended.

Comments Related to Proposed Sec.  250.737(a)(2)--14-Day BOP Pressure 
Test

    Summary of comments: BSEE received a number of comments on the 
proposed requirement in Sec.  250.737(a)(2) that BOP pressure tests be 
conducted before 14-days have elapsed since the prior test, and no 
later than 30 days after since the last blind shear ram BOP pressure 
test. One commenter supported more frequent BOP pressure tests of 7 
days for all BOPs used in Arctic OCS operations. However, other 
commenters supported less frequent BOP pressure testing. Commenters 
cited the provisions of API Standard 53, which recommends a 21-day BOP 
test cycle for shear ram BOPs, as well as international industry best 
practices, in support of longer pressure test intervals. Multiple 
commenters pointed out that less frequent testing would mitigate wear 
and tear on the equipment from the testing itself, and wear and tear 
adversely affects long-term reliability of the equipment and thus 
increases the risks from equipment failure.
     Response: BSEE has not made any changes from the 14-day 
testing requirement in the proposed and existing regulations. BSEE did 
not receive any new supporting data with any comments that would 
support changes to the existing 14-day testing interval at this time. 
Although BSEE is aware of concerns that the more frequently BOPs are 
tested, the more likely the equipment is to wear out prematurely, and 
thus to fail to operate properly when needed, further study, research, 
and discussions with subject matter experts is needed for BSEE to make 
a determination that it is appropriate to change the general 14-day 
testing requirement. An operator that believes a different interval is 
warranted by special circumstances, however, may seek approval from the 
District Manager or Regional Supervisor to use an alternative procedure 
in accordance with Sec.  250.141. More details concerning this issue 
are contained in part V.B.6 of this document.

Comments Related to Proposed Sec.  250.737(a)(4)--District Manager 
Directed BOP Pressure Test

    Summary of comments: BSEE received one comment on proposed 
paragraph (a)(4), objecting to the BSEE District Manager having the 
authority to increase BOP testing frequency.
     Response: Like similar provisions throughout 30 CFR part 
250, Sec.  250.737(a)(4) is intended to give District Managers the 
necessary flexibility and discretion to require actions as needed in 
specific cases to fulfill the purposes of the regulation, and BSEE is 
therefore not making any changes to proposed paragraph (a)(4). In any 
case, this provision is identical to the longstanding language in the 
current regulations (i.e., former Sec.  250.447(b)), and BSEE is 
unaware of any significant concerns raised by operators in connection 
with District Managers exercising this authority.

Comments Related to Proposed Sec.  250.737(b)--BOP Pressure Test 
Procedures

    Summary of comments: Another commenter recommended that BSEE 
require an additional ram low pressure test after the completion of the 
high pressure test. The recommended ram testing sequence would be, in 
this case, low pressure, high pressure, and low pressure. The commenter 
stated that it is possible to tear the packing element elastomer seal 
during high pressure test such that it might not seal again during a 
low pressure test.
     Response: The pressure test procedures reflected in the 
rule have been in place for many years (formerly in Sec.  250.448), and 
BSEE is not aware of issues created by, or operators raising any 
concerns with, those procedures. BSEE is also unaware of any new data 
supporting a change in the procedures and is therefore not revising 
Sec.  250.737(b) as suggested.

Comments Related to Proposed Sec.  250.737(b)(2)--BOP High Pressure 
Test

    Summary of comments: Commenters noted that this provision does not 
differentiate between initial and subsequent testing, noting that 
proposed Sec.  250.737(d) requirements for subsea BOPs differentiate 
between stump, initial and subsequent testing, all of which utilize 
different test pressures. Another commenter asked BSEE to clarify 
proposed paragraph (b)(2) to confirm that the blind shear rams will 
only be tested to the high-pressure for the well at initial 
installation, and that subsequent tests will be performed to the casing 
test pressure.
     Response: BSEE has not made changes to proposed Sec.  
250.737(b)(2), which is largely based on the longstanding requirements 
for BOP testing in the current rules (former Sec.  250.448(b)), 
including blind shear ram testing. BSEE does not agree that the 
clarification requested by the commenter is necessary. BSEE discusses 
the additional testing requirements for subsea BOPs in more detail 
later in response to comments on proposed Sec.  250.737(d). If an 
operator has any questions about testing specific components, it may 
contact the appropriate District Manager for guidance.

Comments Related to Proposed Sec.  250.737(b)(3)--Annular BOP High 
Pressure Test

    Summary of comments: A commenter suggested that the words ``lesser 
of the'' are missing from this paragraph, noting that hydrostatic 
pressure should also be accounted for in subsea tests by deducting that 
pressure from the surface applied pressure.
     Response BSEE has not made any changes to Sec.  
250.737(b)(3). That provision allows the operator to choose between 70 
percent of the RWP or 500 psi greater than the calculated MASP for its 
high pressure test. The operator is free to use the lesser of those 
pressures if it so chooses, and no changes to the regulatory language 
are required to allow that. In addition, the hydrostatic pressure is 
already accounted for in the subsea BOP test, because it is added to 
the applied surface pressure to equal the MASP at the mudline.

Comments Related to Proposed Sec.  250.737(b)(3)--Annular BOP High 
Pressure Test

    Summary of comments: Another commenter recommended that the 
pressure test on the annular should be to a minimum of 70 percent of 
the RWP, stating that at times the annular is tested in excess of 70 
percent of the working pressure, while not exceeding the RWP.
     Response: BSEE has not made any changes to Sec.  
250.737(b)(3). That provision requires testing to either 70 percent of 
the RWP or 500 psi greater than the MASP. However, if an operator 
believes there are situations where testing to higher than 70 percent 
of the RWP is prudent and no less protective than this regulatory 
requirement, it may seek approval for alternative test pressures from 
the appropriate District Manager under Sec.  250.141.

[[Page 25967]]

Comments Related to Proposed Sec.  250.737(c)--BOP Pressure Test 
Duration

    Summary of comments: Commenters suggested that pressure testing 
regimes are clearly defined in API Standard 53, and that BSEE should 
align the rule with API Standard 53 or at least reference that 
standard. A commenter also suggested that BSEE remove the use of 
predictive-type technology from the rule. A commenter also suggested 
that BSEE follow API Spec. 6A guidance on pressure stabilization.
     Response: BSEE has not made any changes to Sec.  
250.737(c), which is identical in most respects to longstanding 
requirements in the existing regulations (formerly Sec.  250.448(c)). 
The comment does not identify or explain the type of predictive-type 
technology to which it objects; however, if it refers to the use of 
charts or digital recorders, BSEE notes that the existing regulations 
also refer to charts and recorders. BSEE is unaware of any concerns 
regarding conflicts with API Standard 53 or Spec. 6A for pressure 
testing durations or pressure stabilization. If there are any concerns 
surrounding the duration and method of pressure testing, operators may 
contact the appropriate District Manager for guidance.

Comments Related to Proposed Sec.  250.737(c)--BOP Pressure Test 
Duration

    Summary of comments: Other commenters noted that proposed Sec.  
250.737(c) will result in a large number of new chart recorders being 
ordered concurrently by industry, and that lead times for new equipment 
may exceed the proposed 90 days for compliance and put rigs out of 
compliance. These commenters requested 12 months to obtain and install 
the necessary equipment across all rigs.
     Response: BSEE has not made any changes to the compliance 
date for this provision. If an operator has any specific concerns about 
availability of equipment to meet the compliance date, it may contact 
the District Manager for guidance or request approval to use 
alternative technology or procedures under Sec.  250.141.

Comments Related to Proposed Sec.  250.737(d)(2)--Surface BOP Test With 
Water

    Summary of comments: Commenters expressed concerns about the 
proposed requirement to use water to test a surface BOP system. 
Commenters agreed that water should be used for the initial test of a 
surface BOP, but asserted that after the initial test, the use of mud 
is acceptable. Commenters suggested that BSEE revise the final rule to 
allow the operator to select test fluid appropriate for the well 
conditions.
     Response: BSEE agrees with the comments about initially 
testing surface BOPs with water, then allowing other appropriate fluids 
to be used for subsequent testing. Accordingly, BSEE has revised final 
Sec.  250.737(d)(2) by clarifying that water must be used for the 
initial test of a surface BOP system, but that subsequent tests may use 
drilling, completion, or workover fluids. The revised requirement would 
address the comments raised about the use of water for post-initial 
testing while still preserving well integrity by not reducing the 
hydrostatic column.

Comments Related to Proposed Sec.  250.737(d)(2)(ii)--72-Hour Surface 
BOP System Test Notification

    Summary of comments: A commenter also suggested that the initial 
test of surface BOPs should be the only applicable test requiring 72-
hour notice to BSEE; subsequent testing must comply with the test 
frequency required by the rules, so notification to BSEE of subsequent 
tests should not be required.
     Response: BSEE agrees with the comment and has revised 
final Sec.  250.737(d)(2)(ii) by clarifying BSEE's intent that the 
notice requirements for this paragraph apply only to the initial test.

Comments Related to Proposed Sec.  250.737(d)(3)(iii)--72-Hour Stump 
Test Notification

    Summary of comments: Multiple commenters recommended deleting Sec.  
250.737(d)(3)(iii), which requires the operator to notify the BSEE 
District Manager at least 72 hours before the stump test so BSEE 
representative(s) can witness the testing.
     Response: BSEE has not made any changes to Sec.  
250.737(d)(3)(iii). BSEE requires notification to help ensure 
compliance with the approved permits.

Comments Related to Proposed Sec.  250.737(d)(3)(iv)--BOP Stump Test 
ROV Functions

    Summary of comments: Two commenters recommended adding more 
specific details to paragraph (d)(3)(iv), which requires testing and 
verification of all ROV intervention functions on subsea BOP stacks 
during stump testing. The commenters suggested replacing ``all ROV . . 
. function'' with specific functions (i.e., the shear ram close, one 
pipe ram close, and the LMPR unlock/unlatch intervention).
     Response: BSEE has not made any changes to Sec.  
250.737(d)(3)(iv), because the relevant ROV capabilities were revised 
in final Sec.  250.734(a)(4) to reduce the scope of ROV intervention 
function capability to critical operations only (e.g., operation of 
each shear ram, ram locks, one pipe rams, and LMRP disconnect), similar 
to API Standard 53 and those specified by the commenter.

Comments Related to Proposed Sec. Sec.  250.737(d)(4)(i) and (v)--API 
Standard 53

    Summary of comments: Other commenters asserted that the additional 
requirements for subsea BOP testing proposed in Sec.  250.737(d)(4)(i) 
and (v) conflict with API Standard 53. Under paragraph (d)(4)(i), there 
is not a specified timing requirement between conducting the stump 
testing and the on-bottom installation test; the time between these 
tests is a risk-based operational decision and is determined by the 
operator and equipment owner. The commenter says that API Standard 53 
discusses initial subsea testing and specifies blind shear ram or pipe 
rams only need to be functioned by an ROV, and not pressure tested, and 
that they only have to be tested annually.
     Response: BSEE has not made any changes to Sec.  
250.737(d)(4). Operators are aware and test according to the 30 day 
timeframe, as it is based on current Sec.  250.449(b). The timeframe 
between the initial test and the stump test under Sec.  250.449(b) 
provides adequate time conduct each test. Furthermore, BSEE wants to 
minimize time between these tests to help ensure the components and BOP 
system as a whole can function as intended and tested. BSEE does not 
agree with the commenter about only testing certain components annually 
as this does not provide an acceptable level of confidence that the 
component would function as intended.

Comments Related to Proposed Sec.  250.737(d)(5)--API Standard 53

    Summary of comments: Multiple commenters expressed several concerns 
with requirements in proposed Sec.  250.737(d)(5), including: The 
differences between API Standard 53 and this section regarding pod and 
control station testing; absence of a definition of ``function 
testing;'' confusion about the pod testing rotation; and unnecessary 
testing of remote stations used in emergency situations.
     Response: BSEE agrees with some of the concerns raised by 
the comments, and BSEE has revised final Sec.  250.737(d)(5)(i)(C) by 
deleting the phrase ``and the pod used for pressure testing must be 
alternated between

[[Page 25968]]

pressure tests'' and inserting in its place ``and 14-day pressure 
testing.'' This change will simplify and align the pod testing rotation 
with the required 14-day BOP pressure testing under the final rule and 
improve consistency between paragraphs (d)(5)(i)(A) and (B). Thus, it 
will resolve or minimize the concern raised by the comments regarding 
potential confusion over pod testing rotation and potential differences 
between the proposed requirement and API Standard 53.
    In addition, BSEE has revised final Sec.  250.737(d)(5)(ii) by 
replacing the phrase ``any additional control stations must be function 
tested every 14 days'' with ``remote panels where all BOP functions are 
not included (e.g., life boat panels) must be function tested upon the 
initial BOP tests and monthly thereafter.'' This revision addresses the 
commenters' concerns regarding unnecessary testing of remote stations 
used in emergency situations by ensuring that the EDS panels are not 
operated every 14 days, which could increase risk to the rig crew due 
to the functions that those panels operate. The additional time 
provided by the revised language to test these remote panels will also 
provide more flexibility to conduct the tests at optimum times in order 
to limit risks to the rig crew.
    These changes to final Sec.  250.737(d)(5)(i)(C) and (d)(5)(ii) 
also improve consistency with API Standard 53 and help reduce any 
potential confusion related to testing of the pods and control 
stations. BSEE requires pod and control station testing, to ensure 
proper use of the safety equipment and to reduce the risk of non-
functioning equipment, because all control stations have the potential 
to become critical control mechanisms during well-control events.
    BSEE does not agree that there is any need to define ``function 
testing'' in the rules. The term has been used in the existing 
regulations for many years and the industry is familiar with its 
meaning.

Comments Related to Proposed Sec.  250.737(d)(6) and (7)--API Standard 
53

    Summary of comments: Commenters observed that Sec.  250.737(d)(6) 
conflicts with API Standard 53, which requires testing both the largest 
and smallest pipe sizes during the stump test, and then subsequently 
testing the smaller pipe. Commenters recommended aligning this 
provision with API Standard 53.
    Commenters also noted that the requirement to pressure test annular 
type BOPs against the smallest pipe in use is a new requirement. 
Commenters recommended that BSEE require pressure testing of the 
annular-type BOPs against the largest and smallest drill pipe in use 
during the stump test; then, for subsea BOP pressure tests, pressure 
testing the annular BOPs against the smallest outside diameter drill 
pipe used in the hole section.
     Response: BSEE agrees with the commenters and has revised 
final Sec.  250.737(d)(6) and (7) by replacing ``against the largest 
and smallest sizes of the pipe in use'' with ``against pipe sizes 
according to API Standard 53.'' This revision would help reduce wear of 
the equipment and thus improve overall integrity of the system and 
limit rig personnel's risks from hazardous operations such as tripping 
in and out of the hole.

Comments Related to Proposed Sec.  250.737(d)(9)--BOP Function Test

    Summary of comments: Commenters suggested adding to Sec.  
250.737(d)(9) that pressures tests qualify as function tests.
     Response: No changes to Sec.  250.737(d)(9) are necessary. 
Function testing must occur every 7 days. During a pressure test, the 
component will have to function to close and seal before a pressure 
test can be completed on that component. Therefore, it would also 
qualify as a function test without the need for any additional language 
in this provision.

Comments Related to Proposed Sec.  250.737(d)(12)--ROV Intervention 
Functions

    Summary of comments: Multiple comments raised concerns with Sec.  
250.737(d)(12), including confusion about the ROV capabilities and 
testing, compatibility with the BOP stack, and ROV closing timeframes. 
A commenter proposed moving the requirements to Sec.  250.737(d)(3) and 
deleting Sec.  250.737(d)(12).
     Response: As suggested by the commenter, BSEE deleted 
proposed Sec.  250.737(d)(12) from the final rule. ROV testing is 
sufficiently covered under final Sec.  250.737(d)(3) which requires 
testing of all ROV functions.

Comments Related to Proposed Sec.  250.737(d)(13)--API Standard 53

    Summary of comments: Multiple commenters had concerns with proposed 
Sec.  250.737(d)(13), including concerns about possible inconsistency 
between the rule and API Standard 53 with regard to testing frequency 
and testing autoshear and deadman systems separately. A commenter 
stated that if API Standard 53 is not adopted, BSEE should consider a 
3-year grace period for all rigs to make upgrades to existing control 
systems that would allow low probability/low risk deadman testing to be 
performed on all rigs. A commenter stated that testing the deadman 
circuit is desirable, but doing such testing at present would put many 
operations at risk because they would have to cut off rig power to 
simulate a deadman test and would not have access to power on the rig 
if an incident occurred.
     Response: After considering the comments, BSEE has revised 
final Sec.  250.737(d)(12) to allow the function tests for the 
autoshear/deadman to be combined. Many rigs have already voluntarily 
updated the BOP control systems with an autoshear/deadman testing 
circuit to reduce the risk of not having component operability during 
the testing.
    BSEE does not agree, however, with the comment about adopting API 
Standard 53's testing timeframe or schedule. The final rule will 
require the initial on-bottom test to verify component operability on 
the well. This test provides assurance that the system was not damaged 
while running and latching the BOP on the well, and that it will 
operate under the conditions that it might confront in an emergency. 
These requirements are consistent with established longstanding 
practice, and operators do not need additional time to comply.

Comments Related to Proposed Sec.  250.737(e)--BOP Shear Test

    Summary of comments: A commenter suggested that the OEM should 
perform the shear testing at the OEM test facility and not on the unit 
using the drilling contractor's BOP stack. The commenter stressed that 
there is a risk of damaging equipment when carrying out shear tests. 
Equipment manufacturers should be responsible for demonstrating 
shearing capability as well as providing shearing data that would allow 
for a better understanding of the equipment shearing capability.
     Response: BSEE has not made any changes to Sec.  
250.737(e). BSEE agrees that testing to actually shear pipe should be 
done at a test facility. BSEE does not intend for, nor require, the 
shear testing to be done on the rig.

What must I do in certain situations involving BOP equipment or 
systems? (Sec.  250.738)

    As described in the proposed rule, this section combines and 
revises requirements from former Sec. Sec.  250.451 and 250.517 for 
actions that must be taken when specific situations involving BOP 
systems arise (e.g., failure of a BOP to hold pressure during a test; 
needed

[[Page 25969]]

repairs to a BOP system). The required actions include correction of 
problems (e.g., repair or reconfiguration of the BOP), retesting the 
affected equipment or system, and installation of barriers prior to 
removal of a BOP, depending on the situation. BSEE has revised certain 
provisions of proposed Sec.  250.738 in the final rule as discussed in 
the comment responses for this section and in part V.C of this 
document.

Comments Related to Proposed Sec.  250.738(a)--BOP Equipment Does Not 
Hold the Required Pressure During Testing

    Summary of Comments: Commenters generally supported requirements in 
Sec.  250.738(a) for situations when BOP equipment does not hold the 
required pressure during testing. Several commenters requested a change 
to the requirement to exclude minor issues which are easily solved or 
remediated. The proposed revisions are as follows: ``You must report 
any equipment failures, including leaks that cannot be remedied, to the 
District office and on the daily report as required in Sec.  250.746.'' 
One commenter suggested that in addition to reporting the problem and 
retesting the affected equipment, the well must be secured and 
operations suspended until the BOP is successfully pressure tested, or 
repaired, or replaced in accordance with Sec.  250.738.
     Response: BSEE agrees with the comment about limiting the 
reporting requirements, and BSEE has revised Sec.  250.738(a) by 
removing the requirement for reporting to the District Manager. The 
reporting to the District Manager is unnecessary because the 
information will still be included in the daily report, and the report 
is available for BSEE review. BSEE has not made any other changes to 
this paragraph. The commenter's suggestions about what to do if you 
have to repair or replace the BOP if leaks are observed are covered 
under Sec.  250.738(b).

Comments Related to Proposed Sec.  250.738(b)--Repair, Replacement, or 
Reconfiguration of the BOP System

    Summary of Comments: Commenters generally supported requirements in 
Sec.  250.738(b) for repair, replacement, or reconfiguration of a 
surface or subsea BOP system. Several commenters requested a change 
from the term ``BOP system'' to ``BOP stack,'' so that a BOP surface 
component does not affect operations and can be replaced without having 
to put the well in a safe controlled condition. Other comments 
suggested changing the word ``certifying'' in Sec.  250.738 (b)(3) to 
``verifying.''
     Response: BSEE disagrees with the comment about the need 
to change the term ``BOP system'' in Sec.  250.738(b) to ``BOP stack,'' 
because there are many other important components of a BOP system 
(e.g., the subsea wellhead connector, the LMRP connector, the choke and 
kill lines on the LMRP and on the marine riser system) that are 
typically not considered part of the BOP stack. Therefore, no changes 
are necessary to paragraph (b) in this regard. BSEE also does not agree 
that it is necessary to change the word ``certifying'' to ``verifying'' 
in paragraph (b)(3). BSEE wants to ensure the BOP is appropriate for 
use and the BAVO certifying report provides BSEE with important 
information to consider in its approval for resuming operations.

Comments Related to Proposed Sec.  250.738(d)--BOP Control Station or 
Pod

    Summary of Comments: Commenters generally supported requirements in 
Sec.  250.738(d) for a BOP control station or pod that does not 
function properly. One commenter suggested revisions for clarity by 
suggesting the following change to paragraph (d): ``A BOP control 
station or pod does not function properly or no longer provides the 
required minimum level of redundancy.'' Another commenter stated that 
the term ``[function] properly'' is vague and misleading and that 
paragraph (d) seems to conflict with paragraph (o).
     Response: BSEE disagrees with the comment about making any 
changes to the pod requirements of Sec.  250.738(d). The suggested 
phrase ``or no longer provides the required minimum level of 
redundancy'' is unnecessary. BSEE expects both control pods to be 
functional to ensure there is continuous BOP operability and control in 
case of emergency situations. When one of the pods is damaged or fails, 
the other pod must still be able to operate the BOP stack. Therefore, 
BSEE has not made any changes to paragraph (d).
    BSEE disagrees with the commenters' concerns about the term 
``[functions] properly'' in Sec.  250.738(d). BSEE requires two pods so 
they are not considered redundant equipment under Sec.  250.738(o). 
BSEE needs to ensure that the pods can operate the required components 
of the BOP stack in an emergency situation. Therefore no changes are 
necessary to this paragraph. If there are any concerns about a specific 
operational limit of your pod functionality, contact the appropriate 
District Manager for guidance.

Comments Related to Proposed Sec.  250.738(e)--Tapered String

    Summary of Comments: Commenters generally supported requirements in 
Sec.  250.738(e) for operations with a tapered string. Comments were 
submitted on the requirement to install two sets of pipe rams to seal 
around the smaller pipe. Commenters did not see the need for a 
redundant ram on the smaller size pipe provided the pipe is not across 
the BOP stack while drilling. They stated that the annular provides a 
redundant means to seal against the smaller pipe. Commenters suggested 
revising the provision to say: ``. . . two sets of rams must be capable 
of sealing around the larger-size drill string and two sets of pipe 
rams must be capable of sealing around the smaller size pipe in the 
event that this smaller pipe is across the BOP stack when drilling, or 
one set capable of sealing on the smaller size pipe if the pipe will 
not be across the BOP while drilling . . . .''
     Response: BSEE agrees with the comment about only 
requiring one set of pipe rams to seal on the smaller size pipe and has 
revised final Sec.  250.738(e) by replacing the requirement to install 
``two'' sets of pipe rams capable of sealing around the smaller size 
pipe with ``one'' set. This change does not decrease the sealing 
capabilities of the BOP stack because many BOP stacks use VBRs, that 
can seal around a greater variety of pipe sizes and, as the commenter 
stated, the annular is also used to seal around the smaller pipe sizes.

Comments Related to Proposed Sec.  250.738(f)--Casing Rams or Casing 
Shear Rams on a Surface BOP Stack

    Summary of Comments: Multiple commenters had concerns about the 
requirements in proposed Sec.  250.738(f) for installing casing rams or 
casing shear rams in a surface BOP stack. The comments stated that the 
proposed requirement conflicts with API Standard 53 and implies that 
casing (not just drill pipe) has to be sheared. Commenters noted that 
API Standard 53 does not specify a need to shear casing. Commenters 
also recommended revisions to the language regarding testing the ram 
bonnets before running casing, as follows: ``. . . Test the ram 
bonnets' seals before running casing to the RWP or MASP\`MAWHP' plus 
500 psi.''
     Response: BSEE agrees with the concerns related to the 
reference to shearing casing, not just drill pipe and revised final 
Sec.  250.738(f) by removing the sentence ``[t]he BOP must also provide 
for sealing the well after casing

[[Page 25970]]

is sheared.'' BSEE recognizes that this statement is not necessary in 
this location, as there are shearing capability requirements covered in 
more detail throughout this subpart (e.g., Sec.  250.732(b)).
    BSEE also agrees with the commenters' concern about testing the ram 
bonnets and has revised paragraph (f) by replacing ``ram bonnets'' with 
``affected connections.'' BSEE recognizes that testing the ram bonnets 
does not properly address the necessary testing to ensure BOP system 
integrity. Testing the affected connections is a better indicator of 
proper ram installation that shows system pressure integrity.

Comments Related to Proposed Sec.  250.738(g)--Annular BOP

    Summary of Comments: One comment was received on the requirements 
in Sec.  250.738(g) for use of an annular BOP with a RWP less than the 
anticipated surface pressure. The commenter points out that paragraph 
(g) would allow an operator to use an annular BOP with an RWP less than 
the anticipated surface pressure, with BSEE approval; yet for safe 
operations, the annular BOP should have an RWP to match or exceed the 
anticipated surface pressure. Commenters suggest that DOI should 
provide further justification for this practice and include limitations 
on when this practice would be safe.
     Response: BSEE disagrees with the comment. Annulars are 
typically used with wellbore pressures less than MASP. An annular does 
not have any locking mechanisms to keep it closed, as do pipe and blind 
shear rams, and an annular will relax and not seal if the hydraulic 
pressure is lost. Thus, a single annular is not commonly used for well 
control purposes; rather, annulars are commonly used in conjunction 
with other MASP-rated components, such as pipe rams or blind shear 
rams, that can seal the well under MASP. The annular is used for quick 
closing and spacing of the joint so the well-control rams can close on 
a desired section of pipe. Because of the annular design, it is used 
differently than well-control rams; its design allows for pipe to be 
pulled through it, such as in stripping operations, and for piping 
spaceout in the BOP. Therefore, no changes are needed to paragraph (g).

Comments Related to Proposed Sec.  250.738(j)--Removing the BOP Stack

    Summary of Comments: One comment was submitted on the proposed 
requirement in Sec.  250.738(j) to remove the BOP stack. The commenter 
requested that the requirement to have two barriers in place prior to 
BOP removal be revised to require two independent tested and verified 
barriers.
     Response: BSEE does not agree with the suggested changes. 
It is not necessary to revise Sec.  250.738(j) given that barriers must 
be independently tested, to ensure integrity before removing the BOP 
stack. Nor is any change needed to clarify that the barriers must be 
tested before moving off location. Section 250.720(b) effectively 
requires that the barriers be tested before removing mud from the riser 
in preparation for removing the BOP stack.

Comments Related to Proposed Sec.  250.738(k)--Deadman or Autoshear 
Activation

    Summary of Comments: One comment was submitted on the proposed 
requirement in Sec.  250.738(k) requirements related to deadman or 
autoshear activation. The commenter described the requirements as too 
prescriptive and suggested that BSEE revise paragraph (k) by replacing 
the phrase ``place the blind shear ram opening function in the block 
position prior to re-establishing power to the stack'' with the phrase 
``Then you must address that possibility prior to re-establishing power 
to the stack.''
     Response: BSEE disagrees that the language should only 
require the operator to address the possibility of the BSR opening upon 
re-establishing power to the BOP stack. BSEE is aware of situations 
where the BSR opened upon re-establishing power to the BOP stack, and 
BSEE wants to ensure that the well is not unsecured prematurely and 
that the operator is prepared for the use of well-control measures if 
necessary. Therefore, no changes to Sec.  250.738(k) are necessary.

Comments Related to Proposed Sec.  250.738(l)--BOP Test Ram

    Summary of comments: Multiple comments were submitted on the 
proposed Sec.  250.738(l) requirements that would apply if a test ram 
is used. A commenter had concerns about the maximum pressure for the 
approved ram test for the well. Commenters also requested that 
hydraulic connectors, wet-mate connectors, and all stabs be exempted 
from the test.
     Response: BSEE agrees with most of the commenters' 
concerns and has revised final Sec.  250.738(l) by replacing that 
entire paragraph with a requirement that the wellhead/BOP connection 
must be tested to the MASP plus 500 psi for the hole section to which 
it is exposed, and providing that this can be done by: Testing the 
wellhead/BOP connection to the maximum MASP plus 500 psi for the well 
upon installation; or pressure testing each casing to the MASP plus 500 
psi for the next hole section; or some combination of those two tests. 
These changes align the regulations with current BSEE policy and 
practice related to testing the wellhead/BOP connections. These changes 
provide clarity to BSEE's testing requirements. BSEE also agrees, in 
part, with the need to remove the hydraulically operated BOP components 
language of paragraph (l). BSEE removed this provision in this 
paragraph because it is sufficiently covered under Sec.  250.737(d)(4).

Comments Related to Proposed Sec.  250.738(o)--Redundant Components

    Summary of comments: Multiple comments were submitted on the 
proposed Sec.  250.738(o) requirements for installation of redundant 
components for well control in BOP systems. The comments suggested that 
BSEE revise the paragraph (o) to require a one-time identification and 
certification submitted with documentation under proposed Sec.  
250.731, including identification of all additional redundant 
components and certification using failure modes analysis by a BAVO 
that the failure of those additional redundant components will not 
impact the BOP in a way that will make it unfit for well-control 
purposes. One other commenter suggested that the requirement to submit 
a report each time a redundant component fails can actually be a 
deterrent to operators who would otherwise want to achieve higher 
safety levels by incorporating redundancy beyond the required levels.
     Response: BSEE disagrees with the commenters' concerns 
about the failure of redundant components. If redundant components are 
installed and planned to be used as necessary, they need to be able to 
fully function and operate (similarly to the required components) as 
intended. The operator has the option to utilize the redundant systems 
without having to pull the stack, as long as the failure does not 
interfere with the required functionality. Therefore, no changes to 
Sec.  250.738(o) are necessary.

Comments Related to Proposed Sec.  250.738(p)--Bottom Hole Assembly

    Summary of comments: Comments were submitted on the proposed 
requirements in Sec.  250.738(p) for tripping the BOP and bottom hole 
assembly positioning. Most commenters raised concerns about the 
requirement to ensure well stability for 30 minutes prior to 
positioning the bottom hole assembly. They stated that determining

[[Page 25971]]

stable well conditions should not be regulated to a prescribed time 
requirement, and that other methods should be permitted, such as flow 
checks, tripping volumes, or well monitoring. Comments were also raised 
about the using the term ``immediate'' with regard to removing the 
bottom hole assembly from across the BOP in the event of a well control 
or emergency situation. The commenters' suggestions for revision to 
paragraph (p) included deleting the word ``immediate'' and stating in 
the well-control plan that removing non-shearables from across the BOP 
stack is to be done as efficiently as possible without jeopardizing the 
safety of personnel. The comment recommended that this removal occur 
prior to positioning the bottom hole assembly into the BOP. Another 
comment recommended that this provision require a minimum 5-minute flow 
check on the trip tank to confirm that the well is not flowing, after 
which the bottom hole assembly may be tripped through the BOP.
     Response: BSEE agrees with most of the commenters' 
suggestions and has revised final Sec.  250.738(p) by removing the 
reference to the 30 minute timeframe and deleting the word 
``immediate'' before ``removal of the bottom hole assembly.'' BSEE 
recognizes there are many suitable methods to ensure that a well is 
stable, as the comments suggested. BSEE understands that, for every 
well, the bottom hole assembly will be across the BOP stack, and it is 
BSEE's intention to ensure that there are procedures in place to limit 
this exposure across the BOP stack at some point. BSEE removed 
``immediate'' from the regulatory text to enable appropriate actions to 
be taken to make sure the well is secure and to ensure safety.

What are the BOP maintenance and inspection requirements? (Sec.  
250.739)

    As provided for in the proposed rule, this section combines and 
revises requirements from several sections of the existing regulations 
regarding maintenance and inspection of BOPs. This section now requires 
BOP maintenance and inspection procedures to meet or exceed OEM 
recommendations, recognized engineering practices, and industry 
standards incorporated by reference into the regulations. It also 
establishes procedures for a complete breakdown and inspection of the 
BOP and associated components every 5 years, which can be done in 
phased intervals (a change from the proposed rule), and requires that 
the inspection be documented and that a BAVO be present during the 
inspection. In addition, the final rule requires frequent visual 
inspections of all BOPs, and that personnel who maintain, inspect, or 
repair BOPs or other critical components meet certain training 
criteria. BSEE has revised proposed Sec.  250.739 in the final rule as 
discussed in the comment responses for this section and in part V.C of 
this document.

Comments Related to Proposed Sec.  250.739(a)--Critical Components and 
Recognized Engineering Practices

    Summary of comments: Several commenters requested clarification of 
the phrases ``critical components'' and ``recognized engineering 
practices and industry standards'' in proposed Sec.  250.739(a), 
stating that the terms are vague and open to inconsistent 
interpretation. They also requested a description of what the 
deliverables would be for conformance to API Standard 53. Several 
commenters requested that BSEE revise paragraph (a) to require that 
operators maintain and inspect their BOP systems, as defined in API 
Standard 53 1.1.2, to ensure that the equipment functions as designed. 
The commenters also suggested that all BOP maintenance and inspections 
must meet the equipment owner's preventative maintenance program, and 
that operators must: Document how they met or exceeded the provisions 
of API Standard 53; maintain complete records to ensure the required 
traceability of the equipment; and record the results of the 
inspections and maintenance actions; and make all records available to 
BSEE upon request.
     Response: BSEE agrees with the comment about defining all 
critical components and has revised final Sec.  250.739(a) by replacing 
``all critical components'' with ``BOP stack equipment.'' However, BSEE 
does not agree with the commenters' recommendation for revisions to 
paragraph (a) concerning the references to API Standard 53 and owners' 
preventative maintenance programs. This section already requires the 
BOP maintenance and inspections to meet or exceed API Standard 53. 
Thus, the commenters' proposed reference to the owner's preventative 
maintenance program would not be appropriate. BSEE is aware of major 
differences between different owners' preventative maintenance 
programs. BSEE realizes that such programs are useful to help plan and 
ensure maintenance and inspections are completed. But due to the 
differences between company-specific programs, BSEE cannot rely on a 
reference to such programs in paragraph (a) to satisfy the BOP 
maintenance and inspection requirements of this provision.

Comments Related to Proposed Sec.  250.739(b)--BOP Breakdown and 
Inspection

    Summary of comments: Multiple commenters expressed concerns with 
the 5-year testing provision in proposed Sec.  250.739(b), which would 
have required complete breakdown and inspection of the BOP system and 
every associated component at one time. Most industry commenters did 
not object to a 5-year inspection requirement for each BOP component, 
provided that the inspections could be staggered, or phased, over time, 
as provided in API Standard 53. Commenters expressed concern that 
requiring all components to be inspected at one time would put too many 
rigs out of service, potentially for long periods of time, with 
substantial economic impacts.
     Response: BSEE agrees with the commenters' concerns about 
performing the 5-year major inspection of the entire BOP system and all 
components at one time. Accordingly, BSEE has revised final Sec.  
250.739(b) by: Allowing the complete breakdown and inspection to be 
performed in phased intervals; adding clarification that all system and 
component inspection dates must be tracked, documented, and available 
on the rig; and including new paragraphs (b)(1), (2), and (3) 
describing the types of actions that could be used as start dates for 
the inspection intervals. The final regulatory language will allow a 
phased approach, as long as there is proper documentation and tracking 
to ensure that BSEE can verify that each applicable component has had a 
major inspection within the preceding 5 years. Proper documentation 
will improve BSEE oversight, as compared to current practice, while a 
phased approach would avoid the possibility of long shut downs. BSEE 
added the list of actions that can be used to start the 5-year 
timeframe, which are consistent with API Standard 53, to provide 
additional clarity.

Comments Related to Proposed Sec.  250.739(d)--Personnel Training

    Summary of comments: Several commenters raised concern with the 
proposed Sec.  250.739(d) training requirements, stating that: BOP 
equipment OEMs do not specify qualification and training criteria; OEM 
training courses do not address every aspect of maintenance and 
troubleshooting that is encountered in the field; and training is 
covered under the SEMS program requirements.

[[Page 25972]]

Commenters suggested revisions to proposed Sec.  250.739(d), including 
requiring: Personnel who maintain, inspect, or repair BOPs or other 
critical components to meet the qualifications and training criteria 
specified by the equipment owner; consideration of OEM guidelines; and 
performing maintenance, inspection, and repair in accordance with API 
Standard 53.
     Response: BSEE agrees with several of the suggestions in 
these comments and has revised final Sec.  250.739(d) by requiring that 
personnel be trained in accordance with all applicable training 
requirements in subpart S, any applicable OEM criteria, recognized 
engineering practices, and industry standards incorporated by reference 
in final subpart G. These revisions, made in response to the comments, 
clarify BSEE's intent to ensure that all personnel are trained properly 
for the equipment that they will maintain, inspect, or repair.

Comments Related to Proposed Sec.  250.739(e)--Retention of Equipment 
Design Records

    Summary of comments: Several commenters raised concerns with the 
retention of equipment design records proposed in Sec.  250.739(e) and 
suggested alternative language. Commenters stated that equipment 
designs are proprietary information of the OEM; therefore, the design 
records can only be retained by the OEM. Further, commenters stated 
that retention of this information is required by the OEM to meet API 
manufacturing specifications. Commenters also stated that modifications 
to the functional design of the stack are maintained by the equipment 
owner; therefore, it should be the responsibility of the equipment 
owner to maintain all required records.
     Response: BSEE agrees with the commenters' concerns about 
retention of equipment design records and has revised the last sentence 
in final Sec.  250.739(e) to require that the operator ensure that all 
equipment schematics, maintenance, inspection, and repair records are 
located at an onshore location for the service life of the equipment. 
BSEE understands that the equipment OEMs may retain proprietary design 
documents that are not available to others. Therefore, BSEE replaced 
``design'' with ``schematics'' and revised the operator's 
responsibility from ``maintaining'' design records to ``ensuring'' that 
the equipment schematics, and other specified records, are kept at an 
onshore location. These revisions will address the commenters' concerns 
that only the OEM may have the original design records and that only 
the equipment owner may have design modification records. BSEE 
understands that the equipment schematics are usually made available by 
OEMs. Under the revised language, the operator is only responsible for 
ensuring that the schematics and other specific records are located 
onshore (given that records located on the rig unit may become 
inaccessible or lost in the event of an emergency), whether or not the 
onshore location for each of the relevant records is the operator's, 
equipment owner's, or the OEM's.

Records and Reporting

What records must I keep? (Sec.  250.740)

    As provided for in the proposed rule, this section incorporates and 
clarifies recordkeeping requirements from former Sec.  250.466 
applicable to all operations covered under final subpart G. This 
section requires that well records, including a daily report for each 
well, must be kept onsite during well operations. Well records must 
include, among other things, complete information on: Well operations, 
all tests conducted, and RTM data; oil, gas and mineral deposits 
encountered; casings; and significant malfunctions or problems. BSEE 
has revised proposed Sec.  250.740 in the final rule as discussed in 
the comment responses for this section and in part V.C of this 
document.

Comments Related to Proposed Sec.  250.740(a)--RTM and Well Data

    Summary of comments: A commenter contested the RTM aspects of the 
rule in proposed Sec.  250.740(a). This commenter indicated that BSEE 
uses ``real-time monitoring'' to encompass both well-site and remote 
monitoring at an onshore location, which are two separate activities. 
The commenter stated that well-site monitoring is a standard practice, 
whereas remote monitoring is not. The commenter recommended replacing 
``real-time monitoring data'' with ``well data.'' Another commenter 
asked whether this provision would require additional RTM (presumably 
beyond what proposed Sec.  250.724 would require).
     Response: BSEE disagrees with the suggestion to remove the 
reference in paragraph (a) to the RTM data. BSEE is requiring RTM data 
in final Sec.  250.724, and Sec.  250.740(a) is intended to require 
operators to preserve the RTM data collected pursuant to Sec.  250.724. 
BSEE is not imposing additional RTM obligations beyond those required 
in Sec.  250.724. To clarify that point, BSEE has added to final Sec.  
250.740(a), after the reference to real-time monitoring data, ``as 
required by Sec.  250.724.''
    BSEE also disagrees with the suggestion that paragraph (a) be 
limited to ``well data'' (presumably because the commenter believed 
that the revision would eliminate the need to retain records onshore 
related to ``remote'' RTM). Section 250.724 requires that RTM data be 
gathered offshore to be transmitted to an onshore location. BSEE may 
need to review the RTM data at the onshore location if there is an 
incident. Similarly, BSEE may need to review the retained RTM data 
onshore after an incident, in order to verify conditions at the time of 
the incident and to assist in an incident investigation. If the 
commenter's suggested revision was intended to limit the data BSEE can 
review onshore, then BSEE rejects that suggestion.

Comments Related to Proposed Sec.  250.740(d)--Kind, Weight, Size, 
Grade, and Setting Depth of Casing

    Summary of comments: Commenters recommended that BSEE clarify the 
information required by proposed Sec.  250.740(d), regarding records on 
kind, weight, size, grade, and setting depth of casing. The comments 
suggested that BSEE revise paragraph (d) to read: ``Information 
relative to casing and cementing such as weight, size, grade, and 
setting depth of casing and volume and type of cement pumped along with 
cementing pressures and displacements.''
     Response: BSEE does not agree that the revision suggested 
by the commenters is necessary or would provide any additional clarity 
for this recordkeeping requirement. The scope of these records is 
already clarified by the detailed requirements in final Sec.  
250.415(a)(3) regarding information about cementing and casing programs 
that must be provided in APDs. BSEE expects that records specified in 
Sec.  250.740(d) will include the information specified in Sec.  
250.415(a)(3).

Comments Related to Proposed Sec.  250.740(f)--Any Significant 
Malfunction or Problem

    Summary of comments: A commenter asserted that the requirement in 
proposed Sec.  250.740(f) regarding recordkeeping for ``any significant 
malfunction or problem'' is ambiguous. This commenter recommended that 
BSEE provide some examples of what type of malfunction or problem for 
which it suggests keeping records, noting that there is already a 
requirement for equipment failure reporting, and that well-control 
events

[[Page 25973]]

and other drilling-related problems are documented in the daily well 
reports.
     Response: BSEE does not agree that this provision is 
ambiguous or that the recordkeeping required by Sec.  250.740(f) is 
duplicative of other reporting requirements in this rule. Although 
there are several specific reporting requirements in this rule for 
subjects similar to the records required by Sec.  250.740(f) (e.g., 
Sec.  250.738(a) requires reporting of irregularities or problems 
resulting from pressure testing), there are no specific record keeping 
requirements for all significant malfunctions or problems. BSEE needs 
to ensure that records of all significant malfunctions or problems are 
maintained so that BSEE can review the records as needed to assist in 
the investigation of any incident or significant problem. The 
requirements for reporting specific events to BSEE, or for keeping 
other records, does not duplicate the recordkeeping under Sec.  
250.740(f) since copies of reports or records under other provisions 
can be used to satisfy Sec.  250.740(f). Therefore, BSEE has not made 
any changes to that paragraph.

Comments Related to Proposed Sec.  250.740(g)--Information Required by 
the District Manager

    Summary of comments: Commenters requested that BSEE revise proposed 
Sec.  250.740(g) to clarify what additional information may be required 
and to define the scope of the District Manager's authority to request 
additional records. These commenters suggested defining the scope of 
information requests as information sought ``in the interests of 
resource evaluation, waste prevention, conservation of natural 
resources, and the protection of correlative rights, safety, and 
environment.''
     Response: Like similar provisions throughout 30 CFR part 
250, Sec.  250.740(g) is intended to give District Managers the 
necessary flexibility and discretion to require additional information 
as needed in specific cases to fulfill the purposes of the regulation. 
Of course, the District Managers must exercise that discretion in a 
manner consistent with BSEE's statutory authority and responsibility 
under OCSLA, including--as the commenter suggested--conservation of 
natural resources and protection of safety and the environment on the 
OCS. In addition, the District Manager must exercise the discretionary 
authority of paragraph (g) in a way that serves the purpose of Sec.  
250.740; i.e., the maintenance of records for each well that provide 
relevant information about the specific well and operations, its 
geological conditions and related circumstances, and any significant 
problems or malfunctions. Accordingly, BSEE has revised final Sec.  
250.740(g) to clarify the scope and purpose of the District Manager's 
authority.

How long must I keep records? (Sec.  250.741)

    As provided for in the proposed rule, this section incorporates the 
same requirements as former Sec.  250.467 regarding how long records 
related to drilling, casing and liner pressure tests, diverter and BOP 
tests, and completion and workover activities must be kept. This 
section also requires that records related to RTM data must be kept for 
2 years after completion of operations. There are no changes to this 
proposed section in the final rule.

Comments Related to Proposed Sec.  250.741--Electronic Recordkeeping

    Summary of comments: A commenter recommended that BSEE revise 
Sec. Sec.  250.467 and 250.741 to require records to be kept in 
electronic form for the life of the well. Longer record retention 
periods will ensure that important records are maintained and available 
to the operator and BSEE for future work on the well or during an 
investigation.
     Response: BSEE disagrees with the commenter that all of 
the records identified in Sec.  250.741 (which replaces former Sec.  
250.467) should be required to be kept for the life of the well. BSEE 
already requires that certain data be retained for the life of the 
well, as in final Sec.  250.741(c). BSEE determined that the specific 
retention timeframes for the information listed in Sec.  250.741(a) 
through (c) are reasonable and appropriate for the purpose of allowing 
BSEE to review the information in the event of an incident or 
investigation or to determine compliance with requirements of this 
subpart. Those timeframes are identical to those in the former Sec.  
250.467 (with the exception of the new requirement for RTM data), which 
has been in effect for many years, and BSEE is not aware of any 
instances in which those timeframes have proven inadequate. 
Accordingly, BSEE does not see a need at this time for expanding those 
timeframes as suggested by the commenter.

Comments Related to Proposed Sec.  250.741(b)--Casing and Liner 
Pressure Tests, Diverter Tests, BOP Tests, and RTM Data

    Summary of comments: A commenter asserted that retention of the 
identified records under Sec.  250.741(b)--i.e., casing and liner 
pressure tests, diverter tests, and RTM data--for 2 years is not 
necessary on a decommissioning operation after the well has been 
plugged, although the commenter acknowledged that the information may 
need to be kept longer in the event of a re-drill or sidetrack. Another 
commenter recommended that BSEE revise paragraph (b) to require the 
operator to retain BOP RTM data while conducting operations on the 
well, and require the owner of the equipment to retain the BOP data for 
a period of 2 years.
     Response: The record retention requirements in final Sec.  
250.741(b) are well established under former Sec.  250.467, and BSEE is 
unaware of any problems with those record retention requirements with 
respect to decommissioning operations. In addition, the commenter that 
suggested revising the proposed requirement for retention of RTM data 
did not provide any support for that suggestion. And BSEE, based on its 
experience with the longstanding records retention requirements for the 
test data specified in former Sec.  250.467(b), sees no reason why the 
operator should not retain RTM data for 2 years. Therefore, BSEE has 
not made the suggested changes to final Sec.  250.741.

What well records am I required to submit? (Sec.  250.742)

    This section contains requirements from former Sec.  250.468 
regarding submission to BSEE of records related to well-logging 
operations, certain well surveys, velocity profiles, and core analyses. 
The remainder of the requirements from former Sec.  250.468, regarding 
well activity reporting, are included in final Sec.  250.743. BSEE 
received no substantive comments on this provision of the proposed rule 
and made no changes to the proposed language.

What are the well activity reporting requirements? (Sec.  250.743)

    As provided for in the proposed rule, this section includes 
requirements from former Sec.  250.468(b) and (c) regarding submission 
of WARs for drilling operations in the GOM and Pacific or Alaska 
regions, respectively. It also codifies reporting procedures contained 
in BSEE NTL 2009-G20, Standard Reporting Period for the Well Activity 
Report, and BSEE NTL 2009-G21, Standard Conditions of Approval for Well 
Activities.
    BSEE will rescind any NTLs that are superseded by this section in 
the final rule. BSEE received no substantive comments on this provision 
of the

[[Page 25974]]

proposed rule and made no changes to the proposed language.

What are the end of operation reporting requirements? (Sec.  250.744)

    As described in the proposed rule, this section combines provisions 
from several sections of the existing regulations, codifies certain 
procedures from NTL 2009-G21, Standard Conditions of Approval for Well 
Activities, and clarifies the contents of the EOR (Form BSEE-0125). 
This information provides BSEE with important well data and a better 
understanding of the well operations and conditions. BSEE received no 
substantive comments on this provision of the proposed rule and made no 
changes to the proposed language.

What other well records could I be required to submit? (Sec.  250.745)

    As provided for in the proposed rule, this section incorporates the 
requirements of former Sec.  250.469 regarding well records that a 
District Manager or Regional Supervisor may require an operator to 
submit. BSEE received no substantive comments on this provision of the 
proposed rule and has made no changes to the proposed language.

What are the recordkeeping requirements for casing, liner, and BOP 
tests, and inspections of BOP systems and marine risers? (Sec.  
250.746)

    As described in the proposed rule, this section combines and 
clarifies requirements from several sections of the existing 
regulations regarding recordkeeping for testing of casings, liners and 
BOPs and for BOP and marine riser inspections. It also specifies 
information that must be included in the daily report. BSEE has made 
certain revisions to proposed Sec.  250.746 in the final rule as 
discussed in the comment responses for this section and in part V.C of 
this document.

Comments Related to Proposed Sec. Sec.  250.746(a) and (b)--Test 
Pressure Records and Pressure Charts

    Summary of comments: A commenter recommended revising Sec.  
250.746(a) and (b)--regarding test pressure records and pressure 
charts--to allow the use of digital recorders as these are also an 
acceptable method for recording pressure tests.
     Response: BSEE agrees with the commenter and revised final 
Sec.  250.746(a) and (b) to include digital recorders. This change also 
aligns these provisions more closely with the digital pressure testing 
required in final Sec.  250.737(c).

Comments Related to Proposed Sec.  250.746(d)--Identification on the 
Daily Report of the Control Station and Pod Used During a BOP Test

    Summary of comments: Commenters observed that the requirement in 
proposed Sec.  250.746(d)--requiring identification on the daily report 
of the control station and pod used during a BOP test--apparently 
applies to all types of operations; however, pods are not found on 
equipment (such as surface stacks, coiled tubing units, and snubbing 
units) associated with certain operations. The commenters suggested 
that BSEE revise this paragraph to address this concern.
     Response: BSEE disagrees with the comment. It is BSEE's 
intention that the requirement to identify the pod used during testing 
applies only to testing that actually uses a pod; in fact the proposed 
and final Sec.  250.746(d) provide examples of equipment (i.e., coiled 
tubing and snubbing units) that would not require identification of a 
pod.

Comments Related to Proposed Sec.  250.746(e)--Notifying the District 
Manager of Leaks

    Summary of comments: Commenters stressed that the proposed 
requirement under Sec.  250.746(e) to immediately notify the District 
Manager of any leaks associated with BOP or control system testing is 
unnecessary, especially for equipment failures during BOP testing. 
Other commenters asserted that the proposal to suspend operations when 
any problems or irregularities are observed during testing may be 
unsafe, and that operators need to be able to handle minor problems and 
issues internally. Commenters requested that BSEE clarify under what 
circumstances leaks are considered problems. A commenter also requested 
that BSEE clarify what components are included in ``BOP Control 
Systems'' and recommended rewording the requirement for reporting ``any 
leaks'' associated with BOP or control system testing to require 
reporting of ``unresolved leaks'' associated with such testing.
     Response: BSEE agrees with the commenters' suggestion 
regarding the requirement for ``immediate'' notification to the 
District Manager of any leaks and revised final Sec.  250.746(e) by 
removing that requirement. This proposed notification is unnecessary 
because the same information must be documented in the WAR, which 
former Sec.  250.468 and final Sec.  250.743 require to be submitted to 
BSEE on a weekly basis in the Gulf region and on a daily basis in the 
Alaska region.
    BSEE also agrees with the comment that it is not necessary, and in 
some cases may be imprudent, to suspend operations for ``any problems'' 
and revised Sec.  250.746(e) to state that ``[i]f any problems that 
cannot be resolved promptly are observed during testing. . .'' you must 
suspend operations. This change will limit the amount of shut-ins that 
might have occurred under the proposed language even though the problem 
could have been resolved before posing any significant risk. The 
problem should be evaluated first, and then, if it is determined that 
repairs or other resolution are necessary and cannot be completed 
promptly, operations must be suspended.
    BSEE has also deleted the phrase ``are considered problems or 
irregularities and'' from final Sec.  250.746(e) because not all leaks 
are considered problems and some leaks may not affect BOP system 
operability.
    BSEE is not specifically defining what a BOP ``control system'' 
consists of, however, BSEE does not want to limit an operator that may 
have elements in its control system that are not typically found in 
other BOP control systems. In general, however, BSEE expects that most 
BOP control systems will be consistent with API Standard 53's 
description of that term.

Comments Related to Proposed Sec.  250.746(f)--Record Retention

    Summary of comments: A commenter recommended that, under proposed 
Sec.  250.746(f), BSEE not require the records for pressure testing to 
be kept on the rig/facility after the operation has concluded. Rather, 
the operator should keep these records at an alternative location 
(office, records storage facility).
     Response: BSEE has not made the commenter's suggested 
revision to this section because the documentation may be necessary and 
must be available on the rig for incident investigation and auditing 
purposes.

Subpart P--Sulfur Operations

Well-Control Drills (Sec.  250.1612)

    As provided for in the proposed rule, this section updates the 
references for the drilling crew requirements under final Sec.  
250.711. BSEE received no substantive comments on this provision of the 
proposed rule and has made no changes to the proposed language in the 
final rule.

[[Page 25975]]

Subpart Q--Decommissioning Activities

What are the general requirements for decommissioning? (Sec.  250.1703)

    As provided for in the proposed rule, paragraph (b) of existing 
Sec.  250.1703 includes a new requirement that all permanent packers 
and bridge plugs must comply with API Spec. 11D1. It also requires that 
decommissioning operations must follow all applicable requirements in 
new Subpart G. BSEE has revised paragraph (b) in the final rule as 
discussed in the comment responses for this section and in part V.C of 
this document.

Comments Related to Proposed Sec.  250.1703(b)--Temporary Packers and 
Bridge Plugs

    Summary of comments: Commenters stated that, under proposed Sec.  
250.1703, compliance with API Spec. 11D1 should not be required for 
temporary packers and bridge plugs (i.e., those used for well 
servicing). Commenters stressed that API Spec. 11D1 does not apply to 
temporary packers and bridge plugs.
     Response: BSEE agrees with the commenters that this 
section should apply only to permanently installed packers and bridge 
plugs and has revised final Sec.  250.1703 accordingly.

Comments Related to Proposed Sec.  250.1703(f)--Well Abandonment

    Summary of comments: A commenter noted that Sec.  250.1703(f) adds 
a reference to the requirements of new subpart G, which would make 
subpart G applicable to decommissioning. The commenter noted that well 
abandonments are normally considered as part of the plan only for 
exploration programs and not development programs.
     Response: BSEE does not agree with this comment, and has 
not made the suggested changes to Sec.  250.1703 in the final rule, 
because some of the equipment used in drilling, workover, and 
completion operations is also used for decommissioning (e.g., MODUs and 
BOPs). That equipment must meet the requirements necessary to ensure 
safety and environmental protection without regard to the types of well 
operations in which the equipment is used.

When must I submit decommissioning applications and reports? (Sec.  
250.1704)

    As provided for in the proposed rule, paragraph (g) of existing 
Sec.  250.1704 is revised by removing current paragraphs (g)(2), (4), 
and (6) and the associated instructions in the third column, as well as 
by revising the numbering of current paragraphs (g)(3) and (5) to 
paragraphs (g)(2) and (3), respectively, and by updating the applicable 
citations. Also paragraph (h) clarifies when operators must submit an 
EOR rather than an APM. BSEE received no substantive comments on this 
provision of the proposed rule and made no changes to the proposed 
language in the final rule.

What BOP information must I submit? (Sec.  250.1705)

    As provided for in the proposed rule, this section is removed and 
reserved. The content of this former section is moved to final 
Sec. Sec.  250.731 and 250.732. BSEE received no comments on the 
proposed removal and reservation of this section and the final rule 
implements that action.

Coiled Tubing and Snubbing Operations (Sec.  250.1706)

    This section of the existing regulation was titled ``What are the 
requirements for blowout prevention equipment?'' As provided for in the 
proposed rule, this section is re-titled and moves paragraphs (a) 
through (e) of the former section to final Sec. Sec.  250.730, 250.733, 
250.734, and 250.735. Remaining paragraphs (f) through (h) of the 
existing regulation are redesignated as paragraphs (a) through (c). 
BSEE received no substantive comments on this provision of the proposed 
rule and made no changes to the proposed language in the final rule.

What are the requirements for blowout preventer system testing, 
records, and drills? (Sec.  250.1707)

    This section is removed and reserved. As described in the proposed 
rule, the content of this former section is moved to final Sec. Sec.  
250.711, 250.736, 250.737, and 250.746. BSEE received no comments on 
the proposed removal and reservation of this section and the final rule 
implements that action.

What are my BOP inspection and maintenance requirements? (Sec.  
250.1708)

    This section is removed and reserved. As provided for in the 
proposed rule, the content of this former section is moved to final 
Sec.  250.739. BSEE received no comments on the proposed removal and 
reservation of this section and the final rule implements that action.

What are my well-control fluid requirements? (Sec.  250.1709)

    This section is removed and reserved. As provided for in the 
proposed rule, the content of this former section is moved to final 
Sec.  250.720. BSEE received no comments on the proposed removal and 
reservation of this section and the final rule implements that action.

How must I permanently plug a well? (Sec.  250.1715)

    As provided for in the proposed rule, BSEE proposed to revise 
paragraph (a)(3)(iii)(B) of existing Sec.  250.1715 to require that 
``casing'' bridge plugs must be set 50 to 100 feet above the top of the 
perforated interval. After consideration of comments on the proposed 
rule, BSEE has made no changes to the proposed language in the final 
rule.

Comments Related to Proposed Sec.  250.1715--Abandonment and Isolating 
Zones

    Summary of comments: A commenter suggested revising Sec.  250.1715 
to add new regulatory requirements for abandonment and isolating zones.
     Response: This comment and the suggested revision to Sec.  
250.1715 are outside the scope of this rulemaking, and the suggested 
changes are not necessary or appropriate for consideration at this 
time.

After I permanently plug a well, what information must I submit? (Sec.  
250.1717)

    This section is removed and reserved. The content of this former 
section is moved to final Sec.  250.744. BSEE received no comments on 
the proposed removal and reservation of this section and the final rule 
implements that action.

If I temporarily abandon a well that I plan to re-enter, what must I 
do? (Sec.  250.1721)

    As provided for in the proposed rule, paragraph (g) is removed from 
existing Sec.  250.1721 and former paragraph (h) is redesignated as 
paragraph (g). The content of former paragraph (g)--regarding 
submission of an APM within 30 days after temporarily plugging a well--
has been moved to final Sec.  250.744. BSEE received no substantive 
comments on this provision of the proposed rule and made no changes to 
the proposed language in the final rule.

VII. Derivation Tables

    The following tables are intended to provide information about the 
derivation of new requirements in subparts A, B, D, E, F, G, P, and Q 
of part 250. These tables illustrate:

-- The destination of various current requirements.
-- The organization and content of the revisions.

    These tables do not provide definitive or exhaustive guidance, and 
should be used as reference material and in conjunction with the 
section-by-section discussion and regulatory text of this rule.

[[Page 25976]]

    The following sections in 30 CFR part 250, subparts D, E, F, and Q 
have been [Removed and/or Reserved] according to the following table.

------------------------------------------------------------------------
                                 Removed and/or reserved in 30 CFR part
           Subpart                                250
------------------------------------------------------------------------
D............................  401, 402, 403, 406, 417, 424, 425, 426,
                                440 through 451, 466 through 469.
E............................  502, 506 through 508, 515 through 517.
F............................  602, 606 through 608, 615, 617, 618.
Q............................  1705, 1707 through 1709, 1717.
------------------------------------------------------------------------

    The rule makes changes as outlined in the following table:
BILLING CODE 4310-VH-C

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[[Page 25985]]



VIII. Procedural Matters

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

    E.O. 12866 provides that the Office of Information and Regulatory 
Affairs in the Office of Management and Budget (OMB) will review all 
significant rules. To determine if this rulemaking is a significant 
rule, BSEE prepared an economic analysis to assess the anticipated 
costs and potential benefits of the rulemaking.
    Changes to Federal regulations must undergo several types of 
economic analyses. First, E.O. 12866 and E.O. 13563 direct agencies to 
assess the costs and benefits of regulatory alternatives and, if 
regulation is necessary, to select a regulatory approach that maximizes 
net benefits (including potential economic, environmental, public 
health, and safety effects; distributive impacts; and equity). Under 
E.O. 12866, an agency must determine whether a regulatory action is 
significant and, therefore, subject to the requirements of E.O. 12866, 
including review by OMB. Section 3(f) of E.O. 12866 defines a 
``significant regulatory action'' as any regulatory action that is 
likely to result in a rule that:
    --Has an annual effect on the economy of $100 million or more, or 
adversely affects in a material way the economy, a sector of the 
economy, productivity, competition, jobs, the environment, public 
health or safety, or state, local, or tribal governments or communities 
(also referred to as ``economically significant'');
    --Creates serious inconsistency or otherwise interferes with an 
action taken or planned by another agency;
    --Materially alters the budgetary impacts of entitlement grants, 
user fees, loan programs, or the rights and obligations of recipients 
thereof; or
    --Raises novel legal or policy issues arising out of legal 
mandates, the President's priorities, or the principles set forth in 
E.O. 12866.
    BSEE determined that this rule is a significant rulemaking within 
the definition of E.O. 12866 because the estimated annual costs or 
benefits would exceed $100 million in at least one year of the 10-year 
analysis period. Accordingly, OMB has reviewed this regulation.
    The following discussion summarizes the economic analysis; for 
details, please refer to the final RIA, which can be viewed at 
www.regulations.gov (use the keyword/ID ``BSEE-2015-0002'').
1. Need for Regulation
    BSEE identified a need to amend the existing BOP and well-control 
regulations to enhance the safety and environmental protection of 
offshore oil and gas operations on the OCS. This final rule creates 30 
CFR part 250, subpart G--Well Operations and Equipment. This new 
subpart consolidates equipment and operational requirements that are 
contained in other subparts of part 250 pertaining to offshore oil and 
gas drilling, completions, workovers, and decommissioning. The rule 
also revises existing provisions throughout subparts D, E, F, and Q of 
part 250 to address concerns raised in the investigations, BSEE's 
internal reviews, the 2012 BSEE public forum and other input from 
stakeholders and the public. The rule addresses and implements multiple 
recommendations resulting from various investigations of the Deepwater 
Horizon incident.\21\ The rule also incorporates guidance from several 
NTLs and revises provisions related to drilling, workover, completion, 
and decommissioning operations to enhance safety and environmental 
protection.
---------------------------------------------------------------------------

    \21\ The DOI JIT report, September 14, 2011, Report Regarding 
the Causes of the April 20, 2010 Macondo Well Blowout; The National 
Commission final report, January 11, 2011, Deep Water, The Gulf Oil 
Disaster and the Future of Offshore Drilling; The Chief Counsel for 
the National Commission report, February 17, 2011, Macondo The Gulf 
Oil Disaster; the National Academy of Engineering final report, 
December 14, 2011, Macondo Well-Deepwater Horizon Blowout; May 22, 
2012, BSEE Public Offshore Energy Safety Forum.
---------------------------------------------------------------------------

2. Alternatives
    BSEE has considered three regulatory alternatives:
    (1) Promulgate the requirements contained in the proposed rule, 
including decreasing the BOP pressure testing frequency for workover 
and decommissioning operations from the current requirement of once 
every 7 days to once every 14 days;
    (2) Promulgate the requirements contained within the proposed rule 
with a change to the required frequency of BOP pressure testing from 
the existing regulatory requirements (i.e., once every 7 or 14 days 
depending upon the type of operation) to once every 21 days for all 
operations; and
    (3) Take no regulatory action and continue to rely on existing BOP 
regulations in combination with permit conditions, DWOPs, operator 
prudence, and industry standards as applicable to BOP systems.
    By taking no regulatory action, BSEE would leave unaddressed most 
of the concerns and recommendations that were raised regarding the 
safety of offshore oil and gas operations and the potential for another 
catastrophic event with consequences similar to those of Deepwater 
Horizon.
    Alternative 2 (changing the required frequency of BOP pressure 
testing to once every 21 days for all operations) was not selected 
because BSEE lacks critical data on testing frequency and equipment 
reliability to choose this alternative.
    BSEE has elected to move forward with Alternative 1--the final 
rule--which incorporates recommendations provided prior to the proposed 
rule by government, industry, academia, and other stakeholders. 
However, as discussed in detail earlier in this preamble, the final 
rule does include certain revisions based on BSEE consideration of 
recommendations contained in public comments on the proposed rule, 
including incorporation of relevant elements of API Standard 53 and 
related standards. In addition to addressing concerns and aligning with 
industry standards, BSEE is advancing several of the more critical 
well-control capabilities beyond current industry standards applicable 
to BOP systems based on agency knowledge, experience and technical 
expertise. The rule will also improve efficiency and consistency of the 
regulations and allow for flexibility in future rulemakings.
3. Economic Analysis
    BSEE's initial economic analysis, for the proposed rule, and final 
economic analysis evaluated the expected impacts of the rule as 
compared to the baseline, which includes current industry practices in 
accordance with existing regulations, DWOPs, and industry standards 
with which operators already comply.\22\ Impacts that exist as part of 
the baseline were not considered costs or benefits of the rule.
---------------------------------------------------------------------------

    \22\ BSEE considers compliance with permits, DWOPs, and industry 
standards to be ``self-implementing,'' as addressed in Section E.2 
of OMB Circular A-4, ``Regulatory Analysis'' (2003), and thus 
includes these costs in the baseline for the economic analysis. The 
industry standards relevant to this rule were developed by 
committees of industry members and others and subsequently approved 
by an industry standards development organization (e.g., API).
---------------------------------------------------------------------------

    The final analysis covers 10 years (2016 through 2025) to ensure it 
encompasses the significant costs and benefits likely to result from 
the rule.\23\ We used a 10-year analysis period because of the 
uncertainty associated with predicting industry's activities and

[[Page 25986]]

the advancement of technical capabilities beyond 10 years. When 
summarizing the costs and benefits, we present the estimated annual 
effects, as well as the 10-year discounted totals using discount rates 
of 3 and 7 percent, per OMB Circular A-4, ``Regulatory Analysis'' 
(2003).
---------------------------------------------------------------------------

    \23\ The initial economic analysis, which accompanied the 
proposed rule published in April 2015, also used a 10-year analysis 
period, from 2015 through 2024.
---------------------------------------------------------------------------

    We sought to quantify and monetize the costs of the following 
provisions:
    (a) Additional information in the description of well drilling 
design criteria;
    (b) Additional information in the drilling prognosis;
    (c) Prohibition of a liner as conductor casing;
    (d) Additional capping stack testing requirements;
    (e) Additional information in the APM for installed packers;
    (f) Additional information in the APM for pulled and reinstalled 
packers;
    (g) Rig movement reporting;
    (h) Fitness requirements for MODUs;
    (i) Foundation requirements for MODUs;
    (j) RTM of well operations for rigs under certain circumstances 
(e.g., rigs with a subsea BOP);
    (k) Additional documentation and verification requirements for BOP 
systems and system components;
    (l) Additional information in the APD, APM, or other submittal for 
BOP systems and system components;
    (m) Submission by the operator of an MIA Report completed by a 
BAVO; \24\
---------------------------------------------------------------------------

    \24\ A verification organization seeking BSEE's approval to 
become a BAVO is required to submit documentation describing the 
organization's applicable qualification and experience. (See Sec.  
250.732(a).)
---------------------------------------------------------------------------

    (n) New surface BOP system requirements;
    (o) New subsea BOP system requirements;
    (p) New accumulator system requirements;
    (q) Chart or digital recorders;
    (r) Notification and procedures requirements for testing of surface 
BOP systems;
    (s) Alternating BOP control station function testing;
    (t) ROV intervention function testing;
    (u) Autoshear, deadman, and EDS function testing on subsea BOPs;
    (v) Approval for well-control equipment not covered in Subpart G;
    (w) Breakdown and inspection of BOP systems and components;
    (x) Additional recordkeeping for RTM data;
    (y) Industry familiarization with the new rule; and
    (z) BAVO application costs.
    BSEE also quantified and monetized the potential benefits of the 
rule, including time savings, reductions in oil spills, and reductions 
in fatalities. We estimated the benefits derived from time savings 
associated with Sec.  250.737 of the rule, which streamlines BOP 
testing for workover. We also estimated time-savings benefits 
associated with a change in the required frequency of BOP pressure 
testing under Alternative 1 and Alternative 2, both of which would 
reduce the number of required BOP pressure tests per year (by reducing 
test frequency to once every 14 days and 21 days, respectively). In 
addition, we estimated the benefits derived from the reduction in oil 
spills and fatalities using the incident-reducing potential of the rule 
as a whole.
    BSEE received comments from the public on various aspects of the 
economic analysis of the proposed rule. Some commenters expressed 
concerns about costs that, to them, appeared to be underestimated or 
not included as impacts of the proposed rule. BSEE reviewed these 
comments and any new cost information provided by commenters. BSEE then 
either revised the analysis as appropriate to reflect this new 
information, or retained the original cost estimates and provided a 
justification for doing so. With regard to costs that some commenters 
thought were missing from the initial economic analysis, BSEE notes 
that many of these costs are actually for items that are included in 
the regulatory baseline, and thus are not impacts attributable to the 
rule. In addition, comments on costs were received in reference to some 
specific requirements in the proposed rule that have not been retained 
in the final rule. As a result, many of the comments regarding costs of 
the proposed rule (including but not limited to the potential costs 
associated with the proposed accumulator capacity requirements and the 
proposed mandatory 0.5 ppg safe drilling margin) are no longer 
applicable to the requirements of the final rule.
    Another issue regarding the initial economic analysis for the 
proposed rule related to requirements on various topics that overlapped 
with each other. In these cases, a particular cost could be attributed 
to multiple topics. As a result, some comments identified certain costs 
as missing in the initial RIA, when, in fact, the initial RIA did 
account for those costs under a related topic to which the commenter 
may not have attributed the cost. In other cases, however, BSEE found 
comments on costs to be quite relevant, and made use of the information 
in those comments to revise the final economic analysis.
    In response to comments expressing concern that the 10-year 
analysis period is too short, BSEE notes that the uncertainty 
associated with predicting industry activities, the advancement of 
technical capabilities, and oil price volatility makes it difficult to 
predict costs that would accrue to industry for a timeframe much longer 
than 10 years. BSEE also received comments suggesting that other 
aspects of the rule should be considered, such as the broader, indirect 
economic impacts that may occur as a result of the rule. BSEE 
considered and addressed these comments. More details on the public 
comments on the economic analysis, and BSEE's responses to the comments 
are in part VI.B.6 of this document.
    According to the analytical findings, the time-savings benefits of 
the final rule result in benefits greater than the costs of the rule. 
In other words, based on available data, the rule will be cost-
beneficial even when only the benefits resulting from time-savings are 
considered.
    The final rule will result in benefits to society by reducing the 
probability of incidents involving oil spills. The provisions with the 
highest costs to industry (such as RTM requirements for well operations 
and alternating BOP control station function testing) would have the 
largest impact on reducing spills. Benefits of the rule will result 
from the avoided costs associated with oil spills related to personal 
injuries, natural resource damages, lost hydrocarbons, spill 
containment and cleanup, lost recreational opportunities, and impacts 
to commercial fishing.
    To estimate the potential benefits of the rule associated with 
reducing the risk of oil spill incidents, we examined historical data 
from the BSEE oil spill database, which contains information for spills 
greater than 10 barrels of oil for the GOM and Pacific regions. Based 
upon an analysis of the BSEE oil spill database during the period 1988 
to 2010, BSEE identified LWCs associated with oil spills greater than 
10 barrels and used this data within the economic analysis.\25\ BSEE 
used 1988 as the starting year of the analysis because DOI undertook a 
comprehensive overhaul of its offshore regulatory program in that year, 
which thus provides the most relevant context for evaluating the 
current state of risk that now exist in OCS offshore operations. The 
LWCs that resulted in uncontrolled flow of gas, damage to a rig, and/or 
harm to personnel (but not oil spills over 10

[[Page 25987]]

barrels) are not reflected in this analysis.\26\
---------------------------------------------------------------------------

    \25\ Source: https://www.bsee.gov/Inspection-and-Enforcement/Accidents-and-Incidents/Spills/.
    \26\ Previous MMS data indicate that there were a total of 154 
LWCs during well operations on the OCS between 1988 and 2015. These 
LWCs resulted in 14 fatalities, 55 injuries, damage to facilities 
and equipment, and the release of hydrocarbons.
---------------------------------------------------------------------------

    We reviewed the causes of risk without the rule and how those 
causes of risk would be affected by the rule. In order not to overstate 
the potential risk reduction, we assumed a 1 percent risk reduction in 
the likelihood of all oil spills.\27\ We multiplied the expected annual 
number of spilled barrels of oil (based on the observed average of 
spilled oil per well) by 1 percent to estimate the expected annual 
reduction in barrels of oil spilled associated with the rule.
---------------------------------------------------------------------------

    \27\ Several recent studies have estimated the probabilities of 
blowout failures under a wide range of circumstances. See, e.g., 
``Blowout Preventer (BOP) Failure Event and Maintenance, Inspection 
and Test (MIT) Data Analysis for the Bureau of Safety and 
Environmental Enforcement (BSEE).'' American Bureau of Shipping and 
ABSG Consulting Inc., (under BSEE contract M11PC000027), June 2013; 
``Improved Regulatory Oversight Using Real-Time Data Monitoring 
Technologies in the Wake of Macondo,'' K. Carter, U, of Texas at 
Austin, 2014, published with E. van Oort and A Barendrecht, Society 
of Petroleum Engineers, 2014; ``Deepwater Horizon Blowout Preventer 
Failure Analysis Report to the U.S. Chemical Safety and Hazard 
Investigation Board,`` Engineering Services, LP, 2014. Given this 
accumulated knowledge of failure likelihoods under various 
circumstances, and analysis of how those likelihoods would be 
reduced by the rule, BSEE determined that 1 percent is a reasonable 
lower-bound of risk reduction that could occur as a result of the 
rule, although in BSEE's expert opinion, the actual risk reduction 
from the rule will likely be substantially higher than 1 percent.
---------------------------------------------------------------------------

    We then multiplied the annual reduction in spilled barrels of oil 
by the social and private costs of a spilled barrel of oil, which is 
estimated at $3,658 (in 2014 dollars) per barrel. This estimate was 
derived from the ``Economic Analysis Methodology for the Five Year OCS 
Oil and Gas Leasing Program for 2012-2017'' (hereafter referred to as 
the ``BOEM Case Study''),\28\ and includes costs associated with 
natural resource damages, the value of lost hydrocarbons, and spill 
cleanup and containment.\29\ We used a natural resource damage cost of 
$662 per barrel and a cleanup and containment cost of $2,946 per barrel 
as estimated for the GOM in the Bureau of Ocean Energy Management 
(BOEM) Case Study (both values adjusted to 2014 dollars). We assumed a 
value of lost output per barrel of $50.
---------------------------------------------------------------------------

    \28\ U.S. Department of the Interior, BOEM, 2012, Economic 
Analysis Methodology for the Five Year OCS Oil and Gas Leading 
Program for 2012-2017. BOEM OCS Study 2012-022.
    \29\ The BOEM Case Study presents per-barrel costs associated 
with a catastrophic event. We use this estimate because the BOEM 
Case Study represents a recent estimate for the costs associated 
with an oil spill which includes data from the Deepwater Horizon 
incident.
---------------------------------------------------------------------------

    In addition to the time-savings and risk reduction benefits, the 
final rule has other benefits. Due to difficulties in measuring and 
monetizing these benefits, BSEE does not offer a quantitative 
assessment of them. BSEE has used a conservative approach (one that 
seeks to avoid over-estimating the benefits) in the valuation of an oil 
spill, including only selected costs of such a spill. For example, 
although the analysis captures the environmental damage associated with 
a spill, the analysis is limited because it considers only the 
environmental amenities that researchers could identify and monetize. 
Therefore, the resulting benefits of avoiding a spill should be 
considered as a lower bound estimate of the true benefit to society 
that results from decreasing the risk of oil spills.
    Exhibit 1 displays the net benefits of the rule under the 
assumption that the reduction in the risk of incidents is 1 percent. 
Although BSEE believes the risk reduction of the rule to be at least 1 
percent, and likely higher, there is uncertainty around the level of 
risk reduction the rule would actually achieve.
[GRAPHIC] [TIFF OMITTED] TR29AP16.009

4. Sensitivity Analysis
    This section presents a sensitivity analysis of the potential 
benefits of the rule that could result from varying the following 
factors:
    a. The level of risk reduction of oil spills achieved by the rule, 
and
    b. The level of risk reduction of fatalities achieved by the rule
    Exhibit 2 presents the total 10-year benefits and net benefits 
under a range of possible annual risk reduction levels for oil spills 
from 0 to 20 percent. The final rule is expected to have positive net 
benefits across the full range of risk reduction levels.

[[Page 25988]]

[GRAPHIC] [TIFF OMITTED] TR29AP16.010

    In addition to the time-savings and the prevention of oil spills 
benefits, the rule is anticipated to reduce fatalities among rig 
workers. The oil and gas extraction industry constitutes a relatively 
small percentage of the national workforce, but has a fatality rate 
that is higher than the rate for most industries.
    The benefits of occupational risk reduction are usually measured 
using the value of a statistical life (VSL). BSEE used a VSL of $8.7 
million to estimate the avoided costs associated with a reduction in 
the fatality rate. This is the EPA-recommended estimate of $7.9 million 
updated to 2014 dollars.
    Exhibit 3 presents the resulting total 10-year fatality risk 
reduction benefit across a range of risk reduction values from 0 to 20 
percent. The exhibit also presents the undiscounted and discounted 10-
year total net benefits when fatality risk reduction is considered in 
addition to the benefits of the rule included in the analysis presented 
above (assuming a 1 percent risk reduction in the probability of 
incidents involving oil spills).\30\
---------------------------------------------------------------------------

    \30\ Between 1964 and 2010, there were 27 LWcs resulting in oil 
spills greater than 10 barrels. Two of these events resulted in 
fatalities, a 1984 blowout and the 2010 Deepwater Horizon incident 
that resulted 4 and 11 fatalities, respectively. Based on the 47-
year period from 1964 to 2010, the average number of fatalities was 
approximately 0.320 annually. Using a VSL of $8,423,301, the average 
value of fatalities is $2,691,423 per year. Therefore, each 1 
percent reduction in the risk of a fatality results in a risk 
reduction benefit of $26,914.

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

[[Page 25989]]

[GRAPHIC] [TIFF OMITTED] TR29AP16.011

    BSEE has concluded that, after considering all of the impacts of 
the final rule, the societal benefits justify the societal costs. In 
fact, as previously explained, BSEE estimates that, over the 10-year 
economic analysis period, the quantifiable benefits of the rule (i.e., 
$1,147 million with 7 percent discounting) will substantially exceed 
the quantifiable costs (i.e., $686 million with 7 percent discounting). 
(See Exhibit 1.)
5. Probabilistic Risk Assessment
    The benefits (and costs) of a regulation are based on the 
difference between the baseline (i.e., status quo) and the state of the 
world under the regulation. In relation to safety, environmental, and 
security benefits, one approach to estimating the benefits is based on 
the amount of risk reduction. In general, risk can be reduced in two 
distinct ways: By decreasing the probability of the event, and/or by 
decreasing the consequences of the event. The evaluation of the 
reduction in risk typically can be performed in either a deterministic 
or probabilistic approach.
    Historically, BSEE has evaluated the reduction of risk based on a

[[Page 25990]]

deterministic approach. A probabilistic approach, however, could 
enhance and extend more traditional approaches by: (1) Allowing 
consideration of a broader set of potential challenges; (2) providing a 
logical means for prioritizing these challenges based on risk 
significance; and (3) allowing consideration of a broader set of 
resources to address these challenges. Probabilistic risk assessments 
have been used in some cases by certain Federal agencies including the 
U.S. Nuclear Regulatory Commission, DHS, and the National Aeronautics 
and Space Administration.
    BSEE, however, does not currently collect data that provides a 
comprehensive basis for a probabilistic risk model. In addition, BSEE 
is not aware of any current industry-wide efforts to collect data for 
such a purpose, although BSEE has requested that the Ocean Energy 
Safety Institute develop a database related to equipment reliability 
that might provide useful information for the future development of a 
probabilistic risk assessment.

Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) (5 U.S.C. 601 et seq.) 
requires agencies to prepare a regulatory flexibility analysis to 
determine whether a regulation can be expected to have a significant 
economic impact on a substantial number of small entities. Further, the 
Small Business Regulatory Enforcement Fairness Act (SBREFA) at (5 
U.S.C. 801 et seq.) requires that an agency produce compliance guidance 
for small entities if the rule will have a significant economic impact. 
For the reasons explained in this section, BSEE believes that this rule 
will likely have a significant economic impact on a substantial number 
of small entities and, therefore, a regulatory flexibility analysis is 
required by the RFA. This Final Regulatory Flexibility Analysis 
assesses the impact of the rule on small entities, as defined by the 
applicable Small Business Administration (SBA) size standards.
1. Description of the Reasons for the Actions Being Taken by the Agency
    BSEE identified a need to amend the existing Blowout Preventer 
(BOP) and well-control regulations to enhance the safety and 
environmental protection of oil and gas operations on the OCS. In 
particular, BSEE considers this rule necessary to reduce the likelihood 
of any oil or gas blowout, which can lead to the loss of life, serious 
injuries, and harm to the environment. As was evidenced by the 
Deepwater Horizon incident (which began with a blowout at the Macondo 
well on April 20, 2010), blowouts can result in catastrophic 
consequences.\31\ The Federal government and industry conducted 
multiple investigations to determine the causes of the Deepwater 
Horizon incident; many of these investigations identified BOP 
performance as a concern. BSEE convened Federal decision-makers and 
stakeholders from the OCS oil and gas industry, academia, and other 
entities at a public forum on offshore energy safety on May 22, 2012, 
to discuss ways to address this concern. The investigations and the 
forum resulted in a set of recommendations to improve BOP performance. 
(see proposed rule, 80 FR 21508-21511 (April 17, 2015).)
---------------------------------------------------------------------------

    \31\ For example, any approximation of cost would incorporate 
catastrophic spills such as the Deepwater Horizon incident. The cost 
to BP of cleanup operations for the Deepwater Horizon incident has 
been estimated at more than $14 billion. In addition to cleanup 
costs, BP has agreed to pay over $14 billion to Federal, state, and 
local governments for natural resources damages, economic damage 
claims, or other expenses in a proposed consent decree and proposed 
settlement agreement that has been approved by the court. Source: 
Ramseur, J.L., Hagerty, C.L. 2014. ``Deepwater Horizon Oil Spill: 
Recent Activities and Ongoing Developments,'' Congressional Research 
Office. Available at: https://www.fas.org/sgp/crs/misc/R42942.pdf. 
See summary of settlement agreement regarding natural resources 
damages at www.doi.gov/deepwaterhorizon and at https://www.justice.gov/enrd/deepwater-horizon.
---------------------------------------------------------------------------

    As an agency charged with oversight of offshore operations 
conducted on the OCS, BSEE seeks to improve safety and mitigate risks 
associated with such operations. After careful consideration of the 
various investigations conducted after the Deepwater Horizon incident, 
and of industry's responses to the incident, BSEE has determined that 
the requirements contained in this rule are necessary to fulfill BSEE's 
statutory responsibility to regulate offshore oil and gas operations 
and to enhance the safety of offshore exploration, production, and 
development. (See 43 U.S.C. 1347-1348; 30 CFR 250.101.) BSEE has also 
determined that the BOP regulations need to be updated to incorporate 
certain recommendations as discussed in the preambles to the proposed 
and final rules (e.g., 80 FR 21508-21511), while others are being 
studied for consideration in future rulemakings. The rule creates a new 
subpart G in 30 CFR part 250 to consolidate the requirements for 
drilling, completion, workover, and decommissioning operations. 
Consolidating these requirements will improve efficiency and 
consistency of the regulations and allow for flexibility in future 
rulemakings. The rule also revises existing provisions throughout 
Subparts D, E, F, and Q to address concerns raised in the 
investigations, BSEE's internal reviews, the 2012 BSEE public forum, 
and other input from stakeholders and the public. The rule also 
incorporates guidance from several NTLs and revises provisions related 
to drilling, workover, completion, and decommissioning operations to 
enhance safety and environmental protection.
2. Description and Estimated Number of Small Entities Regulated
    Small entities, as defined by the RFA, consist of small businesses, 
small governmental jurisdictions, or other small organizations. This 
analysis focuses on impacts to small businesses (hereafter referred to 
as ``small entities'') because we have not identified any impacts to 
small governmental jurisdictions or to other small organizations. A 
small entity is one that is independently owned and operated and which 
is not dominant in its field of operation.\32\ The definition of small 
business varies from industry to industry in order to properly reflect 
industry size differences.
---------------------------------------------------------------------------

    \32\ See 5 U.S.C. 601.
---------------------------------------------------------------------------

    The rule will affect operators and holders of Federal oil and gas 
leases, as well as right-of-way holders, on the OCS. This includes 99 
businesses with active operations.\33\ Businesses that operate under 
this rule fall under the SBA's North American Industry Classification 
System (NAICS) codes 211111 (Crude Petroleum and Natural Gas 
Extraction) and 213111 (Drilling Oil and Gas Wells). For these NAICS 
classifications, a small business is defined as one with fewer than 501 
employees. Based on these criteria, 50 (50.51 percent) of the 
businesses operating on the OCS are considered small, and the rest are 
considered large businesses. BSEE considers that a rule has 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. Therefore, BSEE expects 
that the rule will affect a substantial number of small entities.
---------------------------------------------------------------------------

    \33\ We used ReferenceUSA, a directory of business information 
for more than 14 million businesses in all zip codes of the United 
States, to identify the list of offshore oil and gas operators and 
their numbers of employees.
---------------------------------------------------------------------------

    BSEE is using the estimated 99 businesses based on activity at the 
time this economic analysis was developed. The 99 businesses represent 
the best assessment of the total businesses operating in this arena at 
the time the economic analysis was developed. BSEE recognizes that this 
number is a dynamic number and can fluctuate;

[[Page 25991]]

however, BSEE determined that this number of businesses was appropriate 
for this rulemaking.
3. Description and Estimate of Compliance Requirements
    BSEE has estimated the incremental costs for small operators, lease 
holders, and right-of-way holders in the offshore oil and natural gas 
industry. Costs already incurred as a result of current industry 
practice in accordance with existing regulations, DWOPs, and API 
industry standards with which operators already comply were not 
considered as costs of this rule because they are part of the 
baseline.\34\ All costs are presented in 2014 dollars.
---------------------------------------------------------------------------

    \34\ Industry standards are developed by industry members and 
technical experts in open meetings based on a consensus process. 
They contain the baseline requirements that the industry has deemed 
necessary to operate in a safe and reliable manner and are often 
incorporated into commercial contracts between operators and 
contractors.
---------------------------------------------------------------------------

    As described in section 5 below, BSEE considered three regulatory 
alternatives:
    (1) Promulgate the requirements contained in the rule, including 
decreasing the BOP testing frequency for workover and decommissioning 
operations from the current requirement of once every 7 days to once 
every 14 days. The following chart identifies the BOP testing changes 
related to Alternative 1;

                          BOP Pressure Testing
------------------------------------------------------------------------
                                    Current testing       New testing
            Operation                  frequency           frequency
------------------------------------------------------------------------
Drilling/Completions............  Once every 14 days  Once every 14
                                                       days.
Workover/Decommissioning........  Once every 7 days.  Once every 14
                                                       days.
------------------------------------------------------------------------

    (2) Promulgate the requirements contained within the rule with a 
change to the required frequency of BOP pressure testing from the 
existing regulatory requirements (i.e., once every 7 or 14 days, 
depending upon the type of operation) to once every 21 days for all 
operations. The following chart identifies the BOP testing changes 
related to Alternative 2;

                                              BOP Pressure Testing
----------------------------------------------------------------------------------------------------------------
                                           Current testing       New testing frequency    Alternative 2 testing
              Operation                       frequency             (alternative 1)             frequency
----------------------------------------------------------------------------------------------------------------
Drilling/Completions.................  Once every 14 days.....  Once every 14 days.....  Once every 21 days.
Workover/Decommissioning.............  Once every 7 days......  Once every 14 days.....  Once every 21 days.
----------------------------------------------------------------------------------------------------------------

    (3) Take no regulatory action and continue to rely on existing BOP 
regulations in combination with permit conditions, DWOPs, operator 
prudence, and industry standards as applicable to BOP systems.
    By taking no regulatory action (Alternative 3), BSEE would leave 
unaddressed most of the concerns and recommendations that were raised 
regarding the safety of offshore oil and gas operations and the 
potential for another well control event with consequences similar to 
those of the Deepwater Horizon incident (see n. 9, supra).
    Alternative 2 (changing the required frequency of BOP pressure 
testing to once every 21 days for all operations) was not selected 
because BSEE lacks critical data on testing frequency and equipment 
reliability to justify such a change at this time.
    BSEE has elected to move forward with Alternative 1, the final 
rule, which incorporates recommendations provided by government, 
industry, academia, and other stakeholders prior to the proposed rule, 
as well as recommendations contained in public comments on the proposed 
rule. The final rule also incorporates elements of API Standard 53 and 
related standards. In addition to addressing concerns arising from the 
Deepwater Horizon incident and aligning with industry standards, the 
final rule advances several of the more critical well-control 
capabilities beyond current industry standards applicable to BOP 
systems based upon agency knowledge, experience and technical 
expertise. The final rule will also improve efficiency and consistency 
of the regulations and allow for flexibility in future rulemakings.
    We have estimated the costs of the following provisions of the 
final rule:
    (a) Additional information in the description of well drilling 
design criteria;
    (b) Additional information in the drilling prognosis;
    (c) Prohibition of a liner as conductor casing;
    (d) Additional capping stack testing requirements;
    (e) Additional information in the APM for installed packers;
    (f) Additional information in the APM for pulled and reinstalled 
packers;
    (g) Rig movement reporting;
    (h) Fitness requirements for MODUs;
    (i) Foundation requirements for MODUs;
    (j) Monitoring of well operations with a subsea BOP;
    (k) Additional documentation and verification requirements for BOP 
systems and system components;
    (l) Additional information in the APD, APM, or other submittal for 
BOP systems and system components;
    (m) Submission by the operator of an MIA Report completed by a 
BAVO; \35\
---------------------------------------------------------------------------

    \35\ The approved verification organization will have to submit 
documentation for approval by BSEE describing the organization's 
applicable qualification and experience. See discussion on Third-
party Verification in the final rule for further information.
---------------------------------------------------------------------------

    (n) New surface BOP system requirements;
    (o) New subsea BOP system requirements;
    (p) New accumulator system requirements;
    (q) Chart or digital recorders;
    (r) Notification and procedures requirements for testing of surface 
BOP systems;
    (s) Alternating BOP control station function testing;
    (t) ROV intervention function testing;
    (u) Autoshear, deadman, and EDS function testing on subsea BOPs;
    (v) Approval for well-control equipment not covered in subpart G;
    (w) Breakdown and inspection of BOP system and components;

[[Page 25992]]

    (x) Additional RTM-related recordkeeping; and
    (y) Industry familiarization with the new rule.
    (z) BAVO application costs
    These requirements and their associated costs to industry and 
government are discussed in the sections that follow. (Please note that 
the descriptions of the rule provisions presented in the RFA seek to 
mirror the language of the rule; however, only the final regulatory 
text is legally binding.)
(a) Additional Information in the Description of Well Drilling Design 
Criteria
    As discussed in detail in the preamble to the final rule, Sec.  
250.413(g) requires information on safe drilling margins to be included 
in the description of the well drilling design criteria. Safe drilling 
margins are an important parameter in avoiding a fracturing of the 
formation or a compromise of the casing shoe integrity. Either of these 
factors could lead to erratic pressures and uncontrolled flows (e.g., 
formation kicks) emanating from a well reservoir during drilling. This 
information is necessary for BSEE to better review the well drilling 
design and drilling program. The requirement to include information on 
the safe drilling margins in the well drilling design criteria results 
in an annual labor cost of about $300 per entity.\36\
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    \36\ We estimated that industry staff (a mid-level engineer) 
will spend one hour per well (at a compensation rate of $89.42 per 
hour) to include the additional information in the well drilling 
design criteria. Industry already complies with this new requirement 
as part of its design practice for most wells drilled. We assumed 
that this requirement will result in a new cost for all wells 
drilled per year (320). This resulted in an average annual labor 
cost to industry of $28,614, or an annual labor cost per entity of 
$289 (assuming 99 entities).
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(b) Additional Information in the Drilling Prognosis
    Section 250.414 requires industry to provide additional information 
in the drilling prognosis. New paragraph (j) requires the drilling 
prognosis to identify the type of wellhead system to be installed with 
a descriptive schematic, which should include pressure ratings, 
dimensions, valves, load shoulders, and locking mechanism, if 
applicable. This information will provide BSEE with data to reference 
during the approval process and will enable industry and BSEE to 
confirm that the wellhead system is adequate for the intended use.
    The requirement to include additional information in the drilling 
prognosis will result in increased annual labor costs to industry. BSEE 
considers the additional information required for the drilling 
prognosis (submitted as part of the APD) to be readily available. We 
calculated the annual labor cost for this activity by multiplying the 
time required to gather and document the information by the average 
hourly compensation rate of the staff most likely to complete this 
task. We then multiplied the product of this calculation by the 
estimated number of wells drilled per year, resulting in an estimated 
annual labor cost to industry for this documentation requirement of 
about $7,200.\37\ No additional costs to BSEE are expected as a result 
of this requirement. The requirement to include additional information 
in the drilling prognosis (submitted as part of the APD) results in an 
annual labor cost of about $70 per entity.\38\
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    \37\ We assumed that industry staff (a mid-level engineer) will 
spend 0.25 hours to include the additional information in the 
drilling prognosis for a well. We multiplied the number of industry 
staff hours per well by the average hourly compensation rate for a 
mid-level industry engineer ($89.42) and the average number of wells 
drilled per year (320) to obtain the average annual labor cost to 
industry of $7,153.
    \38\ We estimated that industry staff (a mid-level engineer) 
will spend 0.25 hours to include the additional information in the 
drilling prognosis for a well, resulting in an annual cost to 
industry of $7,153, or $72 per entity.
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(c) Prohibition of a Liner as Conductor Casing
    Former Sec.  250.421(f) is being revised to no longer allow a liner 
to be installed as conductor casing. This will ensure that the drive 
pipe is not exposed to wellbore pressures during drilling in subsequent 
hole sections.
    This provision will result in an annual equipment and labor cost to 
industry for wells that are currently allowed to use a liner as 
conductor casing. We multiplied the average cost of the casing joints 
and wellhead per well by the number of affected wells in order to 
calculate annual equipment installation costs. To calculate the 
associated annual labor costs, we multiplied the time required to 
install the equipment per well by the daily labor cost of rig crew time 
and by the number of wells on which the equipment must be installed. We 
then summed the equipment and labor costs to estimate the average 
annual equipment and labor cost to industry for this requirement of 
$795,000. No additional costs to BSEE are expected as a result of this 
requirement. This provision will result in an annual equipment and 
labor cost of about $8,000 per entity.\39\
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    \39\ Based on input provided in submittals to BSEE, we estimated 
that three wells per year (approximately one percent of drilled 
wells currently) have a liner as conductor casing. We estimated an 
average cost of the casing joints and wellhead per well at $65,000. 
This resulted in an average equipment cost of $195,000. We estimated 
that industry staff (rig crew) will spend one extra day to install 
the new equipment on a well, and the average labor cost for a rig 
crew per day is $200,000. This resulted in an estimated average 
annual labor cost to industry of $600,000. The annual equipment and 
labor costs total $795,000 for the industry, or $8,030 per entity.
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(d) Additional Capping Stack Testing Requirements
    Section 250.462 addresses source control and containment 
requirements. New paragraph (e)(1) details requirements for testing of 
capping stacks. New requirements include the function testing of all 
critical components on a quarterly basis and the pressure testing of 
pressure containing critical components on a bi-annual basis. Under the 
former regulations, there is no testing requirement for capping stacks. 
These new requirements help ensure that operators are able to contain a 
subsea blowout.
    These new testing requirements will result in new equipment and 
service costs to industry. We estimated the cost of testing for each 
capping stack, revised based on industry comments on the proposed rule 
and initial RIA, and multiplied this cost by the total number of 
anticipated tests to be performed. These calculations resulted in 
annual compliance costs to industry associated with these requirements 
of about $226,000, or $2,300 per entity.\40\ No additional costs to 
BSEE are expected as a result of these requirements.
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    \40\ BSEE estimated that the equipment and service costs of 
testing for capping stacks will be $14,138 per test, based on 
industry input. Additionally, we estimated that 4 capping stacks 
will be tested quarterly (or a total of 16 annual tests performed). 
This rendered a total annual equipment and service cost to industry 
of $226,200, or $2,285 per entity.
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(e) Additional Information in the APM for Installed Packers
    In Sec.  250.518, paragraphs (e) and (f) clarify requirements for 
installed packers and bridge plugs and require additional information 
in the APM, including descriptions and calculations for determining 
production packer setting depth. These new provisions codify existing 
BSEE policy to ensure consistent permitting. BSEE expects that 
operators already comply with the design specifications included in 
this section, because they are based on an established industry 
standard; i.e., API Spec. 11D1. Thus, the depth setting calculation is 
the only requirement that imposes a new cost beyond the baseline. The 
required calculations will be submitted for every well that is 
completed where tubing is installed.

[[Page 25993]]

    The requirement to include additional information in the APM will 
result in a labor cost to industry and BSEE. We based the industry 
labor cost associated with this new requirement on the time required to 
add the new descriptions and calculations to an APM and on the number 
of wells with installed packers for which an APM will be submitted per 
year. We based the new annual labor cost to BSEE on the time that BSEE 
will spend reviewing the new information in an APM and on the average 
hourly compensation rate of the BSEE staff most likely to complete this 
task. We estimated an average annual labor cost of about $5,800 to 
industry (or about $60 per entity) and an average annual labor cost of 
about $4,400 to BSEE.\41\
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    \41\ We estimated that industry staff (a mid-level engineer) 
will spend 0.25 hours to include the additional information in the 
APM for a well, at a compensation rate of $89.42 per hour. We 
estimated that APMs will be submitted for an average of 260 wells 
with installed packers per year. We estimated that BSEE staff (a 
mid-level engineer) will spend 0.25 hours to review the additional 
information in the APM for a well, at a compensation rate of $67.85.
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(f) Additional Information in the APM for Pulled and Reinstalled 
Packers
    In Sec.  250.619, new paragraphs (e) and (f) clarify requirements 
for pulled and reinstalled packers and bridge plugs and require 
additional descriptions and calculations in the APM regarding 
production packer setting depth. These new requirements codify existing 
BSEE policy to ensure consistent permitting. BSEE expects that 
operators already comply with the design specifications included in 
this section, which incorporate an established industry standard (i.e., 
API Spec 11D1). The depth setting description and calculation is the 
only requirement that will impose a new cost beyond the baseline. The 
required calculations will be submitted for every well that is worked 
over where tubing is pulled and then reinstalled. The requirement to 
include additional information in the APM will result in a labor cost 
of about $23,000 to industry (or about $200 per entity) and about 
$17,000 to BSEE.\42\
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    \42\ We estimated that industry staff (a mid-level engineer) 
will spend 0.25 hours (at $89.42 per hour) to include the additional 
information in the APM for a well, and that APMs will be submitted 
for an average of 1,010 wells with pulled and reinstalled packers 
per year. We estimated that BSEE staff (a mid-level engineer) will 
spend 0.25 hours (at $67.85 per hour) to review the additional 
information in the APM for a well.
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(g) Rig Movement Reporting
    Section 250.712 lists requirements for reporting movement of rig 
units to the BSEE District Manager. Revised paragraph (a) extends the 
rig movement reporting requirements to all rig units conducting 
operations covered under this subpart, including MODUs, platform rigs, 
snubbing units, and coiled tubing units. Paragraphs (c) and (e) are new 
and require notification if a MODU or platform rig is to be warm or 
cold stacked and when a drilling rig enters OCS waters. Paragraph (f) 
is revised to clarify that, if the anticipated date for initially 
moving on or off location changes by more than 24 hours, an updated 
Movement Notification Report will be required. Currently, movement 
reports are only required for drilling operations, but the rule 
requires operators to submit movement reports for other operations as 
well, including when rigs are stacked or enter OCS waters. These 
changes will allow BSEE to better anticipate upcoming operations, 
locate MODUs and platform rigs in case of emergency, and verify rig 
fitness. The requirement to notify BSEE of rig unit movement will 
result in annual labor costs to industry of about $4,000 (or about $40 
per entity) and to BSEE of about $3,100.\43\
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    \43\ This is based on the assumption of an average of 60 reports 
per year, of which 50 require about 0.5 hours to prepare by industry 
(by a mid-level engineer at a compensation rate of $89.42 per hour), 
and 10 others requiring about 2 hours to complete. It was estimated 
that BSEE requires as much time to process and review the reports, 
by a mid-level BSEE engineer, at a compensation rate of $67.85 per 
hour.
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(h) Fitness Requirements for MODUs
    Section 250.713(a) adds a requirement that operators provide 
fitness information for a MODU for well operations. Operators must 
provide information and data to demonstrate the drilling unit's 
capability to perform at the new drilling location. This information 
must include the maximum environmental and operational conditions that 
the unit is designed to withstand, including the minimum air gap (if 
relevant) that is necessary for both hurricane and non-hurricane 
seasons. If sufficient environmental information and data are not 
available at the time the APD or APM is submitted, the District Manager 
may approve the APD or APM but require operators to collect and report 
this information during operations. Under this circumstance, the 
District Manager may revoke the approval of the APD or APM if 
information collected during operations shows that the drilling unit is 
not capable of performing at the new location. These costs, in 
combination with the foundation requirements for MODUs, are discussed 
at the end of the next section.
(i) Foundation Requirements for MODUs
    Section 250.713(b) introduces foundation requirements for MODUs 
performing well operations. Operators must provide information to show 
that site-specific soil and oceanographic conditions are capable of 
supporting the rig unit.\44\ If operators provide sufficient site-
specific information in the Exploration Plan (EP), Development and 
Production Plan (DPP), or Development Operations Coordination Document 
(DOCD) submitted to BOEM, operators may reference that information. The 
regulations state that the District Manager may require operators to 
conduct additional surveys and soil borings before approving the APD, 
if additional information is needed to make a determination that the 
conditions are capable of supporting the rig unit or equipment 
installed on a subsea wellhead. For moored rigs, operators must submit 
a plan of the rig's anchor patterns approved in the EP, DPP, or DOCD in 
the APD or APM.
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    \44\ Soil sampling data is included in the exploration plan and 
DWOP submissions, and verified in the APD process, under existing 
regulations.
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    This requirement will result in labor costs to industry and BSEE. 
To calculate the industry labor cost, we multiplied the time required 
to record and report the information by the average hourly compensation 
rate of the industry staff most likely to complete this task and by the 
number of APMs per year. To calculate the BSEE labor cost, we 
multiplied the time that BSEE will spend to review the information by 
the average hourly compensation rate of the BSEE staff most likely to 
complete this task and by the number of APMs per year. The new 
requirements under Sec.  250.713 to notify BSEE of rig unit movement 
and foundation requirement for MODUs will result in labor costs to 
industry and BSEE, based on the labor required per report and the 
number of reports per year. We estimated these annual labor costs to be 
about $208,000 to industry (about $2,100 per entity) and about $158,000 
to BSEE.\45\
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    \45\ These estimates were based on the assumption that industry 
staff (a mid-level engineer) will spend 5 hours on average per 
report, at a compensation rate of $89.42 per hour, and an average of 
466 reports will be provided per year. We estimated that BSEE staff 
(a mid-level engineer) will spend 5 hours on average to review and 
process the information, at an average compensation rate of $67.85 
per hour.
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(j) RTM for Well Operations
    Section 250.724 is a new section that establishes requirements for:
    (1) RTM of well operations on rigs that have a subsea BOP, floating 
facilities using surface BOPs, and rigs

[[Page 25994]]

operating in high pressure and high temperature reservoirs,
    (2) Storing RTM data onshore, and
    (3) An RTM plan addressing RTM capabilities and procedures.
    In order to comply with this section, industry will incur annual 
equipment and labor costs associated with gathering, recording, 
transmitting, and storing data (as well as minimal one-time labor costs 
to develop RTM plan).\46\ To calculate the costs associated with these 
new requirements, we estimated the average equipment and labor cost per 
day to perform continuous monitoring (based on BSEE's interactions with 
the industry and review of the equipment involved), and the average 
amount of time that a rig will engage in well operations per year (and 
will thus be subject to this monitoring requirement). We assumed that 
this type of service mostly lends itself to a day rate, and multiplied 
the cost per day to perform the monitoring by the number of days per 
year that the rig will be engaged in well operations. We then 
multiplied the product by the number of rigs that will incur this new 
cost. This calculation resulted in average annual equipment and labor 
costs for this monitoring requirement of $40.5 million to industry (or 
about $409,000 per entity).\47\ Since BSEE will not normally receive or 
review RTM plans, no significant additional costs to BSEE are expected 
as a result of these requirements.
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    \46\ As explained later in part VIII, under Paperwork Reduction 
Act (PRA) of 1995, we assumed that it will take an estimated 5 
burden hours to develop each RTM plan. Based on the assumption that 
industry staff (a mid-level engineer) will develop these plans, at a 
compensation rate of $89.42 per hour, the one-time cost of this 
requirement would be about $447 per plan. Over the 10-year economic 
analysis period, the average annual cost would be about $44.7 per 
plan. (We believe that the total costs for small entities could be 
even smaller since, based on the comments submitted by industry, 
some operators already have RTM plans that may merely need some 
adjustment to satisfy the final rule requirements; nonetheless, we 
have assumed here that all affected small entities would need to 
develop such plans.) These estimated costs are so small that they 
are effectively subsumed by the overall costs of complying with the 
RTM requirements generally.
    \47\ We estimated that the average costs per day and the average 
operational days per year will be the same for rigs with subsea 
BOPs, surface BOPs on floating facilities, and rigs operating in 
HPHT reservoirs. We estimated that a rig operates for 270 days per 
year (three operations per year and three months per operation) and 
that the average cost per day to perform continuous monitoring will 
be $5,000, including equipment and labor. This estimate is based on 
the experience of the BSEE regulatory staff, working in conjunction 
with BSEE engineers who interact with industry on a regular basis 
and review the equipment. We also estimated that half of the rigs 
with subsea BOPs already conduct this monitoring. Thus, only half of 
rigs with subsea BOPs (20 rigs) will incur a new cost to comply with 
these requirements. Similarly, we estimated that a total of 10 rigs 
(i.e., 5 floating facilities with a surface BOP and 5 rigs in HPHT 
reservoirs) will incur a new cost to comply with these requirements. 
We multiplied the time that the rig is operational per year (270) by 
the average cost per day ($5,000) to perform monitoring and by the 
number of affected rigs (30) to obtain an average annual equipment 
and labor cost to industry of $40,500,000.
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(k) Additional Documentation and Verification Requirements for BOP 
Systems and System Components
    Section 250.730 lists general requirements for BOP systems and 
system components and adds new documentation and verification 
requirements.\48\ We estimated an annual labor cost to industry of 
about $1,800 associated with these submissions and labor costs to BSEE 
of about $700.\49\ We were unable to estimate the cost for a 
certification entity to meet the requirements of ISO 17011 for quality 
management systems for BOP stacks.
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    \48\ Section 250.730(d) requires that quality management systems 
for the manufacture of BOP stacks be certified by an entity that 
meets the requirements of International Organization for 
Standardization (ISO) 17011. Additionally, operators may submit a 
request for approval of equipment manufactured under quality 
assurance programs other than API Specification Q1, and BSEE may 
approve such a request provided the operator submits relevant 
information about the alternative program. Additionally, new 
paragraph (d) will result in labor costs to industry associated with 
submitting requests for alternative programs.
    \49\ We estimated that a mid-level industry engineer will spend 
2 hours to submit a request, at a compensation rate of $89.42 per 
hour, for each of ten wells during the year. We estimated that a 
mid-level BSEE engineer will spend 1 hour to process a request, at a 
compensation rate of $67.85 per hour.
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    Section 250.731(c) requires verification by a BAVO of specified 
aspects of equipment design, equipment tests, shear tests, and pressure 
integrity tests; all certification documentation must be made available 
to BSEE. The requirements laid out in Sec.  250.731(c) regarding 
certification for BOP systems and system components will result in new 
equipment and service costs to industry. We estimated a one-time cost 
to industry for equipment and service and multiplied the cost by the 
number of wells that will incur this new cost. This calculation 
resulted in one-time equipment and service costs for this certification 
requirement of $12.8 million to industry.\50\
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    \50\ We based this estimate on the assumption that the service 
costs per well will be $40,000, and 320 wells will incur a new cost 
to comply with these requirements.
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    Section 250.732(c) requires a comprehensive review by a BAVO of BOP 
and related equipment for use in high temperature and high pressure 
conditions. The requirements in new Sec.  250.732(c) surrounding a 
review of BOP systems and system components in HPHT conditions will 
result in new annual costs to industry. To calculate the costs 
associated with the required verifications of BOP systems and 
components by BSEE-approved verification organizations, we estimated 
the annual cost for performing the verification and multiplied the 
annual cost by the number of wells that will incur this new cost. This 
calculation resulted in annual equipment and labor costs for this 
verification requirement of $500,000 to industry.\51\
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    \51\ We estimated that the annual costs per well will be 
$50,000. We estimated that 10 HPHT wells will incur a new cost to 
comply with these requirements. We multiplied the annual cost of 
equipment and service by the number of affected wells to obtain an 
average annual equipment and service cost to industry of $500,000.
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    In total, all of the annual equipment and labor costs associated 
with these new documentation and certification requirements are 
estimated to be $18,005 per entity.
(l) Additional Information in the APD, APM, or Other Submittals for BOP 
Systems and System Components
    Section 250.731 lists the descriptions of BOP systems and system 
components that must be included in the applicable APD, APM, or other 
submittal for a well. Revised paragraph (a) requires the submittal to 
include descriptions of the rated capacities for the fluid-gas 
separator system, control fluid volumes, control system pressure to 
achieve a seal of each ram BOP, number of accumulator bottles and 
bottle banks, and control fluid volume calculations for the accumulator 
system.
    New paragraph (e) requires a listing of the functions with 
sequences and timing of autoshear, deadman, and EDS for subsea BOPs. 
Paragraph (b) adds schematic drawing requirements, including labeling 
for the control system alarms and set points, control stations, and 
riser cross section. For subsea BOPs, surface BOPs on floating 
facilities, and BOPs operating under HPHT conditions, new paragraph (f) 
requires submission of a certification that an MIA Report has been 
submitted within the past 12 months. New paragraphs (c) and (d) include 
a change in required certifications; the paragraphs require submission 
of certification from a BAVO (rather than a ``qualified third-party'') 
\52\ that:
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    \52\ BSEE expects that BAVOs will come from qualified third 
parties used by operators under BSEE's former regulations and 
industry standards. In addition, the certifications required under 
new Sec.  250.731(c) and (d) are similar to the verifications 
required by former Sec.  250.416(e) and (f). Thus, there should not 
be any incremental costs from these new certification requirements.

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[[Page 25995]]

    (1) Test data demonstrate that the shear ram(s) will shear the 
drill pipe at the water depth, and
    (2) The BOP has been designed, tested, and maintained to perform 
under the maximum environmental and operational conditions anticipated 
to occur at the well, and
    (3) That the accumulator systems have sufficient fluid to function 
the BOP system without assistance from the charging system.
    The requirements to provide additional documentation about the BOP 
system and system components in the APD, APM, or other submittal will 
result in labor costs to industry and BSEE. To calculate the industry 
labor cost associated with these new requirements, we multiplied the 
estimated time it will take to document the required information in an 
APD, APM, or other submittal by the average hourly compensation rate of 
the industry staff most likely to complete this task. We then 
multiplied the product by the estimated number of wells drilled per 
year.
    Likewise, to calculate the new annual labor cost to BSEE, we 
multiplied the time that BSEE will spend to process each submittal by 
the average hourly compensation rate of the BSEE staff most likely to 
complete this task and by the estimated number of wells drilled per 
year. These calculations resulted in average annual labor costs for 
this documentation requirement of about $29,000 (about $300 per entity) 
to industry and about $22,000 to BSEE.
(m) Submission of an MIA Report by a BAVO
    Sections 250.732(d) and (e) include new requirements on the 
submission of an MIA Report on the BOP stack and systems. New paragraph 
(d) outlines the requirements for this report, which must be completed 
by a BAVO and submitted by the operator for operations that require the 
use of a subsea BOP, a surface BOP on a floating facility, or a BOP 
that is being used in HPHT operations. We calculate this annual cost by 
multiplying the time required to complete the task by the number of 
submittals per year and by the hourly compensation rate of the industry 
staff most likely to complete the task. These calculations result in an 
annual labor cost to industry of about $80,000.
    Section 250.731(f) requires a certification stating that this 
report was submitted to BSEE prior to beginning any operations (to 
include maintenance and repairs) involving these BOPs. The BAVO report 
will enhance BSEE's review and permitting process and ensure that BSEE 
is aware of repairs or other changes to the operating BOPs.
    These reporting requirements will result in new capital costs to 
industry and new labor costs to industry associated with the submission 
and review of reports. To calculate the capital costs to industry of 
submitting MIA reports, we multiplied the annual capital cost of 
submitting the report by the estimated number of wells that will be 
affected. This calculation resulted in annual capital costs for 
reporting of $4.8 million to industry. To calculate the industry labor 
cost, we multiplied the time required to submit a report by the average 
hourly compensation rate of the industry staff most likely to complete 
this task and then multiplied this cost by the number of additional 
reports expected per year. These calculations result in average annual 
labor costs of about $45,000 to industry and about $11,000 to BSEE. 
Overall, all of the requirements under this section result in an annual 
cost per entity of about $50,000.\53\
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    \53\ We estimated an annual capital cost of $15,000 for each of 
320 wells, which resulted in an annual capital cost of $4.8 million. 
For labor costs, we estimated that industry staff (a mid-level 
engineer) will spend a half hour to prepare a report for each of 320 
wells, at a compensation rate of $89.42. We also estimated that the 
same staff would spend 5 hours for each of 50 reports per year, and 
10 hours for each of 90 reports per year.
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(n) New Surface BOP Requirements
    Section 250.735 includes new requirements for surface BOP stacks. 
Specifically, new Sec.  250.735(g)(2)(i) requires that remotely-
operated locking devices be installed on blind shear rams on surface 
BOPs. BSEE recognizes that the equipment and labor costs associated 
with this new requirement will be case-specific (since every BOP stack 
is unique). In any case, BSEE estimates that this new requirement will 
create a new one-time equipment cost to industry for the installation 
of remotely-operated locks. Operators may choose, although they are not 
required, to use hydraulically operated locks to comply with this 
requirement. Because we cannot predict how many operators will use 
hydraulic locks, rather than alternative (and typically less costly) 
locking devices, we have continued to estimate the cost of this 
provision based on the cost for installing hydraulic locks, even though 
that may result in an overestimation of actual costs. We estimate this 
cost by multiplying the cost per equipment part by the number of rigs 
with surface BOPs. This results in a one-time cost to industry of $2.50 
million, or about $2,500 per entity per year (over a 10-year 
period).\54\
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    \54\ Based on industry comments, BSEE has revised the cost 
estimate for this provision. The cost of installing a hydraulically 
operated lock is estimated at $50,000. Although the revised final 
rule only imposes such new costs on surface BOPs with blind shear 
rams, we chose to multiply this cost by the estimated total number 
(50) of rigs with surface BOPs with any kind of sealing ram to 
obtain the one-time cost estimate to industry of $2.5 million.
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(o) New Subsea BOP System Requirements
    Section 250.734 includes new requirements for subsea BOP systems, 
based on recommendations from the Deepwater Horizon incident 
investigations. Revised paragraph (a) requires that BOPs be equipped 
with dual shear rams and outlines the requirements for the shear rams.
    BSEE recognizes that the equipment costs associated with these new 
subsea BOP system requirements will be case-specific. For example, the 
costs will depend on the age of the rig and BOP system, the BOP system 
type, and the size of the rig, among other factors. In order to 
estimate the cost to industry associated with these new shear ram 
requirements, we multiplied the estimated cost of compliance per rig by 
the estimated number of affected rigs. Since API Standard 53 covers the 
requirements under paragraph (a) for all rigs with the exception of 
moored rigs, the costs of these requirements, except the costs 
associated with moored rigs, are included in the baseline. We 
multiplied the cost of compliance for a moored rig by the number of 
moored rigs in order to calculate the one-time equipment costs of $50 
million for this requirement.\55\ This results in an average annual 
cost of $5 million per year over ten years, or an annual cost of about 
$51,000 per entity.
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    \55\ Although the actual costs for obtaining and installing any 
new equipment required by this section will vary, as stated above, 
based on existing technology for centering/shearing and BSEE's 
discussion with a relevant equipment manufacturer, BSEE believes 
that the height of the subsea BOP stacks will not need to change 
significantly. We also estimated that 5 moored rigs will be affected 
and that the one-time capital compliance costs, including 
installation costs, associated with these shear ram requirements 
will be $10,000,000 per rig. To calculate the total one-time capital 
costs to industry, we multiplied the equipment cost per rig by the 
number of affected rigs to yield a total cost to industry of 
$50,000,000.
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(p) New Accumulator System Requirements
    Section 250.735(a) lists new requirements for the accumulator 
system of a BOP. The accumulator system must operate all BOP functions 
against MASP with at least 200 pounds per square inch remaining on the 
bottles

[[Page 25996]]

above the pre-charge pressure without use of the charging system. 
Revised paragraph (a) details additional accumulator requirements 
regarding fluid capacity and accumulator regulators. This revision will 
ensure that the BOP system is capable of operating all critical 
functions.
    The requirement that the accumulator system operate all functions 
for all BOP systems will result in a total one-time cost to industry of 
about $2.4 million, or about $2,500 per entity per year over 10 
years.\56\ Since this work can be planned for and done during routine 
maintenance or downtime scheduled for other reasons, no incremental rig 
downtime or daily rig costs are expected.
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    \56\ BSEE estimated that the cost of the additional equipment 
needed to meet the requirements will be $25,000 per rig. It is 
unknown how many rigs already comply; thus, we made a conservative 
assumption that all rigs will be affected (90 rigs). We obtained an 
estimated one-time equipment cost of $2.25 million. For the one-time 
labor cost to industry, we estimated that three days of industry 
time will be required per rig to install the new equipment. We 
estimated that industry staff (a mid-level engineer) will spend 24 
hours to install the new equipment on a rig, at a compensation rate 
of $89.42 per hour. This rendered an estimated one-time labor cost 
to industry of $193,143. Summing the equipment and labor costs 
resulted in a total one-time cost to industry of $2,443,143. We 
divided the one-time equipment and labor cost by the number of 
entities (99) to obtain a one-time equipment and labor cost per 
entity of $24,6787.
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(q) Chart Recorders
    Section 250.737(c), which addresses BOP testing requirements, will 
introduce a requirement that each test must hold the required pressure 
for five minutes while using a four-hour chart. This chart will contain 
sufficient detail to show if a leak occurred during the test.
    This testing requirement will result in a one-time equipment and 
labor cost to industry for those operators that do not already have the 
required equipment. Some operators will have to purchase the equipment 
(a chart recorder or digital recorder) to be able to comply with the 
testing requirement. To calculate the equipment cost, we multiplied the 
estimated cost of equipment per rig by the estimated total number of 
rigs that may need it. To calculate the one-time labor cost to 
industry, we multiplied the time required per rig to install the chart 
recorder by the average hourly compensation rate of the industry staff 
most likely to complete this task and by the total number of rigs. This 
calculation resulted in a one-time cost to industry of about $90,000, 
or about $90 per entity per year over 10 years.\57\
---------------------------------------------------------------------------

    \57\ We estimated that a chart recorder would have an average 
cost of $2,000 per rig, for each of 45 rigs (half of the 90 rigs in 
total, with the other half estimated to already have the equipment). 
This yielded an estimated one-time equipment cost to industry of 
$90,000. We estimated that industry staff (rig crew) will spend five 
minutes (0.08 hours) per rig to install the equipment at an average 
hourly compensation rate of $57.20. This resulted in a total one-
time cost to industry of $90,215.
---------------------------------------------------------------------------

(r) Notification and Procedure Requirements for Testing of Surface BOP 
Systems
    Section 250.737(d)(2) expands notification and procedural 
requirements regarding the use of water to test a surface BOP system on 
the initial test. These expanded notification and procedural 
requirements will result in increased annual costs to industry of about 
$5,400 (about $50 per entity) and to BSEE of about $4,100.\58\
---------------------------------------------------------------------------

    \58\ This $54 labor cost per entity reflects our assumptions 
that a mid-level industry engineer will spend 1 additional hour on a 
submittal as a result of these expanded requirements and that 
industry will submit 60 notifications per year.
---------------------------------------------------------------------------

(s) Alternating BOP Control Station Function Testing
    Section 250.737(d)(5) expands the requirements for function testing 
BOP control stations. It requires that the operator designate the BOP 
control stations as primary and secondary and alternate function 
testing of each station weekly. This testing requirement will result in 
increased operating costs to industry. To calculate the annual 
operations costs associated with this requirement, we multiplied the 
time required to conduct the testing per rig by the daily rig operating 
cost and by the estimated number of rigs affected per year. Because 
subsea and surface BOPs have different daily rig operating costs, we 
performed separate calculations for the costs for subsea and surface 
BOP rigs. We estimated an increased annual operating cost to industry 
associated with this provision of $25 million, or an annual operations 
cost of about $250,000 per entity.\59\
---------------------------------------------------------------------------

    \59\ We estimated that testing would require 0.5 days per rig 
per year. Because subsea and surface BOP rigs have different daily 
rig operating costs, we performed separate calculations for the 
costs for subsea and surface BOP rigs. For subsea BOP rigs, we 
multiplied the time required to conduct the testing per rig by the 
daily rig operating cost for subsea BOP rigs ($1 million) and by the 
number of subsea BOP rigs (40) for an annual cost of $20 million for 
subsea BOP rigs. For surface BOP rigs, we estimated a daily rig 
operating cost of $200,000 and the number of surface BOP rigs to be 
50, for an annual cost of $5 million for surface BOP rigs. Summing 
the annual costs for subsea BOP rigs and surface BOP rigs resulted 
in a total annual increased operating cost to industry associated 
with this provision of $25 million.
---------------------------------------------------------------------------

(t) ROV Intervention Function Testing
    Section 250.737(d)(4) establishes requirements for testing ROV 
intervention functions to include testing and verifying the closure of 
the selected ram(s) on a subsea BOP. This testing requirement will 
result in an annual operations cost to industry of about $417,000, or 
about $4,200 per entity.\60\
---------------------------------------------------------------------------

    \60\ We estimated that it will take five minutes per well to 
conduct the testing and that 120 wells will be affected (40 subsea 
BOP rigs with three wells per rig). We considered the time diverted 
for testing as a fraction of a day (0.003472), and the daily 
operating cost per rig ($1,000,000) to obtain an average annual 
operations cost to industry of $416,667, or $4,209 per entity.
---------------------------------------------------------------------------

(u) Autoshear, Deadman, and EDS System Function Testing on Subsea BOPs
    Section 250.737(d)(12) expands the requirements for function 
testing of autoshear, deadman, and EDSs on subsea BOPs. It requires the 
test procedures submitted for the BSEE District Manager's approval to 
include schematics of the actual controls and circuitry of the system, 
the approved schematics of the BOP control system, and a description of 
how the ROV is used during the operation. It also outlines the 
requirements for the deadman system test, including a requirement that 
the testing must indicate the discharge pressure of the subsea 
accumulator system throughout the test. It requires that the blind 
shear rams be tested to verify closure. The operator must document the 
plan to verify closure of the casing shear ram(s), if installed, as 
well as all test results.
    These documentation and testing requirements will result in a one-
time equipment cost and increased annual operating costs to industry. 
The industry will incur a one-time equipment cost to purchase a sensing 
device to detect the discharge pressure during deadman system testing. 
We multiplied the average cost per rig of the sensing device by the 
estimated number of subsea BOP rigs required to comply. We assumed 
installation costs to be negligible because the sensing device will be 
installed as part of routine servicing. In order to calculate the 
annual operations cost, we multiplied the estimated time per subsea BOP 
rig required to comply with the documentation and testing requirements 
by the daily operating cost for a subsea BOP rig and by the estimated 
number of subsea BOP rigs affected per year. These calculations 
resulted in a one-time equipment cost to industry of $100,000 and an 
average annual increased operating cost to industry of $5 million, or 
an annual cost of about $51,000 per entity.\61\
---------------------------------------------------------------------------

    \61\ BSEE estimated that the cost of the sensing device will be 
$2,500 per rig. We multiplied the equipment cost by the total number 
of subsea BOP rigs (40) to obtain the one-time equipment cost to 
industry of $100,000. We estimated that it will take one hour per 
well to perform the testing and documentation tasks required by this 
provision, and that each subsea BOP rig will be affected (40 subsea 
rigs). We multiplied the time diverted for testing in a day 0.125 by 
the daily operating cost per rig ($1,000,000) and by the estimated 
number of rigs affected per year to obtain an average annual 
operations cost to industry of $5 million.

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[[Page 25997]]

(v) Approval for Well-Control Equipment not Covered in Subpart G
    Section 250.738 describes the required actions for specified 
situations involving BOP equipment or systems. Paragraphs (b), (i), and 
(o) include requirements for reports from BAVOs. Reports previously 
required to be prepared by a ``qualified third-party'' under these 
sections will be required to be prepared by a BAVO. Paragraph (m) 
includes a similar change and introduces a requirement that an operator 
request approval from the BSEE District Manager if the operator plans 
to use well-control equipment not covered in Subpart G. The operator 
must submit a report from a BAVO, as well as any other information 
required by the District Manager. This new approval request requirement 
will result in annual labor costs to industry and BSEE of about $13,000 
and about $10,000, respectively, and annual costs per entity of about 
$100.\62\
---------------------------------------------------------------------------

    \62\ These estimates are based on the assumption that industry 
staff (a mid-level engineer) will spend an average of 0.81 hours per 
report, at a compensation rate of $89.42 per hour, for approximately 
183 reports for year. It was estimated that that BSEE staff (a mid-
level engineer) will spend the same amount of time to review and 
process the report, at a compensation rate of $67.85 per hour.
---------------------------------------------------------------------------

(w) Breakdown and Inspection of the BOP System and Components
    Section 250.739(b) introduces a requirement for a complete 
breakdown and inspection of the BOP and every associated component 
every 5 years, which may be performed in phased intervals. During this 
complete breakdown and inspection, a BAVO must document the inspection 
and any problems encountered. This BAVO report must be available to 
BSEE upon request. This additional requirement is necessary to ensure 
that the components on the BOP stack will be regularly inspected. In 
the past, BSEE has, in some cases, seen components of BOP stacks go 
more than 10 years without this type of inspection.
    This inspection and documentation requirement will result in cost 
to industry associated with generating reports by BAVOs. To calculate 
this report cost, we multiplied the estimated report cost per rig by 
the number of reports completed per rig annually and by the estimated 
number of rigs in operation per year. Because subsea and surface BOPs 
differ in structure, they incur different costs to break down and 
inspect. In order to reflect these differences, we performed separate 
calculations of the costs for subsea and surface BOP rigs. Assuming 
staggered inspections, we estimated that, in each year, an average of 
eight subsea BOP rigs would undergo inspections, thereby enabling all 
40 subsea BOP rigs to undergo such inspections over a five-year period. 
Similarly, we estimated that 10, of a total of 50, surface BOP rigs 
would undergo inspections each year. This resulted in annual costs to 
industry of $4.3 million, or about $43,000 per entity.\63\
---------------------------------------------------------------------------

    \63\ For subsea BOP rigs we estimated that equipment and labor 
cost will be $350,000 per rig, for each of 8 subsea BOP rigs each 
year, resulting in an annual cost of $2.8 million. For surface BOP 
rigs we estimated that equipment and labor cost will be $150,000 per 
rig, for each of 10 rigs per year, resulting in an annual cost of 
$1.5 million.
---------------------------------------------------------------------------

    The proposed rule contained a requirement that operators breakdown 
the entire BOP system every five years for recertification, without the 
option to phase or stagger recertification. BSEE received comments that 
this requirement would cause rigs to be out of service for extended 
periods of time, at substantial opportunity costs to industry. BSEE 
revised the requirement in the final rule to allow for staggered 
inspections over the course of five years. This change eliminates the 
need for rigs to be brought out of service for extended periods of 
time.
(x) Additional Recordkeeping for RTM
    Sections 250.740(a) and 250.741(b) introduce requirements for 
additional recordkeeping of RTM data for well operations. These 
additional requirements will create an annual labor cost of about 
$1,500 to industry, or about $15 per entity.\64\
---------------------------------------------------------------------------

    \64\ This $15 labor cost per entity reflects our assumption that 
an administrative staff will spend 0.5 hours to submit a report for 
each of 120 wells (three wells per subsea BOP rig).
---------------------------------------------------------------------------

(y) Industry Familiarization With New Regulations
    When the new regulation takes effect, operators will need to read 
and interpret the rule. Through this review, operators will familiarize 
themselves with the structure of the new rule and identify any new 
provisions relevant to their operations. Operators will evaluate 
whether any new action must be taken to achieve compliance with the 
rule. Reviewing the new regulations will require staff time, 
representing a one-time labor cost of about $20,000 or annual cost of 
$20 per entity.\65\
---------------------------------------------------------------------------

    \65\ We assumed that industry staff (a professional engineer, 
supervisory) will spend two hours to review the new regulation, at 
an hourly wage rate of $53.00, based on BSEE's Supporting Statement 
A (BSEE Production Safety Systems). We multiplied this wage rate by 
the private sector loaded wage factor of 1.43 to account for 
employee benefits, resulting in a loaded average hourly compensation 
rate of $75.79. We assumed that an industry staff will review the 
new regulation at each of the 130 field offices. We multiplied the 
number of hours per review by the average hourly compensation rate 
and by the number of field offices, resulting in an estimated one-
time labor cost to industry of $19,705. We divided annual labor cost 
of $1,971 by the number of entities (99) to obtain an average annual 
one-time labor cost of $20.
---------------------------------------------------------------------------

(z) BAVO Application Costs
    Qualified third-parties currently perform verifications under 
BSEE's existing regulations and current industry practice that are 
similar to the certifications and verifications that a BAVO will be 
required to perform under Sec.  250.732(a) of the final rule. BSEE 
expects that many of these existing third-party organizations will 
become BAVOs. To become a BAVO, organizations will need to apply to 
BSEE and have their applications approved by BSEE. Those that are 
approved as BAVOs will then be placed on a list for operators to use in 
finding a BAVO that will enable the operators to obtain the required 
certifications and verifications.
    We estimated the number of BAVO applications to be 15 in the first 
year (2016), three in the second year (2017), and two per year for each 
of the remaining eight years (2018 to 2025). We further estimated that 
organizations would require, on average, about 100 hours of a mid-level 
engineer's time to complete and submit each application. We also 
estimated that BSEE would require, on average, about 40 hours of a mid-
level engineer's time to review and process each application, except 
during the first year in which BSEE would require 80 hours per 
application (since BSEE will need additional time in the first year to 
develop and begin implementing the approval process). These estimates 
result in average annual costs to industry of about $30,000 per year 
(about $300 per entity) and to BSEE of about $13,000 per year, for a 
total average annual cost of $44,000.\66\
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    \66\ The total is slightly different due to roundiing, using a 
compensation rate of $89.42 per hour for industry results in an 
average annual cost to industry of $30,403; and using a compensation 
rate of $67.85 for BSEE results in an average annual cost to BSEE of 
$13,299.
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Total Cost Burden for Small Entities
    To estimate the cost burden for small entities, BSEE scaled the 
per-entity costs

[[Page 25998]]

to match the labor and equipment costs that would be faced by a small 
entity with few wells as opposed to large entities with several wells. 
Of the 99 entities operating on the OCS, 50 (or 50.51 percent) of them 
are small entities. In terms of revenue of offshore oil and gas sales, 
these small entities account for 18.50 percent of the total revenue of 
all 99 entities. This implies that the average small firm tends to have 
operations that are about 36.6 percent as large as the operations of an 
average operator, e.g., having that many fewer wells, rigs, and 
employees, on average. Therefore, it was estimated that the costs per 
entity for a small entity would be 36.6 percent the cost per entity for 
all entities. As a result, the total estimated annual cost of the rule 
per small entity is about $328,000, in comparison to the average annual 
cost per entity (for all entities) of about $897,000. BSEE's 
calculations thus indicate that the total cost burden of this rule will 
be $3.3 million per affected small entity over 10 years, as presented 
in Exhibit 1.
    Exhibit 2 displays estimates of costs to small entities as a 
percentage of revenues.\67\ In all but the first year of the 10 years 
in the analysis period, the rule represents a cost of approximately 
$304,000 per affected small entity. In the first year, costs will be 
higher at about $556,000 per affected small entity as a result of 
certain one-time equipment costs, especially the costs of new subsea 
BOP system requirements.
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    \67\ We used ReferenceUSA, a directory of business information 
for more than 14 million, businesses in all zip codes of the United 
States, for data on estimated annual revenue and number of 
employees. WE retrieved the ReferenceUSA data in February 2015. 
Based on these data, the average annual revenue of the small 
operators is $105,963,674.
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    The costs of the rule as a proportion of small entity revenue range 
from 0.29 percent in most years to 0.52 percent in the first year. BSEE 
considers a rule to have a ``significant economic impact'' when the 
total annual cost associated with the rule for a small entity is equal 
to or exceeds 1 percent of annual revenue. Thus, the rule is not 
expected to have a significant economic impact on the participating 
small operators, lease holders, and pipeline right-of-way holders. 
Therefore, BSEE has concluded that this rule will not have a 
significant economic impact on a substantial number of small entities.

[[Page 25999]]

[GRAPHIC] [TIFF OMITTED] TR29AP16.012


[[Page 26000]]


[GRAPHIC] [TIFF OMITTED] TR29AP16.013

4. Identification of All Relevant Federal Rules That May Duplicate, 
Overlap, or Conflict With the Rule
    The rule does not conflict with any relevant Federal rules or 
duplicate or overlap with any Federal rules in any way that will 
unnecessarily add cumulative regulatory burdens on small entities 
without any gain in regulatory benefits.
5. Description of Significant Alternatives to the Rule
    BSEE considered three regulatory alternatives:
    (1) Promulgate the requirements contained within the rule, 
including decreasing the BOP testing frequency for workover and 
decommissioning operations from current 7 day to 14 day testing 
frequency. The following chart identifies the BOP testing changes 
related to Alternative 1:

                          BOP Pressure Testing
------------------------------------------------------------------------
                                              Current
                                              testing         Testing
                Operation                    frequency       frequency
                                              (days)          (days)
------------------------------------------------------------------------
Drilling/Completions....................              14              14
Workover/Decommissioning................               7              14
------------------------------------------------------------------------

    (2) Promulgate the requirements contained within the rule with a 
change to the required frequency of BOP pressure testing from the 
existing regulatory requirements (i.e., 7 or 14 days depending upon the 
type of operation) to 21 days for all operations. The following chart 
identifies the BOP testing changes related to Alternative 2:

                                              BOP Pressure Testing
----------------------------------------------------------------------------------------------------------------
                                                                          Testing  frequency     Alternative 2
                      Operation                        Current  testing     (alternative 1)    testing frequency
                                                       frequency (days)         (days)              (days)
----------------------------------------------------------------------------------------------------------------
Drilling/Completions................................                  14                  14                  21
Workover/Decommissioning............................                   7                  14                  21
----------------------------------------------------------------------------------------------------------------


[[Page 26001]]

    (3) Take no regulatory action and continue to rely on existing BOP 
regulations in combination with permit conditions, DWOPs, operator 
prudence, and industry standards.
    BSEE has elected to move forward with Alternative 1--the final 
rule--which incorporates recommendations provided by government, 
industry, academia, and other stakeholders prior to the proposed rule 
or contained in public comments on the proposed rule. In addition to 
addressing concerns and aligning with industry standards, BSEE is 
advancing several of the more critical capabilities beyond current 
industry standards applicable to BOP systems based on agency knowledge, 
experience and technical expertise. The rule will also improve 
efficiency and consistency of the regulations and allow for flexibility 
in future rulemakings.

Small Business Regulatory Enforcement Fairness Act

    The rule is a major rule under the Small Business Regulatory 
Enforcement Fairness Act, 5 U.S.C. 801 et seq. Under that statute, a 
major rule is one that:
    (1) Will have an annual effect on the economy of $100 million or 
more; or
    (2) Will cause a major increase in costs or prices for consumers, 
individual industries, Federal, State, or local government agencies, or 
geographic regions; or
    (3) Will have significant adverse effects on competition, 
employment, investment, productivity, innovation, or the ability of 
U.S.-based enterprises to compete with foreign-based enterprises.
    BSEE has determined that 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 costs affecting small 
businesses, see the Regulatory Flexibility Act section above.

Unfunded Mandates Reform Act of 1995 (UMRA)

    In accordance with UMRA, BSEE has determined that this rule will 
not impose an unfunded mandate on State, local, or tribal governments 
of more than $100 million in a single year and will not have a 
significant or unique effect on State, local, or tribal governments. 
BSEE has determined that this rule will impose costs on the private 
sector of more than $100 million in a single year. Although these costs 
do not appear to trigger the requirement to prepare a written statement 
under UMRA, DOI has chosen to prepare such a written statement 
satisfying the requirements of UMRA. Those requirements are addressed 
and the required statements are found in the final RIA and final RFA 
analysis or in the preamble of this final rule.
    Specifically, the final RIA, the final RFA analysis, or this 
document:
    1. Identify the provisions of Federal law (OCSLA) under which this 
rule is being promulgated;
    2. Include a quantitative assessment of the anticipated costs to 
the private sector (i.e., expenditures on labor and equipment) of the 
final rule; and
    3. Include qualitative and quantitative assessments of the 
anticipated benefits of the final rule.
    Since all of the anticipated expenditures by the private sector 
analyzed in the final RIA and the final RFA analysis would be borne by 
the offshore oil and gas exploration industry, the final RIA and final 
RFA analysis satisfy the UMRA requirement to estimate any 
disproportionate budgetary effects of the proposed rule on a particular 
segment of the private sector (i.e., the offshore oil and gas 
industry).
    As discussed in the Regulatory Planning and Review section 
(regarding E.O. 12866 and the RFA), and as explained fully in the final 
RIA, BSEE considered three regulatory alternatives for dealing with the 
safety and environmental concerns raised by past and potential future 
losses of well control. BSEE has decided to move forward with this 
final rule (Alternative 1) because the other alternatives would not as 
efficiently or effectively address the safety or environmental concerns 
raised by various investigations and studies related to the Deepwater 
Horizon incident or achieve the objectives of this final rule.

Takings Implication Assessment (E.O. 12630)

    Under the criteria in E.O. 12630, this 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 E.O. 13132, this rule does not have 
federalism implications. 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 
assessment is not required.

Civil Justice Reform (E.O. 12988)

    This 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)

    The 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 DOI's Policy on 
Consultation with Indian Tribes (Secretarial Order 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.

Paperwork Reduction Act (PRA) of 1995

    This rule contains a collection of information that was submitted 
to the Office of Management and Budget (OMB) for review and approval 
under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.). The 
title of the collection of information for this rule is 30 CFR part 
250, subpart G, Well Operations and Equipment. The OMB approved the 
collection under Control Number 1014-0028, expiration 04/30/2019, 
285,111 hours, $102,500 non-hour cost burdens. The information 
collection concerns BOP system requirements and maintaining well 
control among others; 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.
    Potential respondents comprise Federal OCS oil, gas, and sulfur 
operators and lessees. The frequency of response varies depending upon 
the requirement. Responses to this collection of information are 
mandatory, or are required to obtain or retain a benefit. The 
information collection (IC) does not include questions of a sensitive 
nature. BSEE will protect proprietary information according to the 
Freedom of Information Act (5 U.S.C. 552) and DOI's implementing 
regulations (43 CFR part 2), 30 CFR 250.197, Data and information to be 
made available to the public or for limited inspection, and 30 CFR part 
252, OCS Oil and Gas Information Program.

[[Page 26002]]

    As stated in the preamble, BSEE received 172 sets of comments from 
individual entities (companies, industry organizations, or private 
citizens), of which 12 comments pertained to IC. The commenters 
discussed the additional burden and felt, in some cases, that the 
burden was not necessarily sufficient. Therefore, based on these 
comments there are changes to the paperwork requirements and/or burdens 
and these changes are as follows:
    Applications for Permit to Drill (APD)--we increased the burden 
hours (+510 hours);
    Applications for Permit to Modify--we increased the burden hours 
(+2,411 hours);
    Also, while reviewing comments on the final rule it became more 
clear that under Sec.  250.712(a), (b), and (f), we were counting the 
number of physical rigs on the OCS rather than counting the number of 
rig movement forms submitted. Therefore, we increased the number of 
response and burden to accurately reflect the number of forms submitted 
(+681 responses and +166 hours);
    Under Sec.  250.712(c), (e)--we increased the burden hours relating 
to notifications if rigs are warm or cold stacked (+25 responses and 
+12 hours);
    The burden hours for Sec.  250.713(a), (b)--information on MODUs--
we revised the burden for collecting and reporting additional 
information (+466 responses and +2,330 hours);
    Under Sec.  250.724--RTM burden hours were increased (-20 responses 
and +64,200 hours);
    Under Sec.  250.724(c)--we added burden hours for the requirement 
to develop and implement an RTM plan (+130 responses and +650 hours);
    Under Sec.  250.732(a)--we increased burden hours for the 
requirement to submit a verification and supporting information for 
BAVO (+2 responses and +675 hours);
    The burden hours in Sec. Sec.  250.740, 250.741, and 250.724(b) for 
retention of drilling records and RTM data were increased (+95 
responses and +35 hours);
    During the proposed rule, we inadvertently entered the wrong hour 
burden under the subtotal for subpart G (Rig. Req. 1,783 hours should 
have been 1,633 hours); therefore, we have decreased the subtotal (-150 
hours);
    Also, between the proposed rule and the final rule numerous ICs 
were submitted to OMB resulting in increases/decreases in OMB approved 
burdens and responses of various regulatory requirements associated 
with the proposed rule (+577 responses and +22,797 hours) (Note: see 
www.reginfo.gov for all of BSEE's ICs); and
    Due to the IC renewals, the number of responses changed, which also 
affected two revised burdens: subpart B--DWOP (-4 hours) and subpart 
D--EOR (+40 hours).
    This rule affects ICs under 30 CFR part 250, subpart A (1014-0022, 
expiration 8/31/2017); subpart B (1014-0024, expiration 11/30/2018; 
renewal for this subpart is currently at OMB for approval); 
Applications for Permits to Drill (1014-0025, expiration 4/30/17); 
Applications for Permits to Modify (1014-0026, expiration 5/31/17); 
subpart D (1014-0018, expiration 10/31/17); subpart E, (1014-0004, 
expiration 12/31/16); subpart F, (1014-0001, expiration 12/31/16); 
subpart P, (1014-0006, expiration 12/31/16); and subpart Q, (1014-0010, 
expiration 10/31/16). Once this final rule becomes effective, the 
paperwork burdens associated with the various other subparts will be 
removed from this collection of information (subpart G) and 
consolidated with the respective IC burdens under their OMB Control 
Numbers.
    This rule also codifies NTL 2013-G01, Global Positioning Systems 
(GPS) for Mobile Offshore Drilling Units (MODUs) (1014-0013, expiration 
11/30/2018 (renewal for this collection is currently at OMB for 
approval)) into subpart G. Once this final rule becomes effective, the 
IC for that NTL will be discontinued.
BILLING CODE 4310-VH-P

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BILLING CODE 4310-VH-C
    An agency may not conduct or sponsor, and you are not required to 
respond to, a collection of information unless it displays a currently 
valid OMB control number. 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; or email at kye.mason@bsee.gov; 
(703) 787-1607.

National Environmental Policy Act of 1969 (NEPA)

    We prepared a final environmental assessment that concludes that 
this final rule would not have a significant impact on the quality of 
the human environment under NEPA. A copy of the Environmental 
Assessment and Finding of No Significant Impact can be viewed at 
www.regulations.gov (use the keyword/ID BSEE-2015-0002).

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 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.

List of Subjects in 30 CFR Part 250

    Administrative practice and procedure, Continental shelf, 
Environmental impact statements, Environmental protection, 
Incorporation by reference, Oil and gas exploration, Outer Continental 
Shelf--mineral resources, Outer Continental Shelf--rights-of-way, 
Penalties, Reporting and recordkeeping requirements, Sulfur.

Janice M. Schneider,
Assistant Secretary, Land and Minerals Management.

    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, 43 U.S.C. 1334.

Subpart A--General

0
2. Amend Sec.  250.102 by:
0
a. Revising paragraphs (b)(1) and (11) through (13); and
0
b. Adding paragraph (b)(19).
    The revisions and addition read as follows:


Sec.  250.102  What does this part do?

* * * * *
    (b) * * *

       Table--Where To Find Information for Conducting Operations
------------------------------------------------------------------------
       For information about . . .                Refer to . . .
------------------------------------------------------------------------
(1) Applications for permit to drill      30 CFR 250, subparts D and G.
 (APD),.
 
                              * * * * * * *
(11) Oil and gas well-completion          30 CFR 250, subparts E and G.
 operations,.
(12) Oil and gas well-workover            30 CFR 250, subparts F and G.
 operations,.
(13) Decommissioning activities,........  30 CFR 250, subparts G and Q.
 

[[Page 26014]]

 
                              * * * * * * *
(19) Well operations and equipment,.....  30 CFR 250, subpart G.
------------------------------------------------------------------------


0
3. Amend Sec.  250.107 by:
0
a. Removing the word ``and'' from the end of paragraph (a)(1);
0
b. Removing the period from the end of paragraph (a)(2) and adding in 
its place a semicolon; and
0
c. Adding paragraphs (a)(3) and (4) and (e).
    The additions read as follows:


Sec.  250.107  What must I do to protect health, safety, property, and 
the environment?

    (a) * * *
    (3) Utilizing recognized engineering practices that reduce risks to 
the lowest level practicable when conducting design, fabrication, 
installation, operation, inspection, repair, and maintenance 
activities; and
    (4) Complying with all lease, plan, and permit terms and 
conditions.
* * * * *
    (e) BSEE may issue orders to ensure compliance with this part, 
including, but not limited to, orders to produce and submit records and 
to inspect, repair, and/or replace equipment. BSEE may also issue 
orders to shut-in operations of a component or facility because of a 
threat of serious, irreparable, or immediate harm to health, safety, 
property, or the environment posed by those operations or because the 
operations violate law, including a regulation, order, or provision of 
a lease, plan, or permit.

0
4. In Sec.  250.125, revise the table in paragraph (a) to read as 
follows:


Sec.  250.125  Service fees.

    (a) * * *

------------------------------------------------------------------------
 Service--processing of the
         following:                Fee amount          30 CFR Citation
------------------------------------------------------------------------
(1) Suspension of Operations/ $2,123..............  Sec.   250.171(e).
 Suspension of Production
 (SOO/SOP) Request.
(2) Deepwater Operations      3,599...............  Sec.   250.292(q).
 Plan (DWOP).
(3) Application for Permit    $2,113 for initial    Sec.   250.410(d);
 to Drill (APD); Form BSEE-    applications only;    Sec.   250.513(b);
 0123.                         no fee for            Sec.   250.1617(a).
                               revisions..
(4) Application for Permit    125.................  Sec.   250.465(b);
 to Modify (APM); Form BSEE-                         Sec.   250.513(b);
 0124.                                               Sec.   250.613(b);
                                                     Sec.   250.1618(a);
                                                     Sec.   250.1704(g).
(5) New Facility Production   $5,426 A component    Sec.   250.802(e).
 Safety System Application     is a piece of
 for facility with more than   equipment or
 125 components.               ancillary system
                               that is protected
                               by one or more of
                               the safety devices
                               required by API RP
                               14C (as
                               incorporated by
                               reference in Sec.
                               250.198); $14,280
                               additional fee will
                               be charged if BSEE
                               deems it necessary
                               to visit a facility
                               offshore, and
                               $7,426 to visit a
                               facility in a
                               shipyard..
(6) New Facility Production   $1,314 Additional     Sec.   250.802(e).
 Safety System Application     fee of $8,967 will
 for facility with 25-125      be charged if BSEE
 components.                   deems it necessary
                               to visit a facility
                               offshore, and
                               $5,141 to visit a
                               facility in a
                               shipyard..
(7) New Facility Production   652.................  Sec.   250.802(e).
 Safety System Application
 for facility with fewer
 than 25 components.
(8) Production Safety System  605.................  Sec.   250.802(e).
 Application--Modification
 with more than 125
 components reviewed.
(9) Production Safety System  217.................  Sec.   250.802(e).
 Application--Modification
 with 25-125 components
 reviewed.
(10) Production Safety        92..................  Sec.   250.802(e).
 System Application--
 Modification with fewer
 than 25 components reviewed.
(11) Platform Application--   22,734..............  Sec.   250.905(l).
 Installation--Under the
 Platform Verification
 Program.
(12) Platform Application--   3,256...............  Sec.   250.905(l).
 Installation--Fixed
 Structure Under the
 Platform Approval Program.
(13) Platform Application--   1,657...............  Sec.   250.905(l)
 Installation--Caisson/Well
 Protector.
(14) Platform Application--   3,884...............  Sec.   250.905(l).
 Modification/Repair.
(15) New Pipeline             3,541...............  Sec.   250.1000(b).
 Application (Lease Term).
(16) Pipeline Application--   2,056...............  Sec.   250.1000(b).
 Modification (Lease Term).
(17) Pipeline Application--   4,169...............  Sec.   250.1000(b).
 Modification (ROW).
(18) Pipeline Repair          388.................  Sec.   250.1008(e).
 Notification.
(19) Pipeline Right-of-Way    2,771...............  Sec.   250.1015(a).
 (ROW) Grant Application.
(20) Pipeline Conversion of   236.................  Sec.   250.1015(a).
 Lease Term to ROW.

[[Page 26015]]

 
(21) Pipeline ROW Assignment  201.................  Sec.   250.1018(b).
(22) 500 Feet From Lease/     3,892...............  Sec.   250.1156(a).
 Unit Line Production
 Request.
(23) Gas Cap Production       4,953...............  Sec.   250.1157.
 Request.
(24) Downhole Commingling     5,779...............  Sec.   250.1158(a).
 Request.
(25) Complex Surface          4,056...............  Sec.   250.1202(a);
 Commingling and Measurement                         Sec.   250.1203(b);
 Application.                                        Sec.   250.1204(a).
(26) Simple Surface           1,371...............  Sec.   250.1202(a);
 Commingling and Measurement                         Sec.   250.1203(b);
 Application.                                        Sec.   250.1204(a).
(27) Voluntary Unitization    12,619..............  Sec.   250.1303(d).
 Proposal or Unit Expansion.
(28) Unitization Revision...  896.................  Sec.   250.1303(d).
(29) Application to Remove a  4,684...............  Sec.   250.1727.
 Platform or Other Facility.
(30) Application to           1,142...............  Sec.   250.1751(a)
 Decommission a Pipeline                             or
 (Lease Term).                                      Sec.   250.1752(a).
(31) Application to           2,170...............  Sec.   250.1751(a)
 Decommission a Pipeline                             or
 (ROW).                                             Sec.   250.1752(a).
------------------------------------------------------------------------

* * * * *

0
5. Amend Sec.  250.198 by:
0
a. Revising paragraphs (h)(51), (63), (68), and (70); and
0
b. Removing the period at the end of paragraph (h)(88) and adding a 
semicolon in its place; and
0
c. Adding paragraphs (h)(89) through (94).
    The revisions and additions read as follows:


Sec.  250.198  Documents incorporated by reference.

* * * * *
    (h) * * *
    (51) API Recommended Practice 2RD, Design of Risers for Floating 
Production Systems (FPSs) and Tension-Leg Platforms (TLPs), First 
Edition, June 1998; Reaffirmed May 2006, including Errata June 2009, 
incorporated by reference at Sec. Sec.  250.292, 250.733, 250.800, 
250.901, and 250.1002;
* * * * *
    (63) API Standard 53, Blowout Prevention Equipment Systems for 
Drilling Wells, Fourth Edition, November 2012, incorporated by 
reference at Sec. Sec.  250.730, 250.735, 250.737, and 250.739;
* * * * *
    (68) ANSI/API Specification Q1, Specification for Quality Programs 
for the Petroleum, Petrochemical and Natural Gas Industry, Eighth 
Edition, December 2007, incorporated by reference at Sec. Sec.  250.730 
and 250.806;
* * * * *
    (70) ANSI/API Specification 6A, Specification for Wellhead and 
Christmas Tree Equipment, Nineteenth Edition, July 2004, including 
Errata 1 (September 2004), Errata 2 (April 2005), Errata 3 (June 2006), 
Errata 4 (August 2007), Errata 5 (May 2009), Addendum 1 (February 
2008), Addenda 2, 3, and 4 (December 2008), incorporated by reference 
at Sec. Sec.  250.730, 250.806, and 250.1002;
* * * * *
    (89) ANSI/API Specification 11D1, Packers and Bridge Plugs, Second 
Edition, July 2009, incorporated by reference at Sec. Sec.  250.518, 
250.619, and 250.1703;
    (90) ANSI/API Specification 16A, Specification for Drill-through 
Equipment, Third Edition, June 2004, Reaffirmed August 2010, 
incorporated by reference at Sec.  250.730;
    (91) ANSI/API Specification 16C, Specification for Choke and Kill 
Systems, First Edition, January 1993, Reaffirmed July 2010; 
incorporated by reference at Sec.  250.730;
    (92) API Specification 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;
    (93) ANSI/API Specification 17D, Design and Operation of Subsea 
Production Systems--Subsea Wellhead and Tree Equipment, Second Edition; 
May 2011, incorporated by reference at Sec.  250.730; and
    (94) ANSI/API Recommended Practice 17H, Remotely Operated Vehicle 
Interfaces on Subsea Production Systems, First Edition, July 2004, 
Reaffirmed January 2009, incorporated by reference at Sec.  250.734.
* * * * *

0
6. In Sec.  250.199, revise paragraph (e) to read as follows:


Sec.  250.199  Paperwork Reduction Act statements--information 
collection.

* * * * *
    (e) BSEE is collecting this information for the reasons given in 
the following table:

------------------------------------------------------------------------
 30 CFR Subpart, title and/or BSEE Form   BSEE collects this information
            (OMB Control No.)                     and uses it to:
------------------------------------------------------------------------
(1) Subpart A, General (1014-0022),       (i) Determine that activities
 including Forms BSEE-0011, iSEE; BSEE-    on the OCS comply with
 0132, Evacuation Statistics; BSEE-0143,   statutory and regulatory
 Facility/Equipment Damage Report; BSEE-   requirements; are safe and
 1832, Notification of Incidents of        protect the environment; and
 Noncompliance.                            result in diligent
                                           development and production on
                                           OCS leases.
                                          (ii) Support the unproved and
                                           proved reserve estimation,
                                           resource assessment, and fair
                                           market value determinations.
                                          (iii) Assess damage and
                                           project any disruption of oil
                                           and gas production from the
                                           OCS after a major natural
                                           occurrence.
(2) Subpart B, Plans and Information      Evaluate Deepwater Operations
 (1014-0024).                              Plans for compliance with
                                           statutory and regulatory
                                           requirements
(3) Subpart C, Pollution Prevention and   (i) Evaluate measures to
 Control (1014-0023).                      prevent unauthorized
                                           discharge of pollutants into
                                           the offshore waters.

[[Page 26016]]

 
                                          (ii) Ensure action is taken to
                                           control pollution.
(4) Subpart D, Oil and Gas and Drilling   (i) Evaluate the equipment and
 Operations (1014-0018), including Forms   procedures to be used in
 BSEE-0125, End of Operations Report;      drilling operations on the
 BSEE-0133, Well Activity Report; and      OCS.
 BSEE-0133S, Open Hole Data Report.
                                          (ii) Ensure that drilling
                                           operations meet statutory and
                                           regulatory requirements.
(5) Subpart E, Oil and Gas Well-          (i) Evaluate the equipment and
 Completion Operations (1014-0004).        procedures to be used in well-
                                           completion operations on the
                                           OCS.
                                          (ii) Ensure that well-
                                           completion operations meet
                                           statutory and regulatory
                                           requirements.
(6) Subpart F, Oil and Gas Well Workover  (i) Evaluate the equipment and
 Operations (1014-0001).                   procedures to be used during
                                           well-workover operations on
                                           the OCS.
                                          (ii) Ensure that well-workover
                                           operations meet statutory and
                                           regulatory requirements.
(7) Subpart G, Blowout Preventer Systems  (i) Evaluate the equipment and
 (1014-0028), including Form BSEE-0144,    procedures to be used during
 Rig Movement Notification Report.         well drilling, completion,
                                           workover, and abandonment
                                           operations on the OCS.
                                          (ii) Ensure that well
                                           operations meet statutory and
                                           regulatory requirements.
(8) Subpart H, Oil and Gas Production     (i) Evaluate the equipment and
 Safety Systems (1014-0003).               procedures that will be used
                                           during production operations
                                           on the OCS.
                                          (ii) Ensure that production
                                           operations meet statutory and
                                           regulatory requirements.
(9) Subpart I, Platforms and Structures   (i) Evaluate the design,
 (1014-0011).                              fabrication, and installation
                                           of platforms on the OCS.
                                          (ii) Ensure the structural
                                           integrity of platforms
                                           installed on the OCS.
(10) Subpart J, Pipelines and Pipeline    (i) Evaluate the design,
 Rights-of-Way (1014-0016), including      installation, and operation
 Form BSEE-0149, Assignment of Federal     of pipelines on the OCS.
 OCS Pipeline Right-of-Way Grant.
                                          (ii) Ensure that pipeline
                                           operations meet statutory and
                                           regulatory requirements.
(11) Subpart K, Oil and Gas Production    (i) Evaluate production rates
 Rates (1014-0019), including Forms BSEE-  for hydrocarbons produced on
 0126, Well Potential Test Report and      the OCS.
 BSEE-0128, Semiannual Well Test Report.
                                          (ii) Ensure economic
                                           maximization of ultimate
                                           hydrocarbon recovery.
(12) Subpart L, Oil and Gas Production    (i) Evaluate the measurement
 Measurement, Surface Commingling, and     of production, commingling of
 Security (1014-0002).                     hydrocarbons, and site
                                           security plans.
                                          (ii) Ensure that produced
                                           hydrocarbons are measured and
                                           commingled to provide for
                                           accurate royalty payments and
                                           security.
(13) Subpart M, Unitization (1014-0015).  (i) Evaluate the unitization
                                           of leases.
                                          (ii) Ensure that unitization
                                           prevents waste, conserves
                                           natural resources, and
                                           protects correlative rights.
(14) Subpart N, Remedies and Penalties..  (The requirements in subpart N
                                           are exempt from the Paperwork
                                           Reduction Act of 1995
                                           according to 5 CFR 1320.4).
(15) Subpart O, Well Control and          (i) Evaluate training program
 Production Safety Training (1014-0008).   curricula for OCS workers,
                                           course schedules, and
                                           attendance.
                                          (ii) Ensure that training
                                           programs are technically
                                           accurate and sufficient to
                                           meet statutory and regulatory
                                           requirements, and that
                                           workers are properly trained.
(16) Subpart P, Sulfur Operations (1014-  (i) Evaluate sulfur
 0006).                                    exploration and development
                                           operations on the OCS.
                                          (ii) Ensure that OCS sulfur
                                           operations meet statutory and
                                           regulatory requirements and
                                           will result in diligent
                                           development and production of
                                           sulfur leases.
(17) Subpart Q, Decommissioning           Ensure that decommissioning
 Activities (1014-0010).                   activities, site clearance,
                                           and platform or pipeline
                                           removal are properly
                                           performed to meet statutory
                                           and regulatory requirements
                                           and do not conflict with
                                           other users of the OCS.
(18) Subpart S, Safety and Environmental  (i) Evaluate operators'
 Management Systems (1014-0017),           policies and procedures to
 including Form BSEE-0131, Performance     assure safety and
 Measures Data.                            environmental protection
                                           while conducting OCS
                                           operations (including those
                                           operations conducted by
                                           contractor and subcontractor
                                           personnel).
                                          (ii) Evaluate Performance
                                           Measures Data relating to
                                           risk and number of accidents,
                                           injuries, and oil spills
                                           during OCS activities.
(19) Application for Permit to Drill      (i) Evaluate and approve the
 (APD, Revised APD), Form BSEE-0123; and   adequacy of the equipment,
 Supplemental APD Information Sheet,       materials, and/or procedures
 Form BSEE-0123S, and all supporting       that the lessee or operator
 documentation (1014-0025).                plans to use during drilling.
                                          (ii) Ensure that applicable
                                           OCS operations meet statutory
                                           and regulatory requirements.

[[Page 26017]]

 
(20) Application for Permit to Modify     (i) Evaluate and approve the
 (APM), Form BSEE-0124, and supporting     adequacy of the equipment,
 documentation (1014-0026).                materials, and/or procedures
                                           that the lessee or operator
                                           plans to use during drilling
                                           and to evaluate well plan
                                           modifications and changes in
                                           major equipment.
                                          (ii) Ensure that applicable
                                           OCS operations meet statutory
                                           and regulatory requirements.
------------------------------------------------------------------------

Subpart B--Plans and Information

0
7. Amend Sec.  250.292 by:
0
a. Removing the word ``and'' from the end of paragraph (o);
0
b. Redesignating paragraph (p) as paragraph (q); and
0
c. Adding new paragraph (p).
    The addition reads 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 critical chain, wire 
rope, or synthetic tether to connect the top of the riser to a buoyancy 
air can, 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 
tether system;
    (2) Detailed information on the design, fabrication, and 
installation of the FSHR, buoy and tether system, including pressure 
ratings, fatigue life, and yield strengths;
    (3) A description of how you met the design requirements, load 
cases, and allowable stresses for each load case according to API RP 
2RD (as incorporated by reference in Sec.  250.198);
    (4) Detailed information regarding the tether system used to 
connect the FSHR to a buoyancy air can;
    (5) Descriptions of your monitoring system and monitoring plan to 
monitor the pipeline FSHR and tether for fatigue, stress, and any other 
abnormal condition (e.g., corrosion) that may negatively impact the 
riser or tether; and
    (6) Documentation that the tether system and connection accessories 
for the pipeline FSHR have been certified by an approved classification 
society or equivalent and verified by the CVA required in subpart I of 
this part; and
* * * * *

Subpart D--Oil and Gas Drilling Operations

0
8. Revise Sec.  250.400 to read as follows:


Sec.  250.400  General requirements.

    Drilling operations must be conducted in a safe manner to protect 
against harm or damage to life (including fish and other aquatic life), 
property, natural resources of the Outer Continental Shelf (OCS), 
including any mineral deposits (in areas leased and not leased), the 
National security or defense, or the marine, coastal, or human 
environment. In addition to the requirements of this subpart, you must 
also follow the applicable requirements of subpart G of this part.


Sec. Sec.  250.401 through 250.403  [Removed and Reserve]

0
9. Remove and reserve Sec. Sec.  250.401 through 250.403.


Sec.  250.406  [Removed and Reserve]

0
10. Remove and reserve Sec.  250.406.

0
11. Revise Sec.  250.411 to read as follows:


Sec.  250.411  What information must I submit with my application?

    In addition to forms BSEE-0123 and BSEE-0123S, you must include the 
information required in this subpart and subpart G of this part, 
including the following:

----------------------------------------------------------------------------------------------------------------
  Information that you must include with an APD                     Where to find a description
----------------------------------------------------------------------------------------------------------------
(a) Plat that shows locations of the proposed      Sec.   250.412.
 well,.
(b) Design criteria used for the proposed well,..  Sec.   250.413.
(c) Drilling prognosis,..........................  Sec.   250.414.
(d) Casing and cementing programs,...............  Sec.   250.415.
(e) Diverter systems descriptions,...............  Sec.   250.416.
(f) BOP system descriptions,.....................  Sec.   250.731.
(g) Requirements for using a MODU, and...........  Sec.   250.713.
(h) Additional information.......................  Sec.   250.418.
----------------------------------------------------------------------------------------------------------------


0
12. In Sec.  250.413, revise 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, planned 
safe drilling margin, and casing setting depths in true vertical 
measurements;
* * * * *

0
13. Amend Sec.  250.414 by:
0
a. Revising paragraphs (c), (h), and (i); and
0
b. Adding paragraphs (j) and (k).
    The revisions and additions read as follows:


Sec.  250.414  What must my drilling prognosis include?

* * * * *
    (c) Planned safe drilling margin that is between the estimated pore 
pressure and the lesser of estimated fracture gradients or casing shoe 
pressure integrity test and that is based on a risk assessment 
consistent with expected well conditions and operations.
    (1) Your safe drilling margin must also include use of equivalent 
downhole mud weight that is:
    (i) Greater than the estimated pore pressure; and
    (ii) Except as provided in paragraph (c)(2) of this section, a 
minimum of 0.5 pound per gallon below the lower of the casing shoe 
pressure integrity test or the lowest estimated fracture gradient.
    (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

[[Page 26018]]

data, off-set well data, analog data, seismic data) to justify the 
alternative equivalent downhole mud weight.
    (3) When determining the pore pressure and lowest estimated 
fracture gradient for a specific interval, you must consider related 
off-set well behavior observations.
* * * * *
    (h) A list and description of all requests for using alternate 
procedures or departures from the requirements of this subpart in one 
place in the APD. You must explain how the alternate procedures afford 
an equal or greater degree of protection, safety, or performance, or 
why the departures are requested;
    (i) Projected plans for well testing (refer to Sec.  250.460);
    (j) The type of wellhead system and liner hanger system to be 
installed and a descriptive schematic, which includes but is not 
limited to pressure ratings, dimensions, valves, load shoulders, and 
locking mechanisms, if applicable; and
    (k) Any additional information required by the District Manager 
needed to clarify or evaluate your drilling prognosis.

0
14. In Sec.  250.415, revise paragraph (a) to read as follows:


Sec.  250.415  What must my casing and cementing programs include?

* * * * *
    (a) The following well design information:
    (1) Hole sizes;
    (2) Bit depths (including measured and true vertical depth (TVD));
    (3) Casing information, including sizes, weights, grades, collapse 
and burst values, types of connection, and setting depths (measured and 
TVD) for all sections of each casing interval; and
    (4) Locations of any installed rupture disks (indicate if burst or 
collapse and rating);
* * * * *

0
15. Revise Sec.  250.416 to read as follows:


Sec.  250.416  What must I include in the diverter description?

    You must include in the diverter description:
    (a) A description of the diverter system and its operating 
procedures;
    (b) A schematic drawing of the diverter system (plan and elevation 
views) that shows:
    (1) The size of the element installed in the diverter housing;
    (2) Spool outlet internal diameter(s);
    (3) Diverter-line lengths and diameters; burst strengths and radius 
of curvature at each turn; and
    (4) Valve type, size, working pressure rating, and location.


Sec.  250.417  [Removed and Reserved]

0
16. Remove and reserve Sec.  250.417.

0
17. In Sec.  250.418, revise paragraphs (g) and (h), remove paragraph 
(i), and redesignate paragraph (j) as paragraph (i) to read as follows:


Sec.  250.418  What additional information must I submit with my APD?

* * * * *
    (g) A request for approval, if you plan to wash out or displace 
cement to facilitate casing removal upon well abandonment. Your request 
must include a description of how far below the mudline you propose to 
displace cement and how you will visually monitor returns;
    (h) Certification of your casing and cementing program as required 
in Sec.  250.420(a)(7); and
* * * * *

0
18. Amend Sec.  250.420 by:
0
a. Revising the introductory text and paragraph (a)(5);
0
b. Redesignating paragraph (a)(6) as paragraph (a)(7);
0
c. Adding new paragraph (a)(6) and paragraph (b)(4); and
0
d. Revising paragraph (c).
    The revisions and additions read as follows:


Sec.  250.420  What well casing and cementing requirements must I meet?

    You must case and cement all wells. Your casing and cementing 
programs must meet the applicable requirements of this subpart and of 
subpart G of this part.
    (a) * * *
    (5) Support unconsolidated sediments;
    (6) Provide adequate centralization to ensure proper cementation; 
and
* * * * *
    (b) * * *
    (4) If you need to substitute a different size, grade, or weight of 
casing than what was approved in your APD, you must contact the 
District Manager for approval prior to installing the casing.
* * * * *
    (c) Cementing requirements. (1) You must design and conduct your 
cementing jobs so that cement composition, placement techniques, and 
waiting times ensure that the cement placed behind the bottom 500 feet 
of casing attains a minimum compressive strength of 500 psi before 
drilling out the casing or before commencing completion operations. (If 
a liner is used refer to Sec.  250.421(f)).
    (2) You must use a weighted fluid during displacement to maintain 
an overbalanced hydrostatic pressure during the cement setting time, 
except when cementing casings or liners in riserless hole sections.

0
19. In Sec.  250.421, revise paragraphs (b) 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
------------------------------------------------------------------------
 
                              * * * * * * *
(b) Conductor...............  Design casing and     Use enough cement to
                               select setting        fill the calculated
                               depths based on       annular space back
                               relevant              to the mudline.
                               engineering and      Verify annular fill
                               geologic factors.     by observing cement
                               These factors         returns. If you
                               include the           cannot observe
                               presence or absence   cement returns, use
                               of hydrocarbons,      additional cement
                               potential hazards,    to ensure fill-back
                               and water depths.     to the mudline.
                              Set casing            For drilling on an
                               immediately before    artificial island
                               drilling into         or when using a
                               formations known to   well cellar, you
                               contain oil or gas.   must discuss the
                               If you encounter      cement fill level
                               oil or gas or         with the District
                               unexpected            Manager.
                               formation pressure
                               before the planned
                               casing point, you
                               must set casing
                               immediately and set
                               it above the
                               encountered zone.
------------------------------------------------------------------------
 

[[Page 26019]]

 
                              * * * * * * *
------------------------------------------------------------------------
(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        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. If you have
                               below an              a liner lap and are
                               intermediate          unable to cement
                               string, you must      500 feet above the
                               set the top of the    previous shoe, as
                               liner at least 100    provided by
                               feet above the        paragraphs (d) and
                               previous casing       (e) of this
                               shoe.                 section, you must
                              You may not use a      submit and receive
                               liner as conductor    approval from the
                               casing.               District Manager on
                              A subsea well casing   a case-by-case
                               string whose top is   basis.
                               above the mudline
                               and that has been
                               cemented back to
                               the mudline will
                               not be considered a
                               liner.
------------------------------------------------------------------------


0
20. Revise Sec.  250.423 to read as follows:


Sec.  250.423  What are the requirements for casing and liner 
installation?

    You must ensure proper installation of casing in the subsea 
wellhead or liner in the liner hanger.
    (a) You must ensure that the latching mechanisms or lock down 
mechanisms are engaged upon successfully installing and cementing the 
casing string. If there is an indication of an inadequate cement job, 
you must comply with Sec.  250.428(c).
    (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 and cementing the 
liner. If there is an indication of an inadequate cement job, you must 
comply with Sec.  250.428(c).
    (c) You must perform a pressure test on the casing seal assembly to 
ensure proper installation of casing or liner. You must perform this 
test for the intermediate and production casing strings or liners.
    (1) You must submit for approval with your APD, test procedures and 
criteria for a successful test.
    (2) You must document all your test results and make them available 
to BSEE upon request.


Sec. Sec.  250.424 through 250.426  [Removed and Reserved]

0
21. Remove and reserve Sec. Sec.  250.424 through 250.426.

0
22. In Sec.  250.427, revise 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 margins 
identified in Sec.  250.414. When you cannot maintain the safe margins, 
you must suspend drilling operations and remedy the situation.

0
23. Amend Sec.  250.428 by:
0
a. Revising paragraphs (b) through (d); and
0
b. Adding paragraph (k).
    The revisions and addition read as follows:


Sec.  250.428  What must I do in certain cementing and casing 
situations?

* * * * *

------------------------------------------------------------------------
 If you encounter the following situation:       Then you must . . .
------------------------------------------------------------------------
 
                              * * * * * * *
------------------------------------------------------------------------
(b) Need to change casing setting depths    Submit those changes to the
 or hole interval drilling depth (for a      District Manager for
 BHA with an under-reamer, this means bit    approval and include a
 depth) more than 100 feet true vertical     certification by a
 depth (TVD) from the approved APD due to    professional engineer (PE)
 conditions encountered during drilling      that he or she reviewed and
 operations,                                 approved the proposed
                                             changes.
(c) Have indication of inadequate cement    (1) Locate the top of cement
 job (such as lost returns, no cement        by:
 returns to mudline or expected height,     (i) Running a temperature
 cement channeling, or failure of            survey;
 equipment),                                (ii) Running a cement
                                             evaluation log; or
                                            (iii) 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,                  Take remedial actions. The
                                             District Manager must
                                             review and approve all
                                             remedial actions 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 will
                                             require submittal of a
                                             certification by a
                                             professional engineer (PE)
                                             certifying that he or she
                                             reviewed and approved the
                                             proposed changes, and must
                                             meet any other requirements
                                             of the District Manager.
------------------------------------------------------------------------
 

[[Page 26020]]

 
                              * * * * * * *
------------------------------------------------------------------------
(k) Plan to use a valve(s) on the drive     Include a description of the
 pipe during cementing operations for the    plan in your APD. Your
 conductor casing, surface casing, or        description must include a
 liner,                                      schematic of the valve and
                                             height above the water
                                             line. The valve must be
                                             remotely operated and full
                                             opening with visual
                                             observation while taking
                                             returns. The person in
                                             charge of observing returns
                                             must be in communication
                                             with the drill floor. You
                                             must record in your daily
                                             report and in the WAR if
                                             cement returns were
                                             observed. If cement returns
                                             are not observed, you must
                                             contact the District
                                             Manager and obtain approval
                                             of proposed plans to locate
                                             the top of cement before
                                             continuing with operations.
------------------------------------------------------------------------

Sec. Sec.  250.440 through 250.451  [Removed and Reserved]

0
24. Remove the undesignated center heading ``Blowout Preventer (BOP) 
System Requirements'' and remove and reserve Sec. Sec.  250.440 through 
250.451.


Sec.  250.456  [Amended]

0
25. Amend Sec.  250.456:
0
a. In paragraph (i), by adding the word ``and'' after the semicolon;
0
b. By removing paragraph (j); and
0
c. By redesignating paragraph (k) as paragraph (j).

0
26. Revise Sec.  250.462 to read as follows:


Sec.  250.462  What are the source control, containment, and collocated 
equipment requirements?

    For drilling operations using a subsea BOP or surface BOP on a 
floating facility, you must have the ability to control or contain a 
blowout event at the sea floor.
    (a) To determine your required source control and containment 
capabilities you must do the following:
    (1) Consider a scenario of the wellbore fully evacuated to 
reservoir fluids, with no restrictions in the well.
    (2) Evaluate the performance of the well as designed to determine 
if a full shut-in can be achieved without having reservoir fluids 
broach to the sea floor. If your evaluation indicates that the well can 
only be partially shut-in, then you must determine your ability to flow 
and capture the residual fluids to a surface production and storage 
system.
    (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. This SCCE, supporting equipment, and collocated equipment 
must include, but is not limited to, the following:
    (1) Subsea containment and capture equipment, including containment 
domes and capping stacks;
    (2) Subsea utility equipment including hydraulic power sources and 
hydrate control equipment;
    (3) Collocated equipment including dispersant injection equipment;
    (4) Riser systems;
    (5) Remotely operated vehicles (ROVs);
    (6) Capture vessels;
    (7) Support vessels; and
    (8) Storage facilities.
    (c) You must submit a description of your source control and 
containment capabilities to the Regional Supervisor and receive 
approval before BSEE will approve your APD, Form BSEE-0123. The 
description of your containment capabilities must contain the 
following:
    (1) Your source control and containment capabilities for 
controlling and containing a blowout event at the seafloor;
    (2) A discussion of the determination required in paragraph (a) of 
this section; and
    (3) Information showing that you have access to and the ability to 
deploy all equipment required by paragraph (b) of this section.
    (d) You must contact the District Manager and Regional Supervisor 
for reevaluation of your source control and containment capabilities if 
your:
    (1) Well design changes; or
    (2) Approved source control and containment equipment is out of 
service.
    (e) You must maintain, test, and inspect the source control, 
containment, and collocated equipment identified in the following table 
according to these requirements:

------------------------------------------------------------------------
                                Requirements, you        Additional
          Equipment                   must:              information
------------------------------------------------------------------------
(1) Capping stacks,.........  (i) Function test     Pressure containing
                               all pressure          critical components
                               containing critical   are those
                               components on a       components that
                               quarterly frequency   will experience
                               (not to exceed 104    wellbore pressure
                               days between          during a shut-in
                               tests),               after being
                                                     functioned.
                              (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 a      wellhead
                               BSEE-approved         connectors, and
                               verification          outlet valves.
                               organization.
                              (iii) Notify BSEE at  ....................
                               least 21 days prior
                               to commencing any
                               pressure testing.
(2) Production safety         (i) Meet or exceed    ....................
 systems used for flow and     the requirements
 capture operations,           set forth in Sec.
                               Sec.   250.800
                               through 250.808,
                               excluding required
                               equipment that
                               would be installed
                               below the wellhead
                               or that is not
                               applicable to the
                               cap and flow
                               system.
                              (ii) Have all         ....................
                               equipment unique to
                               containment
                               operations
                               available for
                               inspection at all
                               times.
(3) Subsea utility            Have all referenced   Subsea utility
 equipment,.                   containment           equipment includes,
                               equipment available   but is not limited
                               for inspection at     to: Hydraulic power
                               all times.            sources, debris
                                                     removal, and
                                                     hydrate control
                                                     equipment.

[[Page 26021]]

 
(4) Collocated equipment,...  Have equipment        Collocated equipment
                               available for         includes, but is
                               inspection at all     not limited to,
                               times.                dispersant
                                                     injection equipment
                                                     and other subsea
                                                     control equipment.
------------------------------------------------------------------------


0
27. In Sec.  250.465, revise paragraph (b)(3) to read as follows:


Sec.  250.465  When must I submit an Application for Permit to Modify 
(APM) or an End of Operations Report to BSEE?

* * * * *
    (b) * * *
    (3) Within 30 days after completing this work, you must submit an 
End of Operations Report (EOR), Form BSEE-0125, as required under Sec.  
250.744.


Sec. Sec.  250.466 through 250.469   [Removed and Reserved]

0
28. Remove and reserve Sec. Sec.  250.466 through 250.469.

Subpart E--Oil and Gas Well-Completion Operations

0
29. Revise Sec.  250.500 to read as follows:


Sec.  250.500  General requirements.

    Well-completion operations must be conducted in a manner to protect 
against harm or damage to life (including fish and other aquatic life), 
property, natural resources of the OCS, including any mineral deposits 
(in areas leased and not leased), the National security or defense, or 
the marine, coastal, or human environment. In addition to the 
requirements of this subpart, you must also follow the applicable 
requirements of subpart G of this part.


Sec. Sec.  250.502 and 250.506   [Removed and Reserved]

0
30. Remove and reserve Sec. Sec.  250.502 and 250.506.
0
31. In Sec.  250.513, revise paragraph (b)(4) to read as follows:


Sec.  250.513  Approval and reporting of well-completion operations.

* * * * *
    (b) * * *
    (4) All applicable information required in Sec.  250.731.
* * * * *


Sec.  250.514  [Amended]

0
32. In Sec.  250.514, remove paragraph (d).


Sec. Sec.  250.515 through 250.517   [Removed and Reserved]

0
33. Remove and reserve Sec. Sec.  250.515 through 250.517.
0
34. Amend Sec.  250.518 by:
0
a. Removing paragraph (b);
0
b. Redesignating paragraphs (c) through (e) as paragraphs (b) through 
(d); and
0
c. Adding new paragraph (e) and paragraph (f).
    The additions read as follows:


Sec.  250.518  Tubing and wellhead equipment.

* * * * *
    (e) When installed, packers and bridge plugs must meet the 
following:
    (1) All permanently installed packers and bridge plugs must comply 
with API Spec. 11D1 (as incorporated by reference in Sec.  250.198);
    (2) The production packer must be set at a depth that will allow 
for a column of weighted fluids to be placed above the packer that will 
exert a hydrostatic force greater than or equal to the force created by 
the reservoir pressure below the packer;
    (3) The production packer must be set as close as practically 
possible to the perforated interval; and
    (4) The production packer must be set at a depth that is within the 
cemented interval of the selected casing section.
    (f) Your APM must include a description and calculations for how 
you determined the production packer setting depth.

Subpart F--Oil and Gas Well-Workover Operations

0
35. Revise Sec.  250.600 to read as follows:


Sec.  250.600  General requirements.

    Well-workover operations must be conducted in a manner to protect 
against harm or damage to life (including fish and other aquatic life), 
property, natural resources of the Outer Continental Shelf (OCS) 
including any mineral deposits (in areas leased and not leased), the 
National security or defense, or the marine, coastal, or human 
environment. In addition to the requirements of this subpart, you must 
also follow the applicable requirements of subpart G of this part.


Sec.  250.602  [Removed and Reserved]

0
36. Remove and reserve Sec.  250.602.


Sec.  250.606  [Removed and Reserved]

0
37. Remove and reserve Sec.  250.606.
0
38. In Sec.  250.613, revise paragraph (b)(3) to read as follows:


Sec.  250.613  Approval and reporting for well-workover operations.

* * * * *
    (b) * * *
    (3) All information required in Sec.  250.731.
* * * * *


Sec.  250.614  [Amended]

0
39. In Sec.  250.614, remove paragraph (d).


Sec.  250.615  [Removed and Reserved]

0
40. Remove and reserve Sec.  250.615.

0
41. Amend Sec.  250.616 by:
0
a. Revising the section heading;
0
b. Removing paragraphs (a) through (e); and
0
c. Redesignating paragraphs (f) through (h) as paragraphs (a) through 
(c).
    The revision reads as follows:


Sec.  250.616  Coiled tubing and snubbing operations.

* * * * *


Sec. Sec.  250.617 and 250.618   [Removed and Reserved]

0
42. Remove and reserve Sec. Sec.  250.617 and 250.618.
0
43. Amend Sec.  250.619 by:
0
a. Removing paragraph (b);
0
b. Redesignating paragraphs (c) through (e) as paragraphs (b) through 
(d); and
0
c. Adding new paragraph (e) and paragraph (f).
    The additions read as follows:


Sec.  250.619  Tubing and wellhead equipment.

* * * * *
    (e) If you pull and reinstall packers and bridge plugs, you must 
meet the following requirements:
    (1) All permanently installed packers and bridge plugs must comply 
with API Spec. 11D1 (as incorporated by reference in Sec.  250.198);
    (2) The production packer must be set at a depth that will allow 
for a column of weighted fluids to be placed above the packer that will 
exert a hydrostatic force greater than or equal to the force created by 
the reservoir pressure below the packer;
    (3) The production packer must be set as close as practically 
possible to the perforated interval; and
    (4) The production packer must be set at a depth that is within the 
cemented interval of the selected casing section.

[[Page 26022]]

    (f) Your APM must include a description and calculations for how 
you determined the production packer setting depth.

0
44. Add subpart G to read as follows:
Subpart G--Well Operations and Equipment

General Requirements

Sec.
250.700 What operations and equipment does this subpart cover?
250.701 May I use alternate procedures or equipment during 
operations?
250.702 May I obtain departures from these requirements?
250.703 What must I do to keep wells under control?

 Rig Requirements

250.710 What instructions must be given to personnel engaged in well 
operations?
250.711 What are the requirements for well-control drills?
250.712 What rig unit movements must I report?
250.713 What must I provide if I plan to use a mobile offshore 
drilling unit (MODU) for well operations?
250.714 Do I have to develop a dropped objects plan?
250.715 Do I need a global positioning system (GPS) for all MODUs?

Well Operations

250.720 When and how must I secure a well?
250.721 What are the requirements for pressure testing casing and 
liners?
250.722 What are the requirements for prolonged operations in a 
well?
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?
250.724 What are the real-time monitoring requirements?

Blowout Preventer (BOP) System Requirements

250.730 What are the general requirements for BOP systems and system 
components?
250.731 What information must I submit for BOP systems and system 
components?
250.732 What are the BSEE-approved verification organization (BAVO) 
requirements for BOP systems and system components?
250.733 What are the requirements for a surface BOP stack?
250.734 What are the requirements for a subsea BOP system?
250.735 What associated systems and related equipment must all BOP 
systems include?
250.736 What are the requirements for choke manifolds, kelly-type 
valves inside BOPs, and drill string safety valves?
250.737 What are the BOP system testing requirements?
250.738 What must I do in certain situations involving BOP equipment 
or systems?
250.739 What are the BOP maintenance and inspection requirements?

Records and Reporting

250.740 What records must I keep?
250.741 How long must I keep records?
250.742 What well records am I required to submit?
250.743 What are the well activity reporting requirements?
250.744 What are the end of operation reporting requirements?
250.745 What other well records could I be required to submit?
250.746 What are the recordkeeping requirements for casing, liner, 
and BOP tests, and inspections of BOP systems and marine risers?

Subpart G--Well Operations and Equipment

General Requirements


Sec.  250.700  What operations and equipment does this subpart cover?

    This subpart covers operations and equipment associated with 
drilling, completion, workover, and decommissioning activities. This 
subpart includes regulations applicable to drilling, completion, 
workover, and decommissioning activities in addition to applicable 
regulations contained in subparts D, E, F, and Q of this part unless 
explicitly stated otherwise.


Sec.  250.701  May I use alternate procedures or equipment during 
operations?

    You may use alternate procedures or equipment during operations 
after receiving approval as described in Sec.  250.141. You must 
identify and discuss your proposed alternate procedures or equipment in 
your Application for Permit to Drill (APD) (Form BSEE-0123) (see Sec.  
250.414(h)) or your Application for Permit to Modify (APM) (Form BSEE-
0124). Procedures for obtaining approval of alternate procedures or 
equipment are described in Sec.  250.141.


Sec.  250.702  May I obtain departures from these requirements?

    You may apply for a departure from these requirements as described 
in Sec.  250.142. Your request must include a justification showing why 
the departure is necessary. You must identify and discuss the departure 
you are requesting in your APD (see Sec.  250.414(h)) or your APM.


Sec.  250.703  What must I do to keep wells under control?

    You must take the necessary precautions to keep wells under control 
at all times, including:
    (a) Use recognized engineering practices to reduce risks to the 
lowest level practicable when monitoring and evaluating well conditions 
and to minimize the potential for the well to flow or kick;
    (b) Have a person onsite during operations who represents your 
interests and can fulfill your responsibilities;
    (c) Ensure that the toolpusher, operator's representative, or a 
member of the rig crew maintains continuous surveillance on the rig 
floor from the beginning of operations until the well is completed or 
abandoned, unless you have secured the well with blowout preventers 
(BOPs), bridge plugs, cement plugs, or packers;
    (d) Use personnel trained according to the provisions of subparts O 
and S of this part;
    (e) Use and maintain equipment and materials necessary to ensure 
the safety and protection of personnel, equipment, natural resources, 
and the environment; and
    (f) Use equipment that has been designed, tested, and rated for the 
maximum environmental and operational conditions to which it may be 
exposed while in service.

Rig Requirements


Sec.  250.710  What instructions must be given to personnel engaged in 
well operations?

    Prior to engaging in well operations, personnel must be instructed 
in:
    (a) Hazards and safety requirements. You must instruct your 
personnel regarding the safety requirements for the operations to be 
performed, possible hazards to be encountered, and general safety 
considerations to protect personnel, equipment, and the environment as 
required by subpart S of this part. The date and time of safety 
meetings must be recorded and available at the facility for review by 
BSEE representatives.
    (b) Well control. You must prepare a well-control plan for each 
well. Each well-control plan must contain instructions for personnel 
about the use of each well-control component of your BOP, procedures 
that describe how personnel will seal the wellbore and shear pipe 
before maximum anticipated surface pressure (MASP) conditions are 
exceeded, assignments for each crew member, and a schedule for 
completion of each assignment. You must keep a copy of your well-
control plan on the rig at all times, and make it available to BSEE 
upon request. You must post a copy of the well-control plan on the rig 
floor.


Sec.  250.711  What are the requirements for well-control drills?

    You must conduct a weekly well-control drill with all personnel 
engaged in well operations. Your drill must familiarize personnel 
engaged in well operations with their roles and functions so that they 
can perform their

[[Page 26023]]

duties promptly and efficiently as outlined in the well-control plan 
required by Sec.  250.710.
    (a) Timing of drills. You must conduct each drill during a period 
of activity that minimizes the risk to operations. The timing of your 
drills must cover a range of different operations, including drilling 
with a diverter, on-bottom drilling, and tripping. The same drill may 
not be repeated consecutively with the same crew.
    (b) Recordkeeping requirements. For each drill, you must record the 
following in the daily report:
    (1) Date, time, and type of drill conducted;
    (2) The amount of time it took to be ready to close the diverter or 
use each well-control component of BOP system; and
    (3) The total time to complete the entire drill.
    (c) A BSEE ordered drill. A BSEE representative may require you to 
conduct a well-control drill during a BSEE inspection. The BSEE 
representative will consult with your onsite representative before 
requiring the drill.


Sec.  250.712  What rig unit movements must I report?

    (a) You must report the movement of all rig units on and off 
locations to the District Manager using Form BSEE-0144, Rig Movement 
Notification Report. Rig units include MODUs, platform rigs, snubbing 
units, wire-line units used for non-routine operations, and coiled 
tubing units. You must inform the District Manager 24 hours before:
    (1) The arrival of a rig unit on location;
    (2) The movement of a rig unit to another slot. For movements that 
will occur less than 24 hours after initially moving onto location 
(e.g., coiled tubing and batch operations), you may include your 
anticipated movement schedule on Form BSEE-0144; or
    (3) The departure of a rig unit from the location.
    (b) You must provide the District Manager with the rig name, lease 
number, well number, and expected time of arrival or departure.
    (c) If a MODU or platform rig is to be warm or cold stacked, you 
must inform the District Manager:
    (1) Where the MODU or platform rig is coming from;
    (2) The location where the MODU or platform rig will be positioned;
    (3) Whether the MODU or platform rig will be manned or unmanned; 
and
    (4) If the location for stacking the MODU or platform rig changes.
    (d) Prior to resuming operations after stacking, you must notify 
the appropriate District Manager of any construction, repairs, or 
modifications associated with the drilling package made to the MODU or 
platform rig.
    (e) If a drilling rig is entering OCS waters, you must inform the 
District Manager where the drilling rig is coming from.
    (f) If you change your anticipated date for initially moving on or 
off location by more than 24 hours, you must submit an updated Form 
BSEE-0144, Rig Movement Notification Report.


Sec.  250.713  What must I provide if I plan to use a mobile offshore 
drilling unit (MODU) for well operations?

    If you plan to use a MODU for well operations, you must provide:
    (a) Fitness requirements. Information and data to demonstrate the 
MODU's capability to perform at the proposed location. This information 
must include the maximum environmental and operational conditions that 
the MODU is designed to withstand, including the minimum air gap 
necessary for both hurricane and non-hurricane seasons. If sufficient 
environmental information and data are not available at the time you 
submit your APD or APM, the District Manager may approve your APD or 
APM, but require you to collect and report this information during 
operations. Under this circumstance, the District Manager may revoke 
the approval of the APD or APM if information collected during 
operations shows that the MODU is not capable of performing at the 
proposed location.
    (b) Foundation requirements. Information to show that site-specific 
soil and oceanographic conditions are capable of supporting the 
proposed bottom-founded MODU. If you provided sufficient site-specific 
information in your EP, DPP, or DOCD submitted to BOEM, you may 
reference that information. The District Manager may require you to 
conduct additional surveys and soil borings before approving the APD or 
APM if additional information is needed to make a determination that 
the conditions are capable of supporting the MODU, or equipment 
installed on a subsea wellhead. For a moored rig, you must submit a 
plat of the rig's anchor pattern approved in your EP, DPP, or DOCD in 
your APD or APM.
    (c) For frontier areas. (1) If the design of the MODU you plan to 
use in a frontier area is unique or has not been proven for use in the 
proposed environment, the District Manager may require you to submit a 
third-party review of the MODU design. If required, you must obtain a 
third-party review of your MODU similar to the process outlined in 
Sec. Sec.  250.915 through 250.918. You may submit this information 
before submitting an APD or APM.
    (2) If you plan to conduct operations in a frontier area, you must 
have a contingency plan that addresses design and operating limitations 
of the MODU. Your plan must identify the actions necessary to maintain 
safety and prevent damage to the environment. Actions must include the 
suspension, curtailment, or modification of operations to remedy 
various operational or environmental situations (e.g., vessel motion, 
riser offset, anchor tensions, wind speed, wave height, currents, icing 
or ice-loading, settling, tilt or lateral movement, resupply 
capability).
    (d) Additional documentation. You must provide the current 
Certificate of Inspection (for U.S.-flag vessels) or Certificate of 
Compliance (for foreign-flag vessels) from the USCG and Certificate of 
Classification. You must also provide current documentation of any 
operational limitations imposed by an appropriate classification 
society.
    (e) Dynamically positioned MODU. If you use a dynamically 
positioned MODU, you must include in your APD or APM your contingency 
plan for moving off location in an emergency situation. At a minimum, 
your plan must address emergency events caused by storms, currents, 
station-keeping failures, power failures, and losses of well control. 
The District Manager may require your plan to include additional events 
that may require movement of the MODU and other information needed to 
clarify or further address how the MODU will respond to emergencies or 
other events.
    (f) Inspection of MODU. The MODU must be available for inspection 
by the District Manager before commencing operations and at any time 
during operations.
    (g) Current monitoring. For water depths greater than 400 meters 
(1,312 feet), you must include in your APD or APM:
    (1) A description of the specific current speeds that will cause 
you to implement rig shutdown, move-off procedures, or both; and
    (2) A discussion of the specific measures you will take to curtail 
rig operations and move off location when such currents are 
encountered. You may use criteria, such as current velocities, riser 
angles, watch circles, and remaining rig power to describe when these 
procedures or measures will be implemented.

[[Page 26024]]

Sec.  250.714  Do I have to develop a dropped objects plan?

    If you use a floating rig unit in an area with subsea 
infrastructure, you must develop a dropped objects plan and make it 
available to BSEE upon request. This plan must be updated as the 
infrastructure on the seafloor changes. Your plan must include:
    (a) A description and plot of the path the rig will take while 
running and pulling the riser;
    (b) A plat showing the location of any subsea wells, production 
equipment, pipelines, and any other identified debris;
    (c) Modeling of a dropped object's path with consideration given to 
metocean conditions for various material forms, such as a tubular 
(e.g., riser or casing) and box (e.g., BOP or tree);
    (d) Communications, procedures, and delegated authorities 
established with the production host facility to shut-in any active 
subsea wells, equipment, or pipelines in the event of a dropped object; 
and
    (e) Any additional information required by the District Manager as 
appropriate to clarify, update, or evaluate your dropped objects plan.


Sec.  250.715  Do I need a global positioning system (GPS) for all 
MODUs?

    All MODUs must have a minimum of two functioning GPS transponders 
at all times, and you must provide to BSEE real-time access to the GPS 
data prior to and during each hurricane season.
    (a) The GPS must be capable of monitoring the position and tracking 
the path in real-time if the MODU moves from its location during a 
severe storm.
    (b) You must install and protect the tracking system's equipment to 
minimize the risk of the system being disabled.
    (c) You must place the GPS transponders in different locations for 
redundancy to minimize risk of system failure.
    (d) Each GPS transponder must be capable of transmitting data for 
at least 7 days after a storm has passed.
    (e) If the MODU is moved off location in the event of a storm, you 
must immediately begin to record the GPS location data.
    (f) You must contact the Regional Office and allow real-time access 
to the MODU location data. When you contact the Regional Office, 
provide the following:
    (1) Name of the lessee and operator with contact information;
    (2) MODU name;
    (3) Initial date and time; and
    (4) How you will provide GPS real-time access.

Well Operations


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

    (a) Whenever you interrupt operations, you must notify the District 
Manager. Before moving off the well, you must have two independent 
barriers installed, at least one of which must be a mechanical barrier, 
as approved by the District Manager. You must install the barriers at 
appropriate depths within a properly cemented casing string or liner. 
Before removing a subsea BOP stack or surface BOP stack on a mudline 
suspension well, you must conduct a negative pressure test in 
accordance with Sec.  250.721.
    (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;
    (iii) Repair to major rig or well-control equipment; or
    (iv) Observed flow outside the well's casing (e.g., shallow water 
flow or bubbling).
    (2) The District Manager may approve alternate procedures or 
barriers, in accordance with Sec.  250.141, if you do not have time to 
install the required barriers or if special circumstances occur.
    (b) Before you displace kill-weight fluid from the wellbore and/or 
riser, thereby creating an underbalanced state, you must obtain 
approval from the District Manager. To obtain approval, you must submit 
with your APD or APM your reasons for displacing the kill-weight fluid 
and provide detailed step-by-step written procedures describing how you 
will safely displace these fluids. The step-by-step displacement 
procedures must address the following:
    (1) Number and type of independent barriers, as described in Sec.  
250.420(b)(3), that are in place for each flow path that requires such 
barriers;
    (2) Tests you will conduct to ensure integrity of independent 
barriers;
    (3) BOP procedures you will use while displacing kill-weight 
fluids; and
    (4) Procedures you will use to monitor the volumes and rates of 
fluids entering and leaving the wellbore.


Sec.  250.721  What are the requirements for pressure testing casing 
and liners?

    (a) You must test each casing string that extends to the wellhead 
according to the following table:

------------------------------------------------------------------------
              Casing type                     Minimum test pressure
------------------------------------------------------------------------
(1) Drive or Structural,...............  Not required.
(2) Conductor, excluding subsea          250 psi.
 wellheads,.
(3) Surface, Intermediate, and           70 percent of its minimum
 Production,.                             internal yield.
------------------------------------------------------------------------

    (b) You must test each drilling liner and liner-top to a pressure 
at least equal to the anticipated leak-off pressure of the formation 
below that liner shoe, or subsequent liner shoes if set. You must 
conduct this test before you continue operations in the well.
    (c) You must test each production liner and liner-top to a minimum 
of 500 psi above the formation fracture pressure at the casing shoe 
into which the liner is lapped.
    (d) The District Manager may approve or require other casing test 
pressures as appropriate under the circumstances to ensure casing 
integrity.
    (e) If you plan to produce a well, you must:
    (1) For a well that is fully cased and cemented, pressure test the 
entire well to maximum anticipated shut-in tubing pressure, not to 
exceed 70% of the burst rating limit of the weakest component before 
perforating the casing or liner; or
    (2) For an open-hole completion, pressure test the entire well to 
maximum anticipated shut-in tubing pressure, not to exceed 70% of the 
burst rating limit of the weakest component before you drill the open-
hole section.
    (f) You may not resume operations until you obtain a satisfactory 
pressure test. If the pressure declines more than 10 percent in a 30-
minute test, or if there is another indication of a leak, you must 
submit to the District Manager for approval your proposed plans to re-
cement, repair the casing or liner, or run additional casing/liner to 
provide a proper seal. Your submittal must include a PE certification 
of your proposed plans.
    (g) You must perform a negative pressure test on all wells that use 
a subsea BOP stack or wells with mudline suspension systems.
    (1) You must perform a negative pressure test on your final casing 
string

[[Page 26025]]

or liner. This test must be conducted after setting your second barrier 
just above the shoe track, but prior to conducting any completion 
operations.
    (2) You must perform a negative pressure test prior to unlatching 
the BOP at any point in the well. The negative pressure test must be 
performed on those components, at a minimum, that will be exposed to 
the negative differential pressure that will occur when the BOP is 
disconnected.
    (3) The District Manager may require you to perform additional 
negative pressure tests on other casing strings or liners (e.g., 
intermediate casing string or liner) or on wells with a surface BOP 
stack as appropriate to demonstrate casing or liner integrity.
    (4) You must submit for approval with your APD or APM, test 
procedures and criteria for a successful negative pressure test. If any 
of your test procedures or criteria for a successful test change, you 
must submit for approval the changes in a revised APD or APM.
    (5) You must document all your test results and make them available 
to BSEE upon request.
    (6) If you have any indication of a failed negative pressure test, 
such as, but not limited to, pressure buildup or observed flow, you 
must immediately investigate the cause. If your investigation confirms 
that a failure occurred during the negative pressure test, you must:
    (i) Correct the problem and immediately notify the appropriate 
District Manager; and
    (ii) Submit a description of the corrective action taken and 
receive approval from the appropriate District Manager for the retest.
    (7) You must have two barriers in place, as described in Sec.  
250.420(b)(3), at any time and for any well, prior to performing the 
negative pressure test.
    (8) You must include documentation of the successful negative 
pressure test in the End-of-Operations Report (Form BSEE-0125).


Sec.  250.722  What are the requirements for prolonged operations in a 
well?

    If wellbore operations continue within a casing or liner for more 
than 30 days from the previous pressure test of the well's casing or 
liner, you must:
    (a) Stop operations as soon as practicable, and evaluate the 
effects of the prolonged operations on continued operations and the 
life of the well. At a minimum, you must:
    (1) Evaluate the well casing with a pressure test, caliper tool, or 
imaging tool. On a case-by-case basis, the District Manager may require 
a specific method of evaluation of the effects on the well casing of 
prolonged operations; and
    (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 show the well's integrity is 
above the minimum safety factors, if an imaging tool or caliper is 
used.
    (b) If well integrity has deteriorated to a level below minimum 
safety factors, you must:
    (1) Obtain approval from the District Manager to begin repairs or 
install additional casing. To obtain approval, you must also provide a 
PE certification showing that he or she reviewed and approved the 
proposed changes;
    (2) Repair the casing or run another casing string; and
    (3) Perform a pressure test after the repairs are made or 
additional casing is installed and report the results to the District 
Manager as specified in Sec.  250.721.


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 or lift boat on or jacked-up over a platform 
with producing wells or that has other hydrocarbon flow:
    (a) The movement of rig units and related equipment on and off a 
platform or from well to well on the same platform, including rigging 
up and rigging down, must be conducted in a safe manner;
    (b) You must install an emergency shutdown station for the 
production system near the rig operator's console;
    (c) You must shut-in all producible wells located in the affected 
wellbay below the surface and at the wellhead when:
    (1) You move a rig unit or related equipment on and off a platform. 
This includes rigging up and rigging down activities within 500 feet of 
the affected platform;
    (2) You move or skid a rig unit between wells on a platform; or
    (3) A MODU or lift boat moves within 500 feet of a platform. You 
may resume production once the MODU or lift boat is in place, secured, 
and ready to begin operations.
    (d) All wells in the same well-bay which are capable of producing 
hydrocarbons must be shut-in below the surface with a pump-through-type 
tubing plug and at the surface with a closed master valve prior to 
moving rig units and related equipment, unless otherwise approved by 
the District Manager.
    (1) A closed surface-controlled subsurface safety valve of the 
pump-through-type may be used in lieu of the pump-through-type tubing 
plug provided that the surface control has been locked out of 
operation.
    (2) The well to which a rig unit or related equipment is to be 
moved must be equipped with a back-pressure valve prior to removing the 
tree and installing and testing the BOP system.
    (3) The well from which a rig unit or related equipment is to be 
moved must be equipped with a back pressure valve prior to removing the 
BOP system and installing the production tree.
    (e) Coiled tubing units, snubbing units, or wireline units may be 
moved onto and off of a platform without shutting in wells.


Sec.  250.724  What are the real-time monitoring requirements?

    (a) No later than April 29, 2019, 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 fluid handling system on the rig; 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 onshore, using qualified personnel 
in accordance with a real-time monitoring plan, as provided in 
paragraph (c) of this section. Onshore personnel who monitor real-time 
data must have the capability to contact rig personnel during 
operations. After operations, you must preserve and store these data 
onshore for recordkeeping purposes as required in Sec. Sec.  250.740 
and 250.741. You must provide BSEE with access to your designated real-
time monitoring data onshore upon request. You must include in your APD 
a certification that you have a real-time monitoring plan that meets 
the criteria 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:

[[Page 26026]]

    (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 onshore during operations, how the data will be labeled and 
monitored by qualified onshore personnel, and how it will be stored 
onshore;
    (3) A description of your procedures for providing BSEE access, 
upon request, to your real-time monitoring data including, if 
applicable, the location of any onshore data monitoring or data storage 
facilities;
    (4) The qualifications of the onshore personnel monitoring the 
data;
    (5) Your procedures for, and methods of, communication between rig 
personnel and the onshore monitoring personnel; and
    (6) Actions to be taken if you lose any real-time monitoring 
capabilities or communications between rig and onshore personnel, and a 
protocol for how you will respond to any significant and/or prolonged 
interruption of monitoring or onshore-offshore communications, 
including your protocol for notifying BSEE of any significant and/or 
prolonged interruptions.

Blowout Preventer (BOP) System Requirements


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 taken 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 (excluding casing shear) 
must be capable of closing and sealing the wellbore at all times, 
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) Those 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, with the 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 change 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, Original Equipment Manufacturers (OEM) 
recommendations unless otherwise directed by BSEE, and recognized 
engineering practices. The training and qualification of repair and 
maintenance personnel must meet or exceed any OEM training 
recommendations unless otherwise directed by BSEE.
    (c) You must follow the failure reporting procedures contained in 
API Standard 53, ANSI/API Spec. 6A, and ANSI/API Spec 16A (all 
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, 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 performed within 120 days of the failure to determine the cause of 
the failure. You must also ensure that the results and any corrective 
action are documented. If the investigation and analysis are performed 
by an entity other than the manufacturer, you must ensure that the 
Chief, Office of Offshore Regulatory Programs and the manufacturer 
receive a copy of the analysis report.
    (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, Office of Offshore Regulatory 
Programs.
    (4) You must send the reports required in this paragraph to: Chief, 
Office of Offshore Regulatory Programs; Bureau of Safety and 
Environmental Enforcement; 45600 Woodland Road, Sterling, VA 20166.
    (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 
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 17011.
    (1) BSEE may consider accepting equipment manufactured under 
quality assurance programs other than API Spec. Q1, provided you submit 
a request to the Chief, Office of Offshore Regulatory Programs for 
approval, containing relevant information about the alternative 
program.
    (2) You must submit this request to the Chief, Office of Offshore 
Regulatory Programs; Bureau of Safety and Environmental Enforcement; 
45600 Woodland Road, Sterling, Virginia 20166.


Sec.  250.731  What information must I submit for BOP systems and 
system components?

    For any operation that requires the use of a BOP, you must include 
the information listed in this section with your applicable APD, APM, 
or other submittal. You are required to submit this information only 
once for each well, unless the information changes from what you 
provided in an earlier approved submission or you have moved off 
location from the well. After you have submitted this information for a 
particular well, subsequent APMs or other submittals for the well 
should reference the approved submittal containing the information 
required by this section and confirm that the information remains 
accurate and that you have not moved off location from that well. If 
the information changes or you have moved off location from the well, 
you must submit updated information in your next submission.

[[Page 26027]]



------------------------------------------------------------------------
         You must submit:                        Including:
------------------------------------------------------------------------
(a) A complete description of the   (1) Pressure ratings of BOP
 BOP system and system components,   equipment;
                                    (2) Proposed BOP test pressures (for
                                     subsea BOPs, include both surface
                                     and corresponding subsea
                                     pressures);
                                    (3) Rated capacities for liquid and
                                     gas for the fluid-gas separator
                                     system;
                                    (4) Control fluid volumes needed to
                                     close, seal, and open each
                                     component;
                                    (5) Control system pressure and
                                     regulator settings needed to
                                     achieve an effective seal of each
                                     ram BOP under MASP as defined for
                                     the operation;
                                    (6) Number and volume of accumulator
                                     bottles and bottle banks (for
                                     subsea BOP, include both surface
                                     and subsea bottles);
                                    (7) Accumulator pre-charge
                                     calculations (for subsea BOP,
                                     include both surface and subsea
                                     calculations);
                                    (8) All locking devices; and
                                    (9) Control fluid volume
                                     calculations for the accumulator
                                     system (for a subsea BOP system,
                                     include both the surface and subsea
                                     volumes).
(b) Schematic drawings,...........  (1) The inside diameter of the BOP
                                     stack;
                                    (2) Number and type of preventers
                                     (including blade type for shear
                                     ram(s));
                                    (3) All locking devices;
                                    (4) Size range for variable bore
                                     ram(s);
                                    (5) Size of fixed ram(s);
                                    (6) All control systems with all
                                     alarms and set points labeled,
                                     including pods;
                                    (7) Location and size of choke and
                                     kill lines (and gas bleed line(s)
                                     for subsea BOP);
                                    (8) Associated valves of the BOP
                                     system;
                                    (9) Control station locations; and
                                    (10) A cross-section of the riser
                                     for a subsea BOP system showing
                                     number, size, and labeling of all
                                     control, supply, choke, and kill
                                     lines down to the BOP.
(c) Certification by a BSEE-        Verification that:
 approved verification              (1) Test data demonstrate the shear
 organization (BAVO),                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; and
                                    (3) The accumulator system has
                                     sufficient fluid to operate the BOP
                                     system without assistance from the
                                     charging system.
(d) Additional certification by a   Verification that:
 BAVO, if you use a subsea BOP, a   (1) The BOP stack is designed and
 BOP in an HPHT environment as       suitable for the specific equipment
 defined in Sec.   250.807, or a     on the rig and for the specific
 surface BOP on a floating           well design;
 facility,                          (2) The BOP stack has not been
                                     compromised or damaged from
                                     previous service; and
                                    (3) The BOP stack will operate in
                                     the conditions in which it will be
                                     used.
(e) If you are using a subsea BOP,  A listing of the functions with
 descriptions of autoshear,          their sequences and timing.
 deadman, and emergency disconnect
 sequence (EDS) systems,
(f) Certification stating that the  ....................................
 MIA Report required in Sec.
 250.732(d) has been submitted
 within the past 12 months for a
 subsea BOP, a BOP being used in
 an HPHT environment as defined in
 Sec.   250.807, or a surface BOP
 on a floating facility.
------------------------------------------------------------------------

Sec.  250.732  What are the BSEE-approved verification organization 
(BAVO) requirements for BOP systems and system components?

    (a) BSEE will maintain a list of BSEE-approved verification 
organizations (BAVOs) on its public website that you must use to 
satisfy any provision in this subpart that requires a BAVO 
certification, verification, report, or review. You must comply with 
all requirements in this subpart for BAVO certification, verification, 
or reporting no later than 1 year from the date BSEE publishes a list 
of BAVOs.
    (1) Until such time as you use a BAVO to perform the actions that 
this subpart requires to be performed by a BAVO, but not after 1 year 
from the date BSEE publishes a list of BAVOs, you must use an 
independent third-party meeting the criteria specified in paragraph 
(a)(2) of this section to prepare certifications, verifications, and 
reports as required by Sec. Sec.  250.731(c) and (d), 250.732 (b) and 
(c), 250.734(b)(1), 250.738(b)(4), and 250.739(b).
    (2) 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 certifications, 
verifications, and reports required under paragraph (a)(1) of this 
section.
    (3) For an organization to become a BAVO, it must submit the 
following information to the Chief, Office of Offshore Regulatory 
Programs; Bureau of Safety and Environmental Enforcement; 45600 
Woodland Road, Sterling, Virginia, 20166, for BSEE review and approval:
    (i) Previous experience in verification or in the design, 
fabrication, installation, repair, or major modification of BOPs and 
related systems and equipment;
    (ii) Technical capabilities;
    (iii) Size and type of organization;
    (iv) In-house availability of, or access to, appropriate 
technology. This should include computer programs, hardware, and 
testing materials and equipment;
    (v) Ability to perform the verification functions for projects 
considering current commitments;
    (vi) Previous experience with BSEE requirements and procedures; and
    (vii) Any additional information that may be relevant to BSEE's 
review.
    (b) Prior to beginning any operation requiring the use of any BOP, 
you must submit verification by a BAVO and supporting documentation as 
required by this paragraph to the appropriate

[[Page 26028]]

District Manager and Regional Supervisor.

------------------------------------------------------------------------
 You must submit verification and
     documentation related to:                      That:
------------------------------------------------------------------------
(1) Shear testing,................  (i) Demonstrates that the BOP will
                                     shear the drill pipe and any
                                     electric-, wire-, and slick-line to
                                     be used in the well, no later than
                                     April 30, 2018;
                                    (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 drill
                                     pipe;
                                    (iv) Ensures testing was performed
                                     on the outermost edges of the
                                     shearing blades of the shear ram
                                     positioning mechanism as required
                                     in Sec.   250.734(a)(16);
                                    (v) Demonstrates the shearing
                                     capacity of the BOP equipment to
                                     the physical and mechanical
                                     properties of the drill pipe; and
                                    (vi) Includes relevant testing
                                     results.
(2) Pressure integrity testing,     (i) Shows that testing is conducted
 and.                                immediately after the shearing
                                     tests;
                                    (ii) Demonstrates that the equipment
                                     will seal at the rated working
                                     pressures (RWP) of the BOP for 30
                                     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.
------------------------------------------------------------------------

    (c) For wells in an HPHT environment, as defined by Sec.  
250.807(b), you must submit verification by a BAVO that the 
verification organization conducted a comprehensive review of the BOP 
system and related equipment you propose to use. You must provide the 
BAVO 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              .................................
 verification organization 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          reasonable potential modes of
 overall system have been proven in a   failure; and
 testing process that demonstrates     (ii) Evaluation of the design
 the performance and reliability of     verification tests. The design
 the 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              For the quality control and
 fabrication, manufacture, and          assurance mechanisms, complete
 assembly of individual components      material and quality controls
 and the overall system uses            over all contractors,
 recognized engineering practices and   subcontractors, distributors,
 quality control and assurance          and suppliers at every stage in
 mechanisms.                            the fabrication, manufacture,
                                        and assembly process.
------------------------------------------------------------------------

    (d) Once every 12 months, you must submit a Mechanical Integrity 
Assessment Report for a subsea BOP, a BOP being used in an HPHT 
environment as defined in Sec.  250.807, or a surface BOP on a floating 
facility. This report must be completed by a BAVO. You must submit this 
report to the Chief, Office of Offshore Regulatory Programs; Bureau of 
Safety and Environmental Enforcement; 45600 Woodland Road, Sterling, VA 
20166. This report must include:
    (1) A determination that the BOP stack and system meets or exceeds 
all BSEE regulatory requirements, industry standards incorporated into 
this subpart, and recognized engineering practices.
    (2) Verification that complete documentation of the equipment's 
service life exists that demonstrates that the BOP stack has not been 
compromised or damaged during previous service.
    (3) A description of all inspection, repair and maintenance records 
reviewed, and verification that all repairs, replacement parts, and 
maintenance meet regulatory requirements, recognized engineering 
practices, and OEM specifications.
    (4) A description of records reviewed related to any modifications 
to the equipment and verification that any such changes do not 
adversely affect the equipment's capability to perform as designed or 
invalidate test results.
    (5) A description of the Safety and Environmental Management 
Systems (SEMS) plans reviewed related to assurance of quality and 
mechanical integrity of critical equipment and verification that the 
plans are comprehensive and fully implemented.
    (6) Verification that the qualification and training of inspection, 
repair, and maintenance personnel for the BOP

[[Page 26029]]

systems meet recognized engineering practices and any applicable OEM 
requirements.
    (7) A description of all records reviewed covering OEM safety 
alerts, all failure reports, and verification that any design or 
maintenance issues have been completely identified and corrected.
    (8) A comprehensive assessment of the overall system and 
verification that all components (including mechanical, hydraulic, 
electrical, and software) are compatible.
    (9) Verification that documentation exists concerning the 
traceability of the fabrication, repair, and maintenance of all 
critical components.
    (10) Verification of use of a formal maintenance tracking system to 
ensure that corrective maintenance and scheduled maintenance is 
implemented in a timely manner.
    (11) Identification of gaps or deficiencies related to inspection 
and maintenance procedures and documentation, documentation of any 
deferred maintenance, and verification of the completion of corrective 
action plans.
    (12) Verification that any inspection, maintenance, or repair work 
meets the manufacturer's design and material specifications.
    (13) Verification of written procedures for operating the BOP stack 
and Lower Marine Riser Package (LMRP) (including proper techniques to 
prevent accidental disconnection of these components) and minimum 
knowledge requirements for personnel authorized to operate and maintain 
BOP components.
    (14) Recommendations, if any, for how to improve the fabrication, 
installation, operation, maintenance, inspection, and repair of the 
equipment.
    (e) You must make all documentation that supports the requirements 
of this section available to BSEE upon request.


Sec.  250.733  What are the requirements for a surface BOP stack?

    (a) When you drill or conduct operations with a surface BOP stack, 
you must install the BOP system before drilling or conducting 
operations to deepen the well below the surface casing and after the 
well is deepened below the surface casing point. The surface BOP stack 
must include at least four remote-controlled, hydraulically operated 
BOPs, consisting of one annular BOP, one BOP equipped with blind shear 
rams, and two BOPs equipped with pipe rams.
    (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 provided that the capability to 
shear tubing with exterior control lines is not required prior to April 
30, 2018, and any electric-, wire-, and slick-line that is in the hole 
and sealing the wellbore after shearing. 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.
    (2) The two BOPs equipped with pipe rams must be capable of closing 
and sealing on the tubular body of any drill pipe, workstring, and 
tubing under MASP, as defined for the operation, except for tubing with 
exterior control lines and flat packs, a bottom hole assembly that 
includes heavy-weight pipe or collars, and bottom-hole tools.
    (b) If you plan to use a surface BOP on a floating production 
facility you must:
    (1) For BOPs installed after April 29, 2019, follow the BOP 
requirements in Sec.  250.734(a)(1).
    (2) For risers installed after July 28, 2016, use a dual bore riser 
configuration before drilling or operating in any hole section or 
interval where hydrocarbons are, or may be, exposed to the well. The 
dual bore riser must meet the design requirements of API RP 2RD (as 
incorporated by reference in Sec.  250.198), including appropriate 
design for the maximum anticipated operating and environmental 
conditions.
    (i) For a dual bore riser configuration, the annulus between the 
risers must be monitored for pressure during operations. You must 
describe in your APD or APM your annulus monitoring plan and how you 
will secure the well in the event a leak is detected.
    (ii) The inner riser for a dual riser configuration is subject to 
the requirements at Sec.  250.721 for testing the casing or liner.
    (c) You must install separate side outlets on the BOP stack for the 
kill and choke lines. If your stack does not have side outlets, you 
must install a drilling spool with side outlets. The outlet valves must 
hold pressure from both directions.
    (d) You must install a choke and a kill line on the BOP stack. You 
must equip each line with two full-bore, full-opening valves, one of 
which must be remote-controlled. On the kill line, you may install a 
check valve and a manual valve instead of the remote-controlled valve. 
To use this configuration, both manual valves must be readily 
accessible and you must install the check valve between the manual 
valves and the pump.


Sec.  250.734  What are the requirements for a subsea BOP system?

    (a) When you drill or conduct operations with a subsea BOP system, 
you must install the BOP system before drilling to deepen the well 
below the surface casing or before conducting operations if the well is 
already deepened beyond the surface casing point. The District Manager 
may require you to install a subsea BOP system before drilling or 
conducting operations below the conductor casing if proposed casing 
setting depths or local geology indicate the need. The following table 
outlines your requirements.

 
------------------------------------------------------------------------
 When operating with a subsea BOP system,
                 you must:                    Additional requirements:
------------------------------------------------------------------------
(1) Have at least five remote-controlled,   You must have at least one
 hydraulically operated BOPs;                annular BOP, two BOPs
                                             equipped with pipe rams,
                                             and two BOPs equipped with
                                             shear rams. For the dual
                                             ram requirement, you must
                                             comply with this
                                             requirement no later than
                                             April 29, 2021.
                                            (i) Both BOPs equipped with
                                             pipe rams must be capable
                                             of closing and sealing on
                                             the tubular body of any
                                             drill pipe, workstring, and
                                             tubing under MASP, as
                                             defined for the operation,
                                             except tubing with exterior
                                             control lines and flat
                                             packs, a bottom hole
                                             assembly that includes
                                             heavy-weight pipe or
                                             collars, and bottom-hole
                                             tools.

[[Page 26030]]

 
                                            (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 provided that the
                                             capability to shear tubing
                                             with exterior control lines
                                             is not required prior to
                                             April 30, 2018, appropriate
                                             area for the liner or
                                             casing landing string,
                                             shear sub on subsea test
                                             tree, and any electric-,
                                             wire-, slick-line in the
                                             hole no later than April
                                             30, 2018; 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).
(2) Have an operable redundant pod control
 system to ensure proper and independent
 operation of the BOP system;
(3) Have the accumulator capacity located   The accumulator capacity
 subsea, to provide fast closure of the      must:
 BOP components and to operate all          (i) Operate each required
 critical functions in case of a loss of     shear ram, ram locks, one
 the power fluid connection to the           pipe ram, and disconnect
 surface;                                    the LMRP.
                                            (ii) Have the capability of
                                             delivering fluid to each
                                             ROV function i.e., flying
                                             leads.
                                            (iii) No later than April
                                             29, 2021, have bottles for
                                             the autoshear, and deadman
                                             that are dedicated to, but
                                             may be shared between,
                                             those functions.
                                            (iv) Perform under MASP
                                             conditions as defined for
                                             the operation.
(4) Have a subsea BOP stack equipped with   The ROV must be capable of
 remotely operated vehicle (ROV)             opening and closing each
 intervention capability;                    shear ram, ram locks, one
                                             pipe ram, and LMRP
                                             disconnect under MASP
                                             conditions as defined for
                                             the operation. The ROV
                                             panels on the BOP and LMRP
                                             must be compliant with API
                                             RP 17H (as incorporated by
                                             reference in Sec.
                                             250.198).
(5) Maintain an ROV and have a trained ROV  The crew must be trained in
 crew on each rig unit on a continuous       the operation of the ROV.
 basis once BOP deployment has been          The training must include
 initiated from the rig until recovered to   simulator training on
 the surface. The ROV crew must examine      stabbing into an ROV
 all ROV-related well-control equipment      intervention panel on a
 (both surface and subsea) to ensure that    subsea BOP stack. The ROV
 it is properly maintained and capable of    crew must be in
 carrying out appropriate tasks during       communication with
 emergency operations;                       designated rig personnel
                                             who are knowledgeable about
                                             the BOP's capabilities.
(6) Provide autoshear, deadman, and EDS     (i) Autoshear system means a
 systems for dynamically positioned rigs;    safety system that is
 provide autoshear and deadman systems for   designed to automatically
 moored rigs;                                shut-in the wellbore in the
                                             event of a disconnect of
                                             the LMRP. This is
                                             considered a rapid
                                             discharge system.
                                            (ii) Deadman system means a
                                             safety system that is
                                             designed to automatically
                                             shut-in the wellbore in the
                                             event of a simultaneous
                                             absence of hydraulic supply
                                             and signal transmission
                                             capacity in both subsea
                                             control pods. This is
                                             considered a rapid
                                             discharge system.
                                            (iii) Emergency Disconnect
                                             Sequence (EDS) system means
                                             a safety system that is
                                             designed to be manually
                                             activated to shut-in the
                                             wellbore and disconnect the
                                             LMRP in the event of an
                                             emergency situation. This
                                             is considered a rapid
                                             discharge system.
                                            (iv) Each emergency function
                                             must close at a minimum,
                                             two shear rams in sequence
                                             and be capable of
                                             performing its expected
                                             shearing and sealing action
                                             under MASP conditions as
                                             defined for the operation.
                                            (v) Your sequencing must
                                             allow a sufficient delay
                                             for closing the upper shear
                                             ram after beginning closure
                                             of the lower shear ram to
                                             provide for maximum sealing
                                             efficiency.
                                            (vi) The control system for
                                             the emergency functions
                                             must be a fail-safe design
                                             once activated.
(7) Demonstrate that any acoustic control   If you choose to use an
 system will function in the proposed        acoustic control system in
 environment and conditions;                 addition to the autoshear,
                                             deadman, and EDS
                                             requirements, you must
                                             demonstrate to the District
                                             Manager, as part of the
                                             information submitted under
                                             Sec.   250.731, that the
                                             acoustic control system
                                             will function in the
                                             proposed environment and
                                             conditions. The District
                                             Manager may require
                                             additional information as
                                             appropriate to clarify or
                                             evaluate the acoustic
                                             control system information
                                             provided in your
                                             demonstration.
(8) Have operational or physical            You must incorporate enable
 barrier(s) on BOP control panels to         buttons, or a similar
 prevent accidental disconnect functions;    feature, on control panels
                                             to ensure two-handed
                                             operation for all critical
                                             functions.
(9) Clearly label all control panels for    Label other BOP control
 the subsea BOP system;                      panels, such as hydraulic
                                             control panel.
(10) Develop and use a management system    The management system must
 for operating the BOP system, including     include written procedures
 the prevention of accidental or unplanned   for operating the BOP stack
 disconnects of the system;                  and LMRP (including proper
                                             techniques to prevent
                                             accidental disconnection of
                                             these components) and
                                             minimum knowledge
                                             requirements for personnel
                                             authorized to operate and
                                             maintain BOP components.

[[Page 26031]]

 
(11) Establish minimum requirements for     Personnel must have:
 personnel authorized to operate critical   (i) Training in deepwater
 BOP equipment;                              well-control theory and
                                             practice according to the
                                             requirements of Subparts O
                                             and S; and
                                            (ii) A comprehensive
                                             knowledge of BOP hardware
                                             and control systems.
(12) Before removing the marine riser,      You must maintain sufficient
 displace the fluid in the riser with        hydrostatic pressure or
 seawater;                                   take other suitable
                                             precautions to compensate
                                             for the reduction in
                                             pressure and to maintain a
                                             safe and controlled well
                                             condition. You must follow
                                             the requirements of Sec.
                                             250.720(b).
(13) Install the BOP stack in a well        Your well cellar must be
 cellar when in an ice-scour area;           deep enough to ensure that
                                             the top of the stack is
                                             below the deepest probable
                                             ice-scour depth.
(14) Install at least two side outlets for  (i) If your stack does not
 a choke line and two side outlets for a     have side outlets, you must
 kill line;                                  install a drilling spool
                                             with side outlets.
                                            (ii) Each side outlet must
                                             have two full-bore, full-
                                             opening valves.
                                            (iii) The valves must hold
                                             pressure from both
                                             directions and must be
                                             remote-controlled.
                                            iv) You must install a side
                                             outlet below the lowest
                                             sealing shear ram. You may
                                             have a pipe ram or rams
                                             between the shearing ram
                                             and side outlet.
(15) Install a gas bleed line with two      (i) The valves must hold
 valves for the annular preventer no later   pressure from both
 than April 30, 2018;                        directions;
                                            (ii) If you have dual
                                             annulars, you must install
                                             the gas bleed line below
                                             the upper annular.
(16) Use a BOP system that has the          (i) A mechanism coupled with
 following mechanisms and capabilities;      each shear ram to position
                                             the entire pipe, completely
                                             within the area of the
                                             shearing blade and ensure
                                             shearing will occur any
                                             time the shear rams are
                                             activated. This mechanism
                                             cannot be another ram BOP
                                             or annular preventer, but
                                             you may use those during a
                                             planned shear. You must
                                             install this mechanism no
                                             later than May 1, 2023;
                                            (ii) The ability to mitigate
                                             compression of the pipe
                                             stub between the shearing
                                             rams when both shear rams
                                             are closed;
                                            (iii) 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 operations are suspended 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 verification report from a BAVO 
documenting the repairs and that the BOP is fit for service;
    (2) Upon relatch of the BOP, perform an initial subsea BOP test in 
accordance with Sec.  250.737(d)(4), including deadman. 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; and
    (3) Receive approval from the District Manager.
    (c) If you plan to drill a new well with a subsea BOP, you do not 
need to submit with your APD the verifications required by this subpart 
for the open water drilling operation. Before drilling out the surface 
casing, you must submit for approval a revised APD, including the 
verifications required in this subpart.


Sec.  250.735  What associated systems and related equipment must all 
BOP systems include?

    All BOP systems must include the following associated systems and 
related equipment:
    (a) An accumulator system (as specified in API Standard 53, and 
incorporated by reference in Sec.  250.198) that provides the volume of 
fluid capacity (as specified in API Standard 53, Annex C) necessary to 
close and hold closed all BOP components against MASP. The system must 
operate under MASP conditions as defined for the operation. You must be 
able to operate the BOP functions as defined in API Standard 53, 
without assistance from a charging system, and still have a minimum 
pressure of 200 psi remaining on the bottles above the pre-charge 
pressure. 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;
    (b) An automatic backup to the primary accumulator-charging system. 
The power source must be independent from the power source for the 
primary accumulator-charging system. The independent power source must 
possess sufficient capability to close and hold closed all BOP 
components under MASP conditions as defined for the operation;
    (c) At least two full BOP control stations. One station must be on 
the rig floor. You must locate the other station in a readily 
accessible location away from the rig floor;
    (d) The choke line(s) installed above the bottom well-control ram;
    (e) The kill line must be installed beneath at least one well-
control ram, and may be installed below the bottom ram;
    (f) A fill-up line above the uppermost BOP;
    (g) Locking devices for all BOP sealing rams (i.e., blind shear 
rams, pipe rams and variable bore rams), as follows:
    (1) For subsea BOPs, hydraulic locking devices must be installed on 
all sealing rams;
    (2) For surface BOPs:
    (i) Remotely-operated locking devices must be installed on blind 
shear rams no later than April 29, 2019;
    (ii) Manual or remotely-operated locking devices must be installed 
on pipe rams and variable bore rams; and

[[Page 26032]]

    (h) A wellhead assembly with a RWP that exceeds the maximum 
anticipated wellhead pressure.


Sec.  250.736  What are the requirements for choke manifolds, kelly-
type valves inside BOPs, and drill string safety valves?

    (a) Your BOP system must include a choke manifold that is suitable 
for the anticipated surface pressures, anticipated methods of well 
control, the surrounding environment, and the corrosiveness, volume, 
and abrasiveness of drilling fluids and well fluids that you may 
encounter.
    (b) Choke manifold components must have a RWP at least as great as 
the RWP of the ram BOPs. If your choke manifold has buffer tanks 
downstream of choke assemblies, you must install isolation valves on 
any bleed lines.
    (c) Valves, pipes, flexible steel hoses, and other fittings 
upstream of the choke manifold must have a RWP at least as great as the 
RWP of the ram BOPs.
    (d) You must use the following BOP equipment with a RWP and 
temperature of at least as great as the working pressure and 
temperature of the ram BOP during all operations:
    (1) The applicable kelly-type valves as described in API Standard 
53 (incorporated by reference in Sec.  250.198);
    (2) On a top-drive system equipped with a remote-controlled valve, 
a strippable kelly-type valve must be installed below the remote-
controlled valve;
    (3) An inside BOP in the open position located on the rig floor. 
You must be able to install an inside BOP for each size connection in 
the pipe;
    (4) A drill string safety valve in the open position located on the 
rig floor. You must have a drill-string safety valve available for each 
size connection in the pipe;
    (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;
    (6) All required manual and remote- controlled kelly-type valves, 
drill-string safety valves, and comparable-type valves (i.e., kelly-
type valve in a top-drive system) that are essentially full opening; 
and
    (7) A wrench to fit each manual valve. Each wrench must be readily 
accessible to the drilling crew.


Sec.  250.737  What are the BOP system testing requirements?

    Your BOP system (this includes the choke manifold, kelly-type 
valves, inside BOP, and drill string safety valve) must meet the 
following testing requirements:
    (a) Pressure test frequency. You must pressure test your BOP 
system:
    (1) When installed;
    (2) Before 14 days have elapsed since your last BOP pressure test, 
or 30 days since your last blind shear ram BOP pressure test. You must 
begin to test your BOP system before midnight on the 14th day (or 30th 
day for your blind shear rams) following the conclusion of the previous 
test;
    (3) Before drilling out each string of casing or a liner. You may 
omit this pressure test requirement if you did not remove the BOP stack 
to run the casing string or liner, the required BOP test pressures for 
the next section of the hole are not greater than the test pressures 
for the previous BOP test, and the time elapsed between tests has not 
exceeded 14 days (or 30 days for blind shear rams). You must indicate 
in your APD which casing strings and liners meet these criteria;
    (4) The District Manager may require more frequent testing if 
conditions or your BOP performance warrant.
    (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. 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 . . .
------------------------------------------------------------------------
(1) Low-pressure test.............  All low-pressure tests must be
                                     between 250 and 350 psi. Any
                                     initial pressure above 350 psi must
                                     be bled back to a pressure between
                                     250 and 350 psi before starting the
                                     test. If the initial pressure
                                     exceeds 500 psi, you must bleed
                                     back to zero and reinitiate the
                                     test.
(2) High-pressure test for blind    The high-pressure test must equal
 shear ram-type BOPs, ram-type       the RWP of the equipment or be 500
 BOPs, the choke manifold, outside   psi greater than your calculated
 of all choke and kill side outlet   MASP, as defined for the operation
 valves (and annular gas bleed       for the applicable section of hole.
 valves for subsea BOP), inside of   Before you may test BOP equipment
 all choke and kill side outlet      to the MASP plus 500 psi, the
 valves below uppermost ram, and     District Manager must have approved
 other BOP components.               those test pressures in your APD.
(3) High-pressure test for annular- The high pressure test must equal 70
 type BOPs, inside of choke or       percent of the RWP of the equipment
 kill valves (and annular gas        or be 500 psi greater than your
 bleed valves for subsea BOP)        calculated MASP, as defined for the
 above the uppermost ram BOP.        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.
------------------------------------------------------------------------

    (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. 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) Additional test requirements. You must meet the following 
additional BOP testing requirements:

------------------------------------------------------------------------
          You must . . .                Additional requirements . . .
------------------------------------------------------------------------
(1) Follow the testing              If there is a conflict between API
 requirements of API Standard 53     Standard 53, testing requirements
 (as incorporated in Sec.            and this section, you must follow
 250.198).                           the requirements of this section.

[[Page 26033]]

 
(2) Use water to test a surface     (i) You must submit test procedures
 BOP system on the initial test.     with your APD or APM for District
 You may use drilling/completion/    Manager approval.
 workover fluids to conduct         (ii) Contact the District Manager at
 subsequent tests of a surface BOP   least 72 hours prior to beginning
 system.                             the initial test to allow BSEE
                                     representative(s) to witness
                                     testing. If BSEE representative(s)
                                     are unable to witness testing, you
                                     must provide the initial test
                                     results to the appropriate District
                                     Manager within 72 hours after
                                     completion of the tests.
(3) Stump test a subsea BOP system  (i) You must use water to conduct
 before installation.                this test. You may use drilling/
                                     completion/workover fluids to
                                     conduct subsequent tests of a
                                     subsea BOP system.
                                    (ii) You must submit test procedures
                                     with your APD or APM for District
                                     Manager approval
                                    (iii) Contact the District Manager
                                     at least 72 hours prior to
                                     beginning the stump test to allow
                                     BSEE representative(s) to witness
                                     testing. If BSEE representative(s)
                                     are unable to witness testing, you
                                     must provide the test results to
                                     the appropriate District Manager
                                     within 72 hours after completion of
                                     the tests.
                                    (iv) You must test and 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.
(4) Perform an initial subsea BOP   (i) You must perform the initial
 test.                               subsea BOP test on the seafloor
                                     within 30 days of the stump test.
                                    (ii) You must submit test procedures
                                     with your APD or APM for District
                                     Manager approval.
                                    (iii) You must pressure test well-
                                     control rams according to
                                     paragraphs (b) and (c) of this
                                     section.
                                    (iv) You must notify the District
                                     Manager at least 72 hours prior to
                                     beginning the initial subsea test
                                     for the BOP system to allow BSEE
                                     representative(s) to witness
                                     testing.
                                    (v) You must test and verify closure
                                     of at least one set of rams during
                                     the initial subsea test through a
                                     ROV hot stab.
                                    (vi) You must pressure test the
                                     selected rams according to
                                     paragraphs (b) and (c) of this
                                     section.
(5) Alternate testing pods between  (i) For two complete BOP control
 control stations.                   stations:
                                    (A) Designate a primary and
                                     secondary station, and both
                                     stations must be function-tested
                                     weekly;
                                    (B) The control station used for the
                                     pressure test must be alternated
                                     between pressure tests; and
                                    (C) For a subsea BOP, the pods must
                                     be rotated between control stations
                                     during weekly function testing and
                                     14 day pressure testing.
                                    (ii) Remote panels where all BOP
                                     functions are not included (e.g.,
                                     life boat panels) must be function-
                                     tested upon the initial BOP tests
                                     and monthly thereafter.
(6) Pressure test variable bore-
 pipe ram BOPs against pipe sizes
 according to API Standard 53,
 excluding the bottom hole
 assembly that includes heavy-
 weight pipe or collars and bottom-
 hole tools.
(7) Pressure test annular type
 BOPs against pipe sizes according
 to API Standard 53.
(8) Pressure test affected BOP
 components following the
 disconnection or repair of any
 well-pressure containment seal in
 the wellhead or BOP stack
 assembly.
(9) Function test annular and pipe/
 variable bore ram BOPs every 7
 days between pressure tests.
(10) Function test shear ram(s)
 BOPs every 14 days.
(11) Actuate safety valves
 assembled with proper casing
 connections before running casing.

[[Page 26034]]

 
(12) Function test autoshear/       (i) You must submit test procedures
 deadman, and EDS systems            with your APD or APM for District
 separately on your subsea BOP       Manager approval. The procedures
 stack during the stump test. The    for these function tests must
 District Manager may require        include the schematics of the
 additional testing of the           actual controls and circuitry of
 emergency systems. You must also    the system that will be used during
 test the deadman system and         an actual autoshear or deadman
 verify closure of the shearing      event.
 rams during the initial test on    (ii) The procedures must also
 the seafloor.                       include the actions and sequence of
                                     events that take place on the
                                     approved schematics of the BOP
                                     control system and describe
                                     specifically how the ROV will be
                                     utilized during this operation.
                                    (iii) When you conduct the initial
                                     deadman system test on the
                                     seafloor, you must ensure the well
                                     is secure and, if hydrocarbons have
                                     been present, appropriate barriers
                                     are in place to isolate
                                     hydrocarbons from the wellhead. You
                                     must also have an ROV on bottom
                                     during the test.
                                    (iv) The testing of the deadman
                                     system on the seafloor must
                                     indicate the discharge pressure of
                                     the subsea accumulator system
                                     throughout the test.
                                    (v) For the function test of the
                                     deadman system during the initial
                                     test on the seafloor, you must have
                                     the ability to quickly disconnect
                                     the LMRP should the rig experience
                                     a loss of station-keeping event.
                                     You must include your quick-
                                     disconnect procedures with your
                                     deadman test procedures.
                                    (vi) You must pressure test the
                                     blind shear ram(s) according to
                                     paragraphs (b) and (c) of this
                                     section.
                                    (vii) If a casing shear ram is
                                     installed, you must describe how
                                     you will verify closure of the ram.
                                    (viii) You must document all your
                                     test results and make them
                                     available to BSEE upon request.
------------------------------------------------------------------------

    (e) Prior to conducting any shear ram tests in which you will shear 
pipe, you must notify the District Manager at least 72 hours in 
advance, to ensure that a BSEE representative will have access to the 
location to witness any testing.


Sec.  250.738  What must I do in certain situations involving BOP 
equipment or systems?

    The table in this section describes actions that you must take when 
certain situations occur with BOP systems.

------------------------------------------------------------------------
    If you encounter the following
              situation:                      Then you must . . .
------------------------------------------------------------------------
(a) BOP equipment does not hold the    Correct the problem and retest
 required pressure during a test;       the affected equipment. You must
                                        report any problems or
                                        irregularities, including any
                                        leaks, on the daily report as
                                        required in Sec.   250.746.
(b) Need to repair, replace, or        (1) First place the well in a
 reconfigure a surface or subsea BOP    safe, controlled condition as
 system;                                approved by the District Manager
                                        (e.g., before drilling out a
                                        casing shoe or after setting a
                                        cement plug, bridge plug, or a
                                        packer).
                                       (2) Any repair or replacement
                                        parts must be manufactured under
                                        a quality assurance program and
                                        must meet or exceed the
                                        performance of the original part
                                        produced by the OEM.
                                       (3) You must receive approval
                                        from the District Manager prior
                                        to resuming operations with the
                                        new, repaired, or reconfigured
                                        BOP.
                                       (4) You must submit a report from
                                        a BAVO to the District Manager
                                        certifying that the BOP is fit
                                        for service.
(c) Need to postpone a BOP test due    Record the reason for postponing
 to well-control problems such as       the test in the daily report and
 lost circulation, formation fluid      conduct the required BOP test
 influx, or stuck pipe;                 after the first trip out of the
                                        hole.
(d) BOP control station or pod that    Suspend operations until that
 does not function properly;            station or pod is operable. You
                                        must report any problems or
                                        irregularities, including any
                                        leaks, to the District Manager.
(e) Plan to operate with a tapered     Install two or more sets of
 string;                                conventional or variable-bore
                                        pipe rams in the BOP stack to
                                        provide for the following: two
                                        sets of rams must be capable of
                                        sealing around the larger-size
                                        drill string and one set of pipe
                                        rams must be capable of sealing
                                        around the smaller size pipe,
                                        excluding the bottom hole
                                        assembly that includes heavy
                                        weight pipe or collars and
                                        bottom-hole tools.
(f) Plan to install casing rams or     Test the affected connections
 casing shear rams in a surface BOP     before running casing to the RWP
 stack;                                 or MASP plus 500 psi. 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.
(g) Plan to use an annular BOP with a  Demonstrate that your well-
 RWP less than the anticipated          control procedures or the
 surface pressure;                      anticipated well conditions will
                                        not place demands above its RWP
                                        and obtain approval from the
                                        District Manager.
(h) Plan to use a subsea BOP system    Install the BOP stack in a well
 in an ice-scour area;                  cellar. The well cellar must be
                                        deep enough to ensure that the
                                        top of the stack is below the
                                        deepest probable ice-scour
                                        depth.
(i) You activate any shear ram and     Retrieve, physically inspect, and
 pipe or casing is sheared;             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 a BSEE-
                                        approved verification
                                        organization certifying that the
                                        BOP is fit to return to service.
(j) Need to remove the BOP stack;      Have a minimum of two barriers in
                                        place prior to BOP removal. You
                                        must obtain approval from the
                                        District Manager of the two
                                        barriers prior to removal and
                                        the District Manager may require
                                        additional barriers and test(s).

[[Page 26035]]

 
(k) In the event of a deadman or       Place the blind shear ram opening
 autoshear activation, if there is a    function in the block position
 possibility of the blind shear ram     prior to re-establishing power
 opening immediately upon re-           to the stack. Contact the
 establishing power to the BOP stack;   District Manager and receive
                                        approval of procedures for re-
                                        establishing power and functions
                                        prior to latching up the BOP
                                        stack or re-establishing power
                                        to the stack.
(l) If a test ram is to be used;       The wellhead/BOP connection must
                                        be tested to the MASP plus 500
                                        psi for the hole section to
                                        which it is exposed. This can be
                                        done by:
                                       (1) Testing wellhead/BOP
                                        connection to the MASP plus 500
                                        psi for the well upon
                                        installation;
                                       (2) Pressure testing each casing
                                        to the MASP plus 500 psi for the
                                        next hole section; or
                                       (3) Some combination of
                                        paragraphs (l)(1) and (2) of
                                        this section.
(m) Plan to utilize any other well-    Contact the District Manager and
 control equipment (e.g., but not       request approval in your APD or
 limited to, subsea isolation device,   APM. Your request must include a
 subsea accumulator module, or gas      report from a BAVO on the
 handler) that is in addition to the    equipment's design and
 equipment required in 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.
(n) You have pipe/variable bore rams   Indicate in your APD or APM which
 that have no current utility or well-  pipe/variable bore rams meet
 control purposes;                      these criteria and clearly label
                                        them on all BOP control panels.
                                        You do not need to function test
                                        or pressure test pipe/variable
                                        bore rams having no current
                                        utility, and that will not be
                                        used for well-control purposes,
                                        until such time as they are
                                        intended to be used during
                                        operations.
(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.,      that are applicable to those
 pipe/variable bore rams, shear rams,   well-control components. If any
 annular preventers, gas bleed lines,   redundant component fails a
 and choke/kill side outlets or         test, you must submit a report
 lines);                                from a BAVO 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.
(p) Need to position the bottom hole   Ensure that the well is stable
 assembly, including heavy-weight       prior to positioning the bottom
 pipe or collars, and bottom-hole       hole assembly across the BOP.
 tools across the BOP for tripping or   You must have, as part of your
 any other operations.                  well-control plan required by
                                        Sec.   250.710, procedures that
                                        enable the removal of the bottom
                                        hole assembly from across the
                                        BOP in the event of a well-
                                        control or emergency situation
                                        (for dynamically positioned
                                        rigs, your plan must also
                                        include steps for when the EDS
                                        must be activated) before MASP
                                        conditions are reached as
                                        defined for the operation.
------------------------------------------------------------------------

Sec.  250.739  What are the BOP maintenance and inspection 
requirements?

    (a) You must maintain and inspect your BOP system to ensure that 
the equipment functions as designed. The BOP maintenance and 
inspections must meet or exceed any OEM recommendations, recognized 
engineering practices, and industry standards incorporated by reference 
into the regulations of this subpart, including API Standard 53 
(incorporated by reference in Sec.  250.198). You must document how you 
met or exceeded the provisions of API Standard 53, maintain complete 
records to ensure the traceability of BOP stack equipment beginning at 
fabrication, and record the results of your BOP inspections and 
maintenance actions. You must make all records available to BSEE upon 
request.
    (b) A complete breakdown and detailed physical inspection of the 
BOP and every associated system and component must be performed every 5 
years. This complete breakdown and 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. A BAVO is 
required to be present during each inspection and must compile a 
detailed report documenting the inspection, including descriptions of 
any problems and how they were corrected. You must make these reports 
available to BSEE upon request. This complete breakdown and inspection 
must be performed every 5 years from the following applicable dates, 
whichever is later:
    (1) The date the equipment owner accepts delivery of a new build 
drilling rig with a new BOP system;
    (2) The date the new, repaired, or remanufactured equipment is 
initially installed into the system; or
    (3) The date of the last 5 year inspection for the component.
    (c) You must visually inspect your surface BOP system on a daily 
basis. You must visually inspect your subsea BOP system, marine riser, 
and wellhead at least once every 3 days if weather and sea conditions 
permit. You may use cameras to inspect subsea equipment.
    (d) You must ensure that all personnel maintaining, inspecting, or 
repairing BOPs, or critical components of the BOP system, are trained 
in accordance with applicable training requirements in subpart S of 
this part, any applicable OEM criteria, recognized engineering 
practices, and industry standards incorporated by reference in this 
subpart.
    (e) You must make all records available to BSEE upon request. You 
must ensure that the rig unit owner maintains the BOP maintenance, 
inspection, and repair records on the rig unit for 2 years from the 
date the records are created or for a longer period if directed by 
BSEE. You must ensure that all equipment schematics, maintenance, 
inspection, and repair records are located at an onshore location for 
the service life of the equipment.

Records and Reporting


Sec.  250.740  What records must I keep?

    You must keep a daily report consisting of complete, legible, and 
accurate records for each well. You must keep records onsite while well 
operations continue. After completion of operations, you must keep all 
operation and other well records for the time periods shown in Sec.  
250.741 at a location of your choice, except as required in Sec.  
250.746. The records must contain complete information on all of the 
following:
    (a) Well operations, all testing conducted, and any real-time

[[Page 26036]]

monitoring data as required by Sec.  250.724;
    (b) Descriptions of formations penetrated;
    (c) Content and character of oil, gas, water, and other mineral 
deposits in each formation;
    (d) Kind, weight, size, grade, and setting depth of casing;
    (e) All well logs and surveys run in the wellbore;
    (f) Any significant malfunction or problem; and
    (g) All other information required by the District Manager as 
appropriate to ensure compliance with the requirements of this section 
and to enable BSEE to determine that the well operations are consistent 
with conservation of natural resources and protection of safety and the 
environment on the OCS.


Sec.  250.741  How long must I keep records?

    You must keep records for the time periods shown in the following 
table.

------------------------------------------------------------------------
  You must keep records relating to . . .            Until . . .
------------------------------------------------------------------------
(a) Drilling;                               90 days after you complete
                                             operations.
(b) Casing and liner pressure tests,        2 years after the completion
 diverter tests, BOP tests, and real-time    of operations.
 monitoring data;
(c) Completion of a well or of any          You permanently plug and
 workover activity that materially alters    abandon the well or until
 the completion configuration or affects a   you assign the lease and
 hydrocarbon-bearing zone.                   forward the records to the
                                             assignee.
------------------------------------------------------------------------

Sec.  250.742  What well records am I required to submit?

    You must submit to BSEE copies of logs or charts of electrical, 
radioactive, sonic, and other well logging operations; directional and 
vertical well surveys; velocity profiles and surveys; and analysis of 
cores. Each Region will provide specific instructions for submitting 
well logs and surveys.


Sec.  250.743  What are the well activity reporting requirements?

    (a) For operations in the BSEE Gulf of Mexico (GOM) OCS Region, you 
must submit Form BSEE-0133, Well Activity Report (WAR), to the District 
Manager on a weekly basis. The reporting week is defined as beginning 
on Sunday (12 a.m.) and ending on the following Saturday (11:59 p.m.). 
This reporting week corresponds to a week (Sunday through Saturday) on 
a standard calendar. Report any well operations that extend past the 
end of this weekly reporting period on the next weekly report. The 
reporting period for the weekly report is never longer than 7 days, but 
could be less than 7 days for the first reporting period and the last 
reporting period for a particular well operation. Submit each WAR and 
accompanying Form BSEE-0133S, Open Hole Data Report, to the BSEE GOM 
OCS Region no later than close of business on the Friday immediately 
after the closure of the reporting week. The District Manager may 
require more frequent submittal of the WAR on a case-by-case basis.
    (b) For operations in the Pacific or Alaska OCS Regions, you must 
submit Form BSEE-0133, WAR, to the District Manager on a daily basis.
    (c) The WAR must include a description of the operations conducted, 
any abnormal or significant events that affect the permitted operation 
each day within the report from the time you begin operations to the 
time you end operations, any verbal approval received, the well's as-
built drawings, casing, fluid weights, shoe tests, test pressures at 
surface conditions, and any other information concerning well 
activities required by the District Manager. For casing cementing 
operations, indicate type of returns (i.e., full, partial, or none). If 
partial or no returns are observed, you must indicate how you 
determined the top of cement. For each report, indicate the operation 
status for the well at the end of the reporting period. On the final 
WAR, indicate the status of the well (completed, temporarily abandoned, 
permanently abandoned, or drilling suspended) and the date you finished 
such operations.


Sec.  250.744  What are the end of operation reporting requirements?

    (a) Within 30 days after completing operations, except routine 
operations as defined in Sec.  250.601, you must submit Form BSEE-0125, 
End of Operations Report (EOR), to the District Manager. The EOR must 
include: a listing, with top and bottom depths, of all hydrocarbon 
zones and other zones of porosity encountered with any cored intervals; 
details on any drill-stem and formation tests conducted; documentation 
of successful negative pressure testing on wells that use a subsea BOP 
stack or wells with mudline suspension systems; and an updated 
schematic of the full wellbore configuration. The schematic must be 
clearly labeled and show all applicable top and bottom depths, 
locations and sizes of all casings, cut casing or stubs, casing 
perforations, casing rupture discs (indicate if burst or collapse and 
rating), cemented intervals, cement plugs, mechanical plugs, perforated 
zones, completion equipment, production and isolation packers, 
alternate completions, tubing, landing nipples, subsurface safety 
devices, and any other information required by the District Manager 
regarding the end of well operations. The EOR must indicate the status 
of the well (completed, temporarily abandoned, permanently abandoned, 
or drilling suspended) and the date of the well status designation. The 
well status date is subject to the following:
    (1) For surface well operations and riserless subsea operations, 
the operations end date is subject to the discretion of the District 
Manager; and
    (2) For subsea well operations, the operations end date is 
considered to be the date the BOP is disconnected from the wellhead 
unless otherwise specified by the District Manager.
    (b) You must submit public information copies of Form BSEE-0125 
according to Sec.  250.186(b).


Sec.  250.745  What other well records could I be required to submit?

    The District Manager or Regional Supervisor may require you to 
submit copies of any or all of the following well records:
    (a) Well records as specified in Sec.  250.740;
    (b) Paleontological interpretations or reports identifying 
microscopic fossils by depth and/or washed samples of drill cuttings 
that you normally maintain for paleontological determinations. The 
Regional Supervisor may issue a Notice to Lessees that sets forth the 
manner, timeframe, and format for submitting this information;
    (c) Service company reports on cementing, perforating, acidizing, 
testing, or other similar services; or
    (d) Other reports and records of operations.

[[Page 26037]]

Sec.  250.746  What are the recordkeeping requirements for casing, 
liner, and BOP tests, and inspections of BOP systems and marine risers?

    You must record the time, date, and results of all casing and liner 
pressure tests. You must also record pressure tests, actuations, and 
inspections of the BOP system, system components, and marine riser in 
the daily report described in Sec.  250.740. In addition, you must:
    (a) Record test pressures on pressure charts or digital recorders;
    (b) Require your onsite lessee representative, designated rig or 
contractor representative, and pump operator to sign and date the 
pressure charts or digital recordings and daily reports as correct;
    (c) Document on the daily report the sequential order of BOP and 
auxiliary equipment testing and the pressure and duration of each test. 
For subsea BOP systems, you must also record the closing times for 
annular and ram BOPs. You may reference a BOP test plan if it is 
available at the facility;
    (d) Identify on the daily report the control station and pod used 
during the test (identifying the pod does not apply to coiled tubing 
and snubbing units);
    (e) Identify on the daily report any problems or irregularities 
observed during BOP system testing and record actions taken to remedy 
the problems or irregularities. Any leaks associated with the BOP or 
control system during testing must be documented in the WAR. If any 
problems that cannot be resolved promptly are observed during testing, 
operations must be suspended until the District Manager determines that 
you may continue; and
    (f) Retain all records, including pressure charts, daily reports, 
and referenced documents pertaining to tests, actuations, and 
inspections at the rig unit for the duration of the operation. After 
completion of the operation, you must retain all the records listed in 
this section for a period of 2 years at the rig unit. You must also 
retain the records at the lessee's field office nearest the facility or 
at another location available to BSEE. You must make all the records 
available to BSEE upon request.

Subpart P--Sulphur Operations

0
45. Revise Sec.  250.1612 to read as follows:


Sec.  250.1612  Well-control drills.

    Well-control drills must be conducted for each drilling crew in 
accordance with the requirements set forth in Sec.  250.711 or as 
approved by the District Manager.

Subpart Q--Decommissioning Activities

0
46. Amend Sec.  250.1703 by:
0
a. Revising paragraphs (b) and (e);
0
b. Redesignating paragraph (f) as paragraph (g); and
0
c. Adding new paragraph (f).
    The revisions and addition read as follows:


Sec.  250.1703  What are the general requirements for decommissioning?

* * * * *
    (b) Permanently plug all wells. Permanently installed packers and 
bridge plugs must comply with API Spec. 11D1 (as incorporated by 
reference in Sec.  250.198);
* * * * *
    (e) Clear the seafloor of all obstructions created by your lease 
and pipeline right-of-way operations;
    (f) Follow all applicable requirements of subpart G of this part; 
and
* * * * *
0
47. Amend Sec.  250.1704 by:
0
a. Revising paragraph (g);
0
b. Redesignating paragraphs (h) and (i) as paragraphs (i) and (j); and
0
c. Adding new paragraph (h).
    The revision and addition read as follows:


Sec.  250.1704  When must I submit decommissioning applications and 
reports?

* * * * *

----------------------------------------------------------------------------------------------------------------
 Decommissioning applications
         and reports                           When to submit                             Instructions
----------------------------------------------------------------------------------------------------------------
 
                                                  * * * * * * *
(g) Form BSEE-0124,            (1) Before you temporarily abandon or           (i) Include information required
 Application for Permit to      permanently plug a well or zone,                under Sec.  Sec.   250.1712 and
 Modify (APM). The submission                                                   250.1721.
 of your APM must be                                                           (ii) When using a BOP for
 accompanied by payment of                                                      abandonment operations, include
 the service fee listed in                                                      information required under Sec.
 Sec.   250.125;                                                                 250.731.
                               (2) Before you install a subsea protective      Refer to Sec.   250.1722(a).
                                device,
                               (3) Before you remove any casing stub or mud    Refer to Sec.   250.1723.
                                line suspension equipment and any subsea
                                protective device,
(h) Form BSEE-0125, End of     (1) Within 30 days after you complete a         Include information required
 Operations Report (EOR);       protective device trawl test,                   under Sec.   250.1722(d).
                               (2) Within 30 days after you complete site       Include information required
                                clearance verification activities,              under Sec.   250.1743(a).
----------------------------------------------------------------------------------------------------------------
 
                                                  * * * * * * *
----------------------------------------------------------------------------------------------------------------

Sec.  250.1705  [Removed and Reserved]

0
48. Remove and reserve Sec.  250.1705.

0
49. Amend Sec.  250.1706 by:
0
a. Revising the section heading;
0
b. Removing paragraphs (a) through (e); and
0
c. Redesignating paragraphs (f) through (h) as paragraphs (a) through 
(c).
    The revision reads as follows:


Sec.  250.1706  Coiled tubing and snubbing operations.

* * * * *

[[Page 26038]]

Sec. Sec.  250.1707 through 250.1709  [Removed and Reserved]

0
50. Remove and reserve Sec. Sec.  250.1707 through 250.1709.

0
51. In Sec.  250.1715, revise paragraph (a)(3)(iii)(B) to read as 
follows:


Sec.  250.1715  How must I permanently plug a well?

    (a) * * *

                  Permanent Well Plugging Requirements
------------------------------------------------------------------------
           If you have . . .                 Then you must use . . .
------------------------------------------------------------------------
 
                                * * * * *
(3) * * *..............................
                                         (iii) * * *
                                         (B) A casing bridge plug set 50
                                          to 100 feet above the top of
                                          the perforated interval and at
                                          least 50 feet of cement on top
                                          of the bridge plug;
 
                                * * * * *
------------------------------------------------------------------------

* * * * *


Sec.  250.1717  [Removed and Reserved]

0
52. Remove and reserve Sec.  250.1717.


Sec.  250.1721  [Amended]

0
53. Amend Sec.  250.1721 by removing paragraph (g) and redesignating 
paragraph (h) as paragraph (g).

[FR Doc. 2016-08921 Filed 4-28-16; 8:45 am]
BILLING CODE 4310-VH-P