Oil and Gas and Sulphur Operations in the Outer Continental Shelf-Blowout Preventer Systems and Well Control, 21503-21585 [2015-08587]

Agencies

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

[Federal Register Volume 80, Number 74 (Friday, April 17, 2015)]
[Proposed Rules]
[Pages 21503-21585]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2015-08587]



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Vol. 80

Friday,

No. 74

April 17, 2015

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 Sulphur Operations in the Outer Continental Shelf--
Blowout Preventer Systems and Well Control; Proposed Rule

Federal Register / Vol. 80 , No. 74 / Friday, April 17, 2015 / 
Proposed Rules

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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 Sulphur Operations in the Outer Continental 
Shelf--Blowout Preventer Systems and Well Control

AGENCY: Bureau of Safety and Environmental Enforcement (BSEE), 
Interior.

ACTION: Proposed rule.

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SUMMARY: The Bureau of Safety and Environmental Enforcement (BSEE) 
proposes new regulations in order to consolidate equipment and 
operational requirements that are common to other subparts pertaining 
to offshore oil and gas drilling, completions, workovers, and 
decommissioning. This proposed rule would focus, at this time, on 
blowout preventer (BOP) requirements, including incorporation of 
industry standards and revising existing regulations. The proposed rule 
would also include reforms in the areas of well design, well control, 
casing, cementing, real-time well monitoring, and subsea containment. 
The proposed rule would address and implement multiple recommendations 
resulting from various investigations of the Deepwater Horizon 
incident. This proposed rule would 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: Submit comments by June 16, 2015. The BSEE may not consider 
comments received after this date. Submit comments to the Office of 
Management and Budget (OMB) on the information collection burden in 
this proposed rule by May 18, 2015. This does not affect the deadline 
for the public to comment to BSEE on the proposed regulations.

ADDRESSES: You may submit comments on the proposed rulemaking by any of 
the following methods. Please use the Regulation Identifier Number 
(RIN) 1014-AA11 as an identifier in your message. See also Public 
Availability of Comments under Procedural Matters.
     Electronic comments: https://www.regulations.gov. In the 
Search box, enter BSEE-2015-0002 then click search. Follow the 
instructions to submit public comments and view supporting and related 
materials available for this rulemaking. We will post all comments.
     Mail or hand-carry comments to the Department of the 
Interior (DOI); Bureau of Safety and Environmental Enforcement; 
Attention: Regulations and Standards Branch; 45600 Woodland Road, 
Sterling, Virginia 20166. Please reference Blowout Preventer Systems 
and Well Control, 1014-AA11 in your comments and include your name and 
return address.
     Send comments on the information collection in this rule 
to: OMB, Interior Desk Officer 1014-NEW, 202-395-5806 (fax); email: 
OIRA_submission@omb.eop.gov. Please also send a copy to BSEE at 
regs@bsee.gov, fax number (703)787-1546, or by the address listed 
above.

FOR FURTHER INFORMATION CONTACT: Kirk Malstrom, Regulations and 
Standards Branch, 202-258-1518, Kirk.Malstrom@bsee.gov. To see a copy 
of the information collection request submitted to OMB, go to https://www.reginfo.gov (select Information Collection Review, Currently Under 
Review).

SUPPLEMENTARY INFORMATION: 

List of Acronyms and References

ANSI American National Standards Institute
APD Application for Permit to Drill
API American Petroleum Institute
APM Application for Permit to Modify
BOP Blowout Preventer
BOEM Bureau of Ocean Energy Management
BSEE Bureau of Safety and Environmental Enforcement
BSR Blind Shear Ram
CBM Condition-based Maintenance
CVA Certified Verification Agent
DHS Department of Homeland Security
DOI Department of the Interior
DWOP Deepwater Operations Plan
ECD Equivalent Circulating Density
EDS Emergency Disconnect Sequence
E.O. Executive Order
EOR End of Operations Report
F Fahrenheit
FPS Floating Production System
FPSO Floating Production, Storage, and Offloading Unit
FSHR Free Standing Hybrid Risers
GOM Gulf of Mexico
GPS Global Position Systems
HPHT High Pressure High Temperature
JIT Joint Investigation Team
LMRP Lower Marine Riser Package
MASP Maximum Anticipated Surface Pressure
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
National Commission National Commission on the BP Deepwater Horizon 
Oil Spill and Offshore Drilling
NTLs Notices to Lessees and Operators
OCS Outer Continental Shelf
OCSLA Outer Continental Shelf Lands Act
OEM Original Equipment Manufacturer
OIRA Office of Information and Regulatory Affairs
OMB Office of Management and Budget
PE Professional Engineer
psi Pounds per square inch
RFA Regulatory Flexibility Act
RIA Regulatory Impact Analysis
RIN Regulation Identifier Number
ROV Remotely Operated Vehicle
RP Recommended Practice
SBA Small Business Administration
SBREFA Small Business Regulatory Enforcement Act of 1996
SCCE Source Control and Containment Equipment
Secretary Secretary of the Interior
SEM Subsea Electronic Module
SEMS Safety and Environmental Management
Spec. Specification
TAR Technical Assessment and Research
TLP Tension Leg Platform
TVD True Vertical Depth
USCG United States Coast Guard
VSL Value of a Statistical Life
WAR Well Activity Report

Executive Summary

    Following the Deepwater Horizon incident on April 20, 2010, 
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:

--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. The BSEE evaluated the recommendations and acted on a 
number of them quickly to improve offshore operations while other 
recommendations required additional input from industry and other 
stakeholders. The requirements in this proposed rule are based on 
recommendations made by the previously listed investigative bodies, 
which found a need to enhance well-control best practices to advance 
safety and protection of the environment.
    This proposed rulemaking would:
    (1) Incorporate the following industry standards:


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--American Petroleum Institute (API) Standard 53, Blowout Prevention 
Equipment Systems for Drilling Wells;
--American National Standards Institute (ANSI)/API Specification 
(Spec.) 11D1, Packers and Bridge Plugs; and
--API Recommended Practice (RP) 17H, Remotely Operated Tools and 
Interfaces on Subsea Production Systems.

    As related to BOP systems:

--ANSI/API Spec. 6A, Specification for Wellhead and Christmas Tree 
Equipment;
--ANSI/API Spec. 16A, Specification for Drill-through Equipment;
--API Spec. 16C, Specification for Choke and Kill Systems;
--API Spec. 16D, Specification for Control Systems for Drilling Well 
Control Equipment and Control Systems for Diverter Equipment; and
--ANSI/API Spec. 17D, Design and Operation of Subsea Production 
Systems--Subsea Wellhead and Tree Equipment.

    (2) Revise the requirements for Deepwater Operations Plan (DWOP) 
which are required to be submitted to BSEE, to include requirements on 
free standing hybrid risers (FSHR) for use with floating production, 
storage, and offloading units (FPSO).
    (3) Revise sections in 30 CFR part 250 Subpart D, Oil and Gas 
Drilling Operations, to include requirements for:

--Submittal of equivalent circulating density (ECD) with the 
Application for Permit to Drill (APD);
--Safe drilling margin;
--Wellhead description;
--Casing or liner centralization during cementing; and
--Source control and containment.

    (4) Revise sections in 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) Revise sections in Subpart Q, Decommissioning Activities, to 
include requirements for:

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

    (6) Add new Subpart G, Well Operations and Equipment, and move 
common requirements from Subparts D, E, F, and Q into new Subpart G.
    Include new requirements in Subpart G for:

--Rig and equipment movement reports,
--Real-time monitoring, 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) Incorporate the guidance from several Notices to Lessees and 
Operators (NTLs) into Subpart G for:

--Global Position 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 Operation Reports 
(EOR).

Table of Contents

I. Background
    BSEE Statutory and Regulatory Authority
    Availability of Incorporated Documents for Public Viewing
    Summary of Documents Incorporated by Reference
    Deepwater Horizon Investigations
    Recommendations on BOPs
    Stakeholder Participation
    BSEE Response to Recommendations and Additional Considerations
II. Organization of Subpart G
III. Effective Date of a Final Rule
IV. Future Plans for Subpart G
V. Section-By-Section Discussion Appendix
VI. Derivation Tables
VII. Procedural Matters

I. Background

BSEE

    In relation to oil and gas exploration, development, and production 
operations on the Outer Continental Shelf (OCS), the Bureau of Safety 
and Environmental Enforcement (BSEE) regulates offshore oil and gas 
operations to promote safety, protect the environment, and conserve 
offshore oil and gas resources. The 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, oversight, and 
accountability of activities on the OCS. The Secretary of the Interior 
(Secretary) announced the new division of responsibilities of the 
former Minerals Management Service (MMS) into two new bureaus and one 
office within DOI in Secretarial Order No. 3299, issued on May 19, 
2010. The 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'' (76 FR 64432, October 18, 2011).

BSEE Statutory and Regulatory Authority

    The BSEE derives its authority primarily from the Outer Continental 
Shelf Lands Act (OCSLA), 43 U.S.C. 1331-1356a. Congress enacted OCSLA 
in 1953, establishing Federal control over the OCS and authorizing the 
Secretary to regulate oil and gas exploration, development, and 
production operations on the OCS. The Secretary has authorized BSEE to 
perform these functions under 30 CFR 250.101.
    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. The 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 Web site at: https://www.bsee.gov/Regulations-and-Guidance/index.aspx.
    The BSEE regulatory program regulates a wide range of facilities 
and activities, including drilling, completion, workover, production, 
pipeline, and decommissioning operations. Drilling, completion, and 
workover operations are types of well operations offshore operators 
perform throughout the OCS from fixed and floating facilities. These 
well operations are the primary topic of this proposed rulemaking.
    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 documented gaps or deficiencies 
in the OCS regulatory programs and made recommendations for 
improvements. The objective of this

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rulemaking is to address many of these recommendations, especially 
those related to BOP system design, performance, and reliability.
    The BOP equipment and systems are critical components of many well 
operations. The BOP systems can be the last defense against a release 
of hydrocarbons into the environment, when all other forms of well 
control have failed (e.g., the drilling fluid program). The BOPs may be 
the last line of defense in preventing release of gas that is volatile 
and considered to be an extreme safety hazard to rig personnel 
(uncontrolled gas releases can lead to explosions). The primary purpose 
of BOP systems is to prevent the uncontrolled release of hydrocarbons 
in an emergency situation by mechanically closing valves or rams that 
block the flow of fluid from the well. In some situations, this may 
require shear rams on the BOP stack to sever the drill pipe before the 
well can be sealed.
    The BOP equipment and systems have increased in complexity as the 
industry moves into deeper water and develops reservoirs with pressures 
greater than 15,000 pounds per square inch (psi) or temperatures 
greater than 350 degrees Fahrenheit (F). Reservoirs with these 
conditions are considered high pressure high temperature (HPHT). Most 
of the BOPs that are used in deep water operations (400 to 10,000 feet) 
are located on the seabed, which presents technological and operational 
challenges. Additionally, HPHT operations create special metallurgical 
and design issues.
    In this rulemaking, BSEE intends to:
     Implement many of the recommendations related to well-
control equipment and fill gaps in the regulatory program.
     Increase the performance and reliability of well-control 
equipment, especially BOPs.
     Improve regulatory oversight over the design, fabrication, 
maintenance, inspection, and repair of critical equipment.
     Gain information on leading and lagging indicators of BOP 
component failures, identify trends in those failures, and help prevent 
accidents.
     Ensure that the industry uses recognized engineering 
practices, as well as innovative technology and techniques to increase 
overall safety.

Availability of Incorporated Documents for Public Viewing

    When a copyrighted technical industry standard is incorporated by 
reference into our regulations, BSEE is obligated to observe and 
protect that copyright. The BSEE provides members of the public with 
Web site addresses where these standards may be accessed for viewing--
sometimes for free and sometimes for a fee. Standards-developing 
organizations decide whether to charge a fee. The API provides free 
online public access to key industry standards, including a broad range 
of technical standards. These free standards represent almost one-third 
of all API standards and include all that are safety-related or have 
been or are proposed to be incorporated into Federal regulations, 
including the standards in this rule. These standards are available for 
online review, and hardcopies and printable versions will continue to 
be available for purchase. We are proposing to incorporate certain API 
standards. The API Web site address is: https://www.api.org/publications-standards-and-statistics/publications/government-cited-safety-documents.
    For the convenience of the viewing public, who may not wish to 
purchase or view these proposed documents online, they may be inspected 
at BSEE, 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.
    These documents, if incorporated in the final rule, would continue 
to be made available to the public for viewing when requested. Specific 
information on where these documents can be inspected or obtained can 
be found at 30 CFR 250.198, Documents incorporated by reference.

Summary of Documents Incorporated by Reference

    This rulemaking is substantive in terms of the content that is 
explicitly stated in the rule text itself, but it also incorporates by 
reference some very technical, detailed standards and specifications in 
the topic of blowout preventers and well control. In their aggregate 
this represents one of the most substantial rulemakings in the history 
of the BSEE and its predecessor organizations. A brief summary, based 
on the descriptions in each standard or specification, is provided in 
the text that follows.
API Standard 53--Blowout Prevention Equipment Systems for Drilling 
Wells
    This standard is to provide requirements for the installation and 
testing of blowout prevention equipment systems whose primary functions 
are to confine well fluids to the wellbore, provide means to add fluid 
to the wellbore, and allow controlled volumes to be removed from the 
wellbore. Blowout preventer 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:
    Blowout preventers (BOPs) including installations for surface and 
subsea BOPs;
    Choke and kill lines;
    Choke manifolds;
    Control systems; and
    Auxiliary equipment.
    This document provides new industry best practices related to:
    The use of double shear rams
    Maintenance and testing requirements.
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.
API Recommended Practice 2RD--Design of Risers for Floating Production 
Systems and Tension-Leg Platforms
    This document 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 Specification 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 document 
requires that equipment be fabricated under a quality management system 
that provides for

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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 Specification 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 Specification 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 Specification 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 blowout preventers; ram 
blocks, packers and top seals; annular blowout preventers; 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 Specification 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. The 
technical content in the 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 & kill line;
    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 Specification 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, transmission 
subsea of electric/optical (rather than hydraulic) signals may be used 
to short 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 Specification 17D--Design and Operation of Subsea Production 
Systems--Subsea Wellhead and Tree Equipment
    This specification 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 Recommended Practice 17H--Remotely Operated Tools and Interfaces on 
Subsea Production Systems
    This recommended practice has been prepared to provide 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.

Deepwater Horizon Investigations

    This section discusses relevant investigations that have 
significant bearing on this proposed rulemaking.
DOI/DHS Investigation
    The joint DOI/DHS investigation started on April 27, 2010, when the 
Secretaries of DOI and DHS convened a joint investigation team (JIT) 
comprised of staff from the MMS and the U.S. Coast Guard (USCG). The 
JIT held seven public hearings and heard testimony from more than 80 
witnesses. The DOI JIT issued a report on September 14, 2011, entitled, 
REPORT REGARDING THE CAUSES OF THE APRIL 20, 2010 MACONDO WELL BLOWOUT, 
which included its findings, conclusions, and recommendations.
National Commission
    On May 22, 2010, President Barack Obama announced the creation of 
the National Commission on the BP Deepwater Horizon Oil Spill and 
Offshore Drilling (National Commission), an independent, non-partisan 
entity. The President charged the National Commission to determine the 
causes of the disaster, to make recommendations for improvement to the 
country's ability to respond to spills, and to recommend reforms to 
make offshore energy production safer. The National Commission 
published its final

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report on January 11, 2011, entitled, DEEP WATER, The Gulf Oil Disaster 
and the Future of Offshore Drilling.
Chief Counsel for the National Commission
    Given the factual and technical complexity of some of the 
underlying causes of the blowout, the National Commission's Chief 
Counsel issued a separate report setting forth in greater detail its 
findings and conclusions regarding the technical, managerial, and 
regulatory aspects of the blowout. The report contains findings and 
conclusions about the loss of well control, and also contains 
recommendations to industry and government to enhance well design. The 
Chief Counsel's report was published on February 17, 2011, and is 
entitled, Macondo: The Gulf Oil Disaster.
National Academy of Engineering
    At the request of DOI, a National Academy of Engineering (NAE)/
National Research Council committee examined the probable causes of the 
Deepwater Horizon explosion, fire, and oil spill in order to identify 
measures for preventing similar harm in the future. The final report 
was released December 14, 2011, and is entitled, Macondo Well-Deepwater 
Horizon Blowout. The final report provides findings about the causes of 
the loss of well control and the failure of the BOP to prevent release 
of hydrocarbons and offers recommendations to industry and government 
that would strengthen oversight of deepwater wells, enhance system 
safety, and improve cementing practices and the technical skills of 
industry and regulatory staff.

Recommendations on BOPs

    Each of the previously discussed investigations resulted in reports 
that contained recommendations to improve offshore safety. One 
consistent element in each of the investigations was the recognition 
that additional requirements related to BOPs and well-control equipment 
are needed. The following list contains some of the recommendations on 
BOPs and related equipment from the various investigations:

--The BSEE should consider promulgating regulations that require 
operators/contractors to have the capability to monitor the subsea 
electronic module (SEM) battery(ies) from the drilling rig, to ensure 
that there is sufficient battery power to operate the system.
--The BSEE should consider requiring standardization of: Remotely 
Operated Vehicle (ROV) intervention panels, ROV intervention 
capabilities, and maximum closing times when using an ROV; ROV hot stab 
and receptacles per API RP 17H; and hot stab designs between drilling 
and production operations.
--The BSEE should consider requiring a blind-shear ram design that 
incorporates improved pipe[hyphen]centering in the shear ram.
--The BSEE should make effective use of industry standards and best 
practice guidelines used by other countries with the recognition that 
standards need to be updated and revised continually.
--The BSEE should improve reporting of safety-related incidents and 
require the reporting of near-misses to assist in accident prevention 
and to improve standards.
--The BSEE should develop standardized requirements for the training 
and certification of key industry personnel.
--The BSEE should rely on independent organizations to verify and 
certify compliance with critical designs and required processes.
--The BSEE should ensure that the general well design includes a review 
of fitness of the components for the intended use.
--The BSEE should consider promulgating regulations that would require 
operators to report leaks associated with BOP control systems.
--The BSEE should consider promulgating regulations that would require 
real[hyphen]time, remote capture of drilling data and BOP function 
data.
--The BSEE should require improvement of the instrumentation on BOP 
systems so that the functionality and condition of the BOP can be 
monitored continuously.
--The BSEE should consider regulations that address a reasonable margin 
of safety between the ECD and the pressure that would cause wellbore 
fracturing.
--The BSEE should establish testing and maintenance requirements for 
BOPs to ensure operability and increased reliability appropriate to the 
environment and application.
--The BSEE should require improvement of the design capabilities of the 
BOP systems so that they can shear and seal all combinations of pipe 
under all possible conditions of load from the pipe and from the well 
flow, and so that there would always be a shearable section of the 
drill pipe in front of a blind-shear ram in the BOP.
--The BSEE should require demonstration of the performance of the 
design capabilities of BOPs and require that they be independently 
certified on a regular basis by test or other means.

Stakeholder Participation

    Since the Deepwater Horizon incident, BSEE has made it a priority 
to participate in meetings, training, and workshops with industry, 
standards organizations, and other stakeholders. The 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 
this proposed rule. This includes the knowledge and skillset that 
industry has, and BSEE wants to benefit from that experience to improve 
the safety of all operations on the OCS.
    Therefore, on May 22, 2012, BSEE hosted a public offshore energy 
safety forum that brought together Federal decision-makers, industry, 
academia, and other stakeholders to discuss additional steps that BSEE 
and the industry might take to continue to improve the reliability and 
safety of BOPs. This public forum provided industry experts, Federal 
decision-makers, and the public the opportunity for free and open 
dialogue. Discussion panels consisted of representatives from 
government organizations, trade associations, equipment manufacturers, 
offshore operators, consultants, training companies, and others. During 
the forum, five separate panels discussed the following BOP topics:

--BOP technology needs identified by Deepwater Horizon investigations;
--Real-time technologies that can aid in diagnostics and kick 
detection;
--Design requirements needed to provide assurance that BOPs would cut 
casing or drill pipe and seal a well effectively;
--Manufacturing, testing, maintenance, and certification requirements 
needed to ensure operability and reliability of BOP equipment; and
--Training and certification needs for industry personnel operating or 
maintaining BOPs.

    You can find additional information about the forum, including 
presentations and transcripts, on the BSEE Web page at: https://www.bsee.gov/BSEE-Newsroom/BSEE-News-Briefs/2012/BSEE-Hosts-BOP-Forum-in-DC. In the year following this forum, BSEE has also received 
significant input and specific recommendations from industry groups, 
operators, equipment manufacturers, and environmental organizations on 
each of these items. For example, BSEE has actively participated in the 
following, among other events:


[[Page 21509]]


--The API Exploration & Production Standards Conference on Oilfield 
Equipment and Materials;
--The Ocean Energy Safety Institute risk forum;
--The Offshore Well Control Equipment Forum, organized by API, January 
30, 2014;
--The International Regulators Forum;
--Various standards committees and sub-committees for standards 
development (e.g., API Committee on Standardization of Oilfield 
Equipment and Material Subcommittee 16 on Drilling Well Control 
Equipment);
--The BSEE and industry assessments of current technology involving 
research that BSEE is funding; and
--The BSEE sponsored standards workshops--November 2012 and January 
2014.

    The BSEE has considered this input in developing this proposed 
rulemaking and has reviewed studies and research on this topic.

BSEE Response to Recommendations and Additional Considerations

    The BSEE evaluated all recommendations from the investigative 
bodies and public input and determined that the agency needs to update 
regulations related to the prevention of blowouts. The prevention of 
blowouts, either through precautionary measures or by operation of a 
BOP, is a critical priority for BSEE. The BSEE therefore focused this 
rulemaking on updating and revising current well-control regulations.
    Several of the recommendations related to BSEE's regulatory 
programs were already implemented in rulemakings following the 
Deepwater Horizon incident. The following items are included in this 
proposed rule and arise out of the investigation reports or from other 
third-party recommendations.

 Shearing Requirements

    The BSEE regulations currently require that a BOP stack include a 
blind shear ram. A blind shear ram is designed to cut drill pipe in the 
well and shut in the well in an emergency well control situation. In 
order for a blind shear ram to shut in a well where drill pipe is 
across the BOP, it must be capable of shearing the drill pipe and there 
are known mechanical and design limitations that may prevent this from 
occurring. As demonstrated by the Deepwater Horizon incident, the 
failure of equipment to perform reliably can result in a major safety 
and/or environmental event.
    Prior to the Deepwater Horizon incident, MMS commissioned the 
following research on shearing capabilities: Technical Assessment & 
Research (TAR) Project 383, Performance of Deepwater BOP Equipment 
During Well-control Events; TAR Project 408, Development of a Blowout 
Intervention Method and Dynamic Kill Simulated for Blowouts Occurring 
Ultra-Deepwater; TAR Project 431, Evaluation of Secondary Intervention 
Methods in Well-control; TAR Project 455, Review of Shear Ram 
Capabilities; and TAR Project 463, Evaluation of Sheer Ram 
Capabilities. This research can be found at https://www.bsee.gov/Technology-and-Research/Technology-Assessment-Programs/Categories/Drilling/. The research indicated that there was a large amount of 
uncertainty related to the shearing capability of existing BOPs. These 
reports documented that there were inconsistent and inadequate testing 
protocols used by manufacturers to demonstrate shearing capability, a 
failure to share shearing data that would allow for a better 
understanding of shearing capability, and a concern that not all 
operators and drilling contractors are aware of the limitations of the 
equipment they are using.
    Following the Deepwater Horizon incident, the Agency received 
recommendations from multiple investigations and studies concerning the 
need for new and more rigorous requirements and technologies to ensure 
that drilling components can be severed and a well safely shut-in 
during an emergency. The BSEE is proposing a series of new requirements 
to address the gaps that were identified in these reports, incorporate 
recent industry standards, and assist in the adoption of improved 
technology through performance-based requirements.
    Some of the limitations of current designs are well known. Industry 
acknowledges that BOP equipment would not shear drill collars, heavy 
weight drill pipe, or drill pipe tool joints. This inability to shear 
all of the components in the drill string can create significant 
complications in an emergency situation and increase the likelihood of 
a catastrophic event occurring. As the industry continues to develop 
more technically challenging resources, shearing and sealing become 
more difficult for several reasons, including:
--The improvements in drill pipe properties, particularly increased 
material strength and ductility, result in higher forces being required 
to shear the drill pipe in the future.
--Increased water depths, in combination with drilling fluid density 
and shut-in pressure, contribute to a BOP having to generate additional 
force to successfully shear.

    The BSEE believes that the current testing protocols and 
verification procedures must be strengthened to ensure that the 
capabilities of shearing equipment are clearly understood and 
demonstrated. Furthermore, on a longer term basis, the overall 
performance of this equipment must improve to ensure that it can 
operate in an emergency situation and can successfully shear a drill 
stem. In this rule, BSEE is proposing to accomplish these objectives 
through the following:

--Require operators to assure that shearing capability for existing 
equipment complies with BSEE requirements related to shearing by 
performing tests and providing detailed results to a BSEE-approved 
verification organization. This organization would perform an 
independent engineering review of the test protocols and data and 
ensure that the testing would provide reasonable assurances that the 
equipment would perform as designed on drill pipe of specific 
mechanical and physical properties and under the operating conditions 
relevant to the particular well at which the equipment will be used. 
The BSEE expects that the independent engineering review would be based 
on recognized engineering practices. To become a BSEE-approved 
verification organization, organizations would need to submit 
documentation for BSEE approval describing the applicable 
qualifications and experience. This engineering review process would 
assist in developing more standardized testing protocols, increase data 
sharing within the industry, and provide information for future BSEE 
determinations of best available and safest technologies under section 
21 of OSCLA, 43 U.S.C. 1347. The BSEE anticipates that industry would 
play an important role in this process by developing rigorous testing 
procedures and protocols for organizations that perform the testing.
--Require compliance with the latest industry standards contained in 
API Standard 53. In addition to these industry standards, BSEE would 
also include a requirement that operators use two shear rams in subsea 
BOP stacks. The use of double shear rams would increase the likelihood 
that a drill string can be sheared by ensuring that a shearable 
component is opposite a shear ram. In this proposed rulemaking, BSEE 
will not propose adopting the provision in API

[[Page 21510]]

Standard 53 that operators can ``opt out'' of this double shear ram 
requirement for moored rigs. If there are unique circumstances that 
prevent the use of two shear rams, operators would be able to apply for 
the use of alternative procedures or equipment under Sec.  250.141.
--Require the use of BOP technology that provides for better shearing 
performance through the centering of the drill pipe in the shear rams. 
A number of investigations \1\ have found that the shear rams did not 
completely cut the drill pipe in the Deepwater Horizon. This occurred 
because the drill pipe was not centered within the stack. The BSEE is 
aware of at least one BOP equipment manufacturer that currently has 
pipe centering technology available and proposes to require the use of 
pipe centering within 7 years after the publication of the final rule 
to encourage further technological development.
---------------------------------------------------------------------------

    \1\ See DOI JIT investigation recommendation, D6.
---------------------------------------------------------------------------

Equipment Reliability and Performance

    Prior to the Deepwater Horizon incident, the industry's guidance 
document for the operation of BOPs was API RP 53--Recommended Practices 
for Blowout Prevention Equipment Systems for Drilling Wells, Third 
Edition, March 1, 1997 (Reaffirmed September 1, 2004). The BSEE 
currently incorporates only specific sections of this document in 
existing regulations, including sections related to maintenance, 
inspection, and accumulator systems. Following the Deepwater Horizon 
incident, industry recognized the need to enhance BOP guidance and 
concluded that it was necessary to completely rewrite API RP 53 and 
upgrade the document from an RP to a standard. The BSEE participated in 
the development of the industry standard and is proposing to 
incorporate the newly published standard into its regulations. 
Additionally, other key industry standards concerning this type of 
equipment would be incorporated by reference.
    The BSEE concluded that incorporating new API Standard 53 
provisions into its regulations would allow for better regulatory 
oversight and would ensure improved BOP design and operability. The 
BSEE believes that the incorporation of this document, and other key 
industry standards, such as ANSI/API Spec. 6A, ANSI/API Spec. 16A, API 
Spec. 16C, API Spec. 16D, ANSI/API Spec. 17D, and API Spec. Q1, would 
establish minimum design, manufacture, and performance baselines for 
this equipment and is essential to ensure the reliability and 
performance of this equipment. The BSEE anticipates that BOP equipment 
that meets these new requirements, along with several supplemental 
requirements (such as requiring blind-shear rams that incorporate 
improved pipe-centering designs), would perform in a more reliable 
manner.
    The BSEE believes that the reliability of BOP-related equipment 
would also increase if its inspection, maintenance, and repair are 
performed by highly-trained personnel. Operators are currently required 
by BSEE regulations to ensure that all personnel are properly trained. 
The BSEE proposes to add requirements that specify that these personnel 
be qualified and trained pursuant to original equipment manufacturer 
(OEM) recommendations, unless otherwise specified by BSEE. The BSEE 
encourages industry to develop standards and certification programs for 
these personnel.

Third-Party Verification

    Regulatory oversight of the lifecycle of BOP equipment, ranging 
from design, installation, inspection, testing, maintenance, and 
repair, presents a variety of logistical and technical challenges, 
especially because the equipment might be used at multiple locations. 
In several sections of the proposed regulations, BSEE would require 
third-party verification of the design, maintenance, inspection, 
testing, and repair of BOP systems and equipment by a BSEE-approved 
entity. We believe that the use of third-party verification 
organizations would help BSEE ensure that these systems are designed 
and maintained during their entire service life to minimize risk. For 
subsea BOPs or BOPs used in HPHT applications, we are proposing that 
BSEE-approved verification organizations submit reports verifying 
compliance with these new requirements. This verification would provide 
BSEE with reasonable assurance that the equipment is fit for service as 
intended.
    The BSEE is also proposing an additional qualification and 
verification process for BOP(s) and related equipment used in HPHT 
wells. The verification must be specific to the conditions of the 
particular well at which the BOP(s) will be used. This verification 
process is needed because there are currently no engineering standards 
for the design, fabrication, and testing of equipment used in HPHT 
conditions. The use of a BSEE-approved verification organization would 
provide an additional layer of review and verification during the 
development and operation of the equipment. It would be the 
responsibility of the operator to clearly demonstrate to the BSEE-
approved verification organization and BSEE that the equipment was 
designed for the HPHT conditions specific to the well, and will perform 
in a reliable manner during its service life under those conditions. To 
become a BSEE-approved verification organization, the organization 
would have to submit documentation for approval describing the 
organization's applicable qualifications and experience.

 Failure Reporting/Near-Miss Reporting

    Several of the standards that BSEE proposes to incorporate by 
reference contain failure reporting processes that ensure that 
operators share information with OEMs related to the performance of 
their equipment. This sharing of information makes it possible for the 
OEMs to notify users of any safety issues that arise. In 2009, the 
industry provided the MMS with a BOP reliability study that 
specifically noted the importance of ANSI/API Spec. 16A, Annex F, and 
referred to this requirement as ``an excellent practice that assists 
manufacturers in identifying problems that occur in the operation and 
maintenance of their projects.'' The BSEE agrees with this statement 
and is including this requirement in the proposed regulations.
    Because the same equipment designs are often used by multiple 
operators, ensuring the timely reporting of this type of data can play 
an important role in preventing future incidents. The need for a 
formalized process for disseminating information to the industry was 
clearly demonstrated following the December 2012 failures of certain 
bolts used in BOPs and wellhead connectors in the Gulf of Mexico (GOM). 
Subsequent investigations revealed that although these failures had 
occurred over a period of years, most of the industry was not aware of 
the safety issues. The BSEE is proposing that the operators report any 
significant problems with BOP or well-control equipment to BSEE to 
ensure that this information can be provided in a timely manner to OCS 
operators and the international community. In the long term, BSEE would 
continue to encourage industry to develop a comprehensive and 
formalized method of collecting, analyzing, and disseminating failure 
data involving critical equipment.

Safe Drilling Practices

    The proposed regulations include new requirements related to the 
maintenance of safe drilling margins

[[Page 21511]]

consistent with the recommendations arising out of Deepwater Horizon 
investigations. The BSEE also proposes to add requirements related to 
liners and other downhole equipment. We believe that these requirements 
would help to reduce the likelihood of a major well-control event 
occurring and ensure the overall integrity of the well design.
    The proposed rule would require that operators have the capability 
to monitor deepwater and HPHT drilling operations from the shore and in 
real time. This would allow operators to anticipate and identify issues 
in a timely manner and to utilize onshore resources to assist in 
addressing critical issues. It would allow BSEE greater visibility of 
operations so BSEE may focus on specific critical operations for 
additional oversight.
    The BSEE also proposes a requirement that designated operators 
report leaks associated with BOP control systems on the daily report, 
in the WAR, and directly to the District Manager. This requirement 
would ensure that the agency is made aware of any leaks and may 
determine if agency action is appropriate.
    The proposed regulation would include requirements concerning ROV 
operations, including the adoption of API RP 17H to standardize ROV hot 
stab activities. An ROV hot stab is a high pressure subsea connector 
used to connect the ROV into the BOP system. An ROV hot stab is 
basically comprised of two parts:
--A valve; and
--A tool that connects onto the valve and controls the valve.
    The valve is usually placed on the subsea BOP stack panel, and is 
accessible for an ROV to insert the tool and activate certain functions 
on the BOP.

BOP Testing

    In response to public input related to the value of pressure 
testing in predicting future performance of a BOP and industry concerns 
about the operational safety issues associated with performing these 
tests, BSEE proposes to modify the BOP testing frequency for workover 
and decommissioning operations. The BSEE proposes to change the current 
7 day BOP testing interval for workover (current Sec.  250.617(b)) and 
decommissioning (current Sec.  250.1707(b)) operations to 14 days, 
which is consistent with the testing frequency requirements (reference 
current Sec.  250.447(b) and 250.517(a)) for drilling and completion 
operations. Some drilling, completion, workover, and decommissioning 
operations use the same rigs and BOP systems; therefore, to ensure 
consistency among different operations involving the same equipment, 
BSEE proposes to harmonize the requirements for that type of equipment. 
Harmonizing the testing frequency would streamline the BOP function-
testing criteria and increase safety by reducing repetition of 
operations, such as pulling out of the hole and running in the hole, 
that pose operational safety issues, therefore limiting the exposure of 
potential risks to offshore personnel. This may also have a positive 
effect on overall equipment durability and reliability.
    A benefit of this provision would be a cost saving to industry. We 
estimated the total cost savings to industry from this provision to be 
$150,000,000 per year (see the economic analysis for more detailed 
information). Based upon existing available data and the timeframes of 
the economic analysis, the cost savings benefits of the proposed rule 
would result in benefits greater than the identified quantitative costs 
of the rule. The BSEE is requesting comments on whether the proposed 
BOP testing interval should be 7 days, 14 days (as proposed), or 21 
days for all types of operations including drilling, completions, 
workovers, and decommissioning. The BSEE is also requesting comments on 
the specific cost implications of each testing interval to further its 
consideration of the issue. For more information on the costs and 
benefits of the proposed rule, refer to the economic analysis.
    In addition to cost savings benefits, BSEE's economic analysis also 
considers benefits from potential reductions in oil spills and reduced 
fatalities. The BSEE is requiring additional measures (e.g. real-time 
monitoring and increased maintenance) that help ensure the 
functionality and operability of the BOP system and, therefore, will 
reduce the risks of spills and fatalities.
    The BSEE is also soliciting comments on the use of pressure and 
functional tests during drilling operations to verify performance, the 
adequacy of current and proposed testing requirements, and the 
identification of risks associated with increasing or decreasing the 
testing frequency.

II. Organization of Subpart G

    The BSEE determined that the most effective way to communicate 
consistent requirements for BOPs across all well operations (drilling, 
completion, workover, and decommissioning) is to consolidate those 
common requirements in one location. The current regulations repeat 
similar BOP requirements in multiple locations throughout 30 CFR part 
250. The BSEE is proposing to consolidate these requirements into 
Subpart G, which is currently reserved. This would allow better 
flexibility, efficiency, and consistency in future rulemaking. The 
proposed rule would structure proposed Subpart G--Well Operations and 
Equipment, under the following undesignated headings:

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

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

III. Effective Date of a Final Rule

    The BSEE understands that operators may need time to comply with 
certain requirements proposed in this rule. The BSEE is taking into 
consideration the amount of time needed to meet the requirements for 
the installation of double shear rams and new certification 
requirements. Based on information provided by industry, all new 
drilling rigs are already being built, pursuant to the same industry 
standards BSEE now proposes to adopt (including API Standard 53), and 
many have already been retrofitted to comply with these industry 
standards. Furthermore, most already comply with recognized engineering 
practices and OEM requirements related to repair and training. The BSEE 
evaluated the proposed requirements in this proposed rule and seeks to 
set reasonable effective dates for those requirements based on 
information gained during, among other activities, interaction with 
stakeholders, involvement with development of industry standards, and 
evaluation of current technology. The BSEE proposes an effective date 
of 3 months following publication of the final rule. Operators would be 
required to demonstrate compliance with most of the proposed 
requirements at that time, with the exception of the following more 
extended timeframes:

--Operators would be required to comply with the real-time monitoring 
requirements within 3 years from the publication of the final rule.
--Operators would be required to install double shear rams on subsea 
BOPs and on surface BOPs on floating facilities within 5 years from the 
publication of the final rule.
--Operators would be required to install shear rams that center drill 
pipe during shearing operations within 7

[[Page 21512]]

years from the publication of the final rule.

    The BSEE is soliciting comments about the proposed compliance dates 
for the requirements in this proposed rule to ensure the dates are 
appropriate. The BSEE is specifically soliciting comments on whether 
the 3-month, 3-year, 5-year, and 7-year compliance dates are 
appropriate and achievable. The BSEE is also specifically soliciting 
comments on whether the proposed requirements can be met sooner than 
the proposed compliance dates (e.g., 5 years after publication of the 
final rule for centering drill pipe), and the anticipated costs for 
meeting these proposed compliance dates. Please provide justification 
for your responses.
    Note that BSEE still retains the discretion under Sec.  250.141 to 
authorize alternate procedures or equipment that provide an equivalent 
level of safety and environmental protection.

IV. Future Plans for Subpart G

    In future rulemaking, BSEE intends to include additional regulatory 
requirements for operations and equipment in Subpart G, 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;
--Diverter systems with subsea BOPs; and
--Coiled tubing, snubbing, and wireline units.

    The BSEE is also researching other topics that would be appropriate 
for inclusion into this new subpart in future rulemakings.

V. Section-By-Section Discussion

Subpart A--General

What does this part do? (Sec.  250.102)
    This section would be revised to add references for Subpart G to 
(b)(1), (11), (12), and (13) and also add new paragraph (b)(19) to the 
table. This would be added so the public will know that they can find 
requirements about well operations and equipment in proposed Subpart G.
What must I do to protect health, safety, property, and the 
environment? (Sec.  250.107)
    Paragraph (a) of this section would be revised to include a general 
performance-based requirement 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. Recognized engineering practices may be drawn from 
established codes, industry standards, published peer-reviewed 
technical reports or industry recommended practices, and similar 
documents applicable to engineering, design, fabrication, installation, 
operation, inspection, repair, and maintenance activities. This risk 
reduction objective is used in other regulatory programs and is 
consistent with BSEE's goal of taking a more risk-based approach in its 
regulations. This risk reduction principle has also been included in a 
recently published industry document (API Bulletin 97) which addresses 
drilling, completion, and workover activities.
    Proposed paragraph (e) would be added to clarify BSEE's authority 
to issue orders when necessary to protect health, safety, property, or 
the environment. The first sentence authorizes BSEE to issue orders to 
ensure compliance with the regulations. The second sentence clarifies 
that BSEE may order that operations of a component or facility be shut-
in 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.
Service fees. (Sec.  250.125)
    This table in this section would be revised to reflect the correct 
citation for payment of the service fee relating to DWOPs.
Documents incorporated by reference. (Sec.  250.198)
    This section would be revised to update citations of currently 
incorporated documents and to incorporate new documents. Changes to 
this section would include:

--Revising paragraph (h)(51) to update cross-references to the sections 
incorporating API RP 2RD, Design of Risers for Floating Production 
Systems (FPSs) and Tension-Leg Platforms (TLPs);
--Removing the incorporation of API RP 53 in paragraph (h)(63) and in 
its place incorporating new API Standard 53, Blowout Prevention 
Equipment Systems for Drilling Wells, Fourth Edition (with the 
exception of the opt-out provision);
--Revising paragraph (h)(68) to update cross-references to the sections 
incorporating API Spec. Q1, Specification for Quality Programs for the 
Petroleum, Petrochemical and Natural Gas Industry;
--Revising paragraph (h)(70) to update cross-references to the sections 
incorporating ANSI/API Spec. 6A, Specification for Wellhead and 
Christmas Tree Equipment;
--Adding new paragraph (h)(89) to incorporate ANSI/API Spec. 11D1, 
Packers and Bridge Plugs;
--Adding new paragraph (h)(90) to incorporate ANSI/API Spec. 16A, 
Specification for Drill-through Equipment;
--Adding new paragraph (h)(91) to incorporate API Spec. 16C, 
Specification for Choke and Kill Systems;
--Adding new paragraph (h)(92) to incorporate API Spec. 16D, 
Specification for Control Systems for Drilling Well Control Equipment 
and Control Systems for Diverter Equipment;
--Adding new paragraph (h)(93) to incorporate ANSI/API Spec. 17D, 
Design and Operation of Subsea Production Systems--Subsea Wellhead and 
Tree Equipment;
--Adding new paragraph (h)(94) to incorporate ANSI/API RP 17H, Remotely 
Operated Vehicle Interfaces on Subsea Production Systems.
Paperwork Reduction Act statements--information collection. (Sec.  
250.199)
    This section would be revised by:
--Changing all the OMB Control Numbers from the 1010 numbering system 
to BSEE's new 1014 numbering system;
--Rewording for plain language the reasons that BSEE collects the 
information and how it is used; and
--Adding paragraphs for APDs, Application for Permit to Modify (APM), 
and Subpart G in the table to identify the basis for the information 
collection.

Subpart B--Plans and Information

What must the Deepwater Operations Plan (DWOP) contain? (Sec.  250.292)
    The proposed rule would re-designate existing paragraph (p) to (q) 
and add a new paragraph (p). Proposed new paragraph (p) would specify 
FSHR requirements within the DWOP. The FSHRs are used in combination 
with FPSOs. The use of FPSOs is relatively new to the GOM. There is 
only one FPSO currently operating in the GOM; however, the use of FPSOs 
is expected to increase in the next few years.

[[Page 21513]]

Currently, BSEE approves the use of FPSOs and associated FSHRs through 
the DWOP process, but has no regulations specifically addressing the 
use of FSHRs. Proposed paragraph (p) would outline what BSEE requires 
in a DWOP that proposes the use of FSHRs. The new requirements would 
include submission of the following:

--Detailed descriptions and drawings of the FSHR buoy and tether 
system;
--Information on the design, fabrication, and installation of the FSHR 
buoy and tether system, including pressure ratings, fatigue life, and 
yield strengths;
--A description of how the operator met the design requirements, load 
cases, and allowable stresses for each load case according to API RP 
2RD, RP for Design of Risers for FPSs and TLPs;
--Detailed information regarding the tether system used to connect the 
FSHR to a buoyancy air can;
--Descriptions of the monitoring system and a 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
--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 Certified Verification Agent 
(CVA) as required in current Subpart I and clarified in BSEE NTL 2007-
G14, Pipeline Risers Subject to the Platform Verification Program.

Subpart D--Oil and Gas Drilling Operations

General Requirements. (Sec.  250.400)
    The proposed rule, would revise this entire section including the 
section heading. The current section entitled, Who is subject to the 
requirements of this subpart? is not necessary because the subject 
matter is sufficiently covered under Sec.  250.146, which states that 
lessees, operators, and the person actually performing the activity to 
which a requirement applies are jointly and severally responsible for 
complying with the regulations.
    The new proposed language would require drilling operations to 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 (in areas leased and not 
leased), the National security or defense, or the marine, coastal, or 
human environment. The new section would also clarify that for drilling 
operations, the operator would need to follow the requirements of this 
subpart and the applicable requirements of proposed Subpart G.
What must I do to keep wells under control? (Sec.  250.401)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.703.
When and how must I secure a well? (Sec.  250.402)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.720.
What drilling unit movements must I report? (Sec.  250.403)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.712.
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)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.723.
What information must I submit with my application? (Sec.  250.411)
    This section would be revised by separating the diverter and BOP 
descriptions in the table containing regulatory cross-references for 
descriptions of APD information, and updating the cross-references to 
include proposed Subpart G.
What must my description of well drilling design criteria address? 
(Sec.  250.413)
    This section would revise paragraph (g) to include the maximum ECD 
on the pore pressure/fracture gradient plot. The ECD is the effective 
density exerted by a circulating fluid against the formation that takes 
into account the pressure drop in the annulus. The ECD is an important 
parameter in avoiding kicks and losses, particularly in wells that have 
a narrow window between the fracture gradient and pore pressure. This 
information is necessary for proper well drilling design and for BSEE 
to better review the drilling program.
What must my drilling prognosis include? (Sec.  250.414)
    This section would revise paragraphs (c), (h), and (i) and add new 
paragraphs (j) and (k).
    Paragraph (c) of this section would be revised to better define the 
safe drilling margin requirements. The planned safe drilling margins 
would be required to be between the proposed drilling fluid weights and 
the estimated pore pressures and the lesser of estimated fracture 
gradients or casing shoe pressure integrity test. The safe drilling 
margins would also have to meet the following conditions:
--Static downhole mud weight must be greater than estimated pore 
pressure;
--Static downhole mud weight must be a minimum of one-half pound per 
gallon below the lesser of the casing shoe pressure integrity test or 
the lowest estimated fracture gradient;
--The ECD must be below the lesser of the casing shoe pressure 
integrity test or the lowest estimated fracture gradient;
--When determining the pore pressure and lowest estimated fracture 
gradient for a specific interval, related hole behavior must be 
considered (e.g., pressures, influx/loss of fluids, and fluid types).

    Changes to better define safe drilling margins are partially based 
on the information revealed during investigations of the Deepwater 
Horizon incident.\2\ Safe drilling margins are used to determine the 
downhole fluid program and ensure fluid densities are capable of 
controlling the estimated pore pressure and formation fluids while not 
fracturing the formations. With clearer requirements for safe drilling 
margins, operators would be able to better understand BSEE requirements 
and design fluid programs accordingly.
---------------------------------------------------------------------------

    \2\ See DOI JIT investigation recommendation, A3.
---------------------------------------------------------------------------

    Paragraphs (h) and (i) would be revised with only minor wording 
changes.
    New paragraph (j) would be added to require that the drilling 
prognosis include the type of wellhead and liner hanger systems to be 
installed and a descriptive schematic. The descriptive schematic would 
include, among other information, pressure ratings, dimensions, valves, 
load shoulders, and locking mechanism, if applicable. This information 
would assist BSEE in its review of the APD, and assist staff in 
ensuring that the wellhead and liner hanger systems are adequate for 
the proposed use.
    New paragraph (k) would be added to require submittal of any 
additional information required by the District Manager.
What must my casing and cementing programs include? (Sec.  250.415)
    Paragraph (a) of this section would be revised to include casing 
information for all sections of each casing interval. Operators would 
also need to include

[[Page 21514]]

bit depths (including measured and true vertical depth (TVD)), and 
locations of any installed rupture disks and indicate either the 
collapse or burst ratings. Requiring this information for all sections 
for each casing interval would make design calculations and submittals 
more accurate and provide a complete representation of the well.
What must I include in the diverter description? (Sec.  250.416)
    This heading and section would be revised to remove the BOP 
descriptions and leave the diverter descriptions. The BOP descriptions 
would be moved to new Subpart G in proposed Sec. Sec.  250.730, 
250.731, and 250.732. The diverter requirements would remain unchanged.
What must I provide if I plan to use a mobile offshore drilling unit 
(MODU)? (Sec.  250.417)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.713.
What additional information must I submit with my APD? (Sec.  250.418)
    Paragraph (g) of this section would be revised to require operators 
to seek approval for plans to wash out or displace cement to facilitate 
casing removal upon well abandonment. The request would need to include 
a description of how far below the mudline the operator proposes to 
displace cement and how the operator will visually monitor returns. 
This proposed change would provide information that would assist BSEE 
in its review of the APD.
What well casing and cementing requirements must I meet? (Sec.  
250.420)
    The introductory language in this section would be revised to 
require that applicable casing and cementing requirements in proposed 
Subpart G must also be followed.
    Existing paragraph (a)(6) would be renumbered as paragraph (a)(7). 
New paragraph (a)(6) would be added to require adequate centralization 
to help ensure proper cementation. Multiple Deepwater Horizon 
investigations discussed the use of centralizers, which are devices 
that maintain the casing or liner in the center of the wellbore to help 
ensure efficient placement of cement around the casing string. If an 
operator cements casing off-center, the wellbore may not be properly 
sealed. New paragraph (b)(4) would be added to specify that if casing 
is needed that differs from what was approved in the APD, the operator 
would have to contact the appropriate District Manager and receive 
approval before installing the different casing. This addition is 
necessary to ensure the casing is suitable for the well conditions and 
for BSEE to have the most up-to-date wellbore information.
    Paragraph (c) would be renumbered and revised by adding a new 
paragraph (c)(2). New paragraph (c)(2) would require the use of a 
weighted fluid to maintain an overbalanced hydrostatic pressure during 
the cement setting time, except when cementing casings or liners in 
riserless hole sections. This proposed change would enhance wellbore 
stability during cementing.
    The use of a weighted fluid is particularly important because most 
well-control events occur due to inadequately weighted fluids in the 
hole, as well as inadequate volume of fluid to hold back the pressures 
in the well. A weighted fluid has a greater density than seawater. As 
the density of the weighted fluid increases, it exerts a greater 
hydrostatic pressure, thereby minimizing the potential for the well to 
flow.
What are the casing and cementing requirements by type of casing 
string? (Sec.  250.421)
    Paragraph (b) of the table in this section would be revised to 
specify that if oil, gas, or unexpected formation pressure is 
encountered, the operator would have to set conductor casing 
immediately and set it above the encountered zone, even if it is before 
the planned casing point. This proposed change would ensure that 
conductor casing is not placed across a hydrocarbon zone.
    Paragraph (f) of the table in this section would be revised to 
disallow the use of liners as conductor casing. When a liner is used as 
conductor casing, a portion of the drive pipe is exposed to wellbore 
pressure, and BSEE does not accept drive pipe as a pressure-rated 
component. By prohibiting the use of liners as conductor casing, BSEE 
would ensure that the drive pipe is not exposed to wellbore pressures.
What are the requirements for casing and liner installation? (Sec.  
250.423)
    This section would be revised as follows:

--Change the heading to more accurately reflect corresponding changes 
within the section.
--Remove the pressure testing and negative pressure testing 
requirements. The pressure testing requirements would be found in 
proposed Sec.  250.721.
--Add information to clarify that liner latching mechanisms, if 
applicable, would need to be engaged upon successfully installing and 
cementing the casing string or liner.
    This last addition would reinforce the importance that liners are 
properly secured in place to ensure wellbore integrity. The 
requirements for latching and lockdown mechanisms were also a topic of 
discussion in the DOI JIT Deepwater Horizon investigation.
What are the requirements for prolonged drilling operations? (Sec.  
250.424)
    This section would be removed and reserved. The content of this 
section would be moved to in proposed Sec.  250.722.
What are the requirements for pressure testing liners? (Sec.  250.425)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.721.
What are the recordkeeping requirements for casing and liner pressure 
tests? (Sec.  250.426)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.746.
What are the requirements for pressure integrity tests? (Sec.  250.427)
    Paragraph (b) would be revised to clarify that operators must 
maintain the drilling margins as described in Sec.  250.414.
What must I do in certain cementing and casing situations? (Sec.  
250.428)
    Paragraph (b) of the table in this section would be revised to 
require District Manager approval for hole interval drilling depth 
changes greater than 100 feet TVD, and submittal of a professional 
engineer (PE) certification, certifying that the PE reviewed and 
approved the proposed changes. This requirement would assist BSEE in 
verifying the actual well conditions. This new requirement would also 
ensure proper PE review of associated changes.
    Paragraph (c) of the table in this section would be revised to 
clarify requirements concerning what actions must be taken if there is 
an indication of an inadequate cement job. There are many indicators of 
an inadequate cement job. These include lost returns, no returns to the 
mudline or failure to reach the expected height for the specific cement 
job, cement channeling, abnormal pressures, or failure of equipment. If 
any of these indicators, or others, are encountered during the cement 
job, then action must be taken to ensure the cement job is adequate. 
Such actions may include running a temperature survey, running a cement

[[Page 21515]]

evaluation log (such as an ultrasonic or equivalent bond log), or a 
combination of these or other techniques to check cement integrity by 
verifying the top of cement, density, condition, bond, etc. If the 
cement job is determined to be adequate, the results of the cement job 
determination would be submitted to the District Manager in the WAR.
    Paragraph (d) of the table in this section would be revised to 
clarify that if an operator has an inadequate cement job, the District 
Manager would have to review and approve all proposed remedial actions, 
unless immediate actions must be taken to ensure the safety of the crew 
or to prevent a well-control event. If the operator needs to take 
immediate action, a description would be required to be submitted to 
the District Manager once the action is completed. The paragraph would 
also clarify that any changes to the well program would require PE 
certification and would need to meet any other requirements imposed by 
the District Manager.
    New paragraph (k) would be added to the table in this section and 
would add clarification concerning the use of valves on drive pipes 
during cementing operations for the conductor casing, surface casing, 
or liner, and require the following to assist BSEE in assessing the 
structural integrity of the well:

--The operator would include a description in the APD of the plan to 
use a valve that includes a schematic of the valve and height above the 
water line.
--The valve would be remotely operated and full opening with visual 
observation while taking returns.
--The person in charge of observing returns would be in communication 
with the drill floor.
--The operator would record in the daily report and in the WAR if 
cement returns were observed; and
--If cement returns were not observed, the operator would have to 
contact the District Manager and obtain approval of proposed plans to 
locate the top of cement, before continuing with operations.

    These proposed additions in paragraph (k) would help BSEE assess 
the well's structural integrity and verify cement suitability to the 
mudline.
    The overall changes to this section would help BSEE assess actual 
well operations and conditions, and also would help ensure proper 
design with additional PE review.
What are the general requirements for BOP systems and system 
components? (Sec.  250.440)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.730.
What are the requirements for a surface BOP stack? (Sec.  250.441)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec. Sec.  250.733 and 250.735.
What are the requirements for a subsea BOP system? (Sec.  250.442)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.734.
What associated systems and related equipment must all BOP systems 
include? (Sec.  250.443)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec. Sec.  250.733, 250.734, and 
250.735.
What are the choke manifold requirements? (Sec.  250.444)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.736.
What are the requirements for kelly valves, inside BOPs, and drill-
string safety valves? (Sec.  250.445)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.736.
What are the BOP maintenance and inspection requirements? (Sec.  
250.446)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.739.
When must I pressure test the BOP system? (Sec.  250.447)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.737.
What are the BOP pressure tests requirements? (Sec.  250.448)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.737.
What additional BOP testing requirements must I meet? (Sec.  250.449)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.737.
What are the recordkeeping requirements for BOP tests? (Sec.  250.450)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.746.
What must I do in certain situations involving BOP equipment or 
systems? (Sec.  250.451)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.738.
What safe practices must the drilling fluid program follow? (Sec.  
250.456)
    This section would remove paragraph (j) and re-designate the other 
paragraphs. The content of current paragraph (j) would be moved to 
proposed Sec.  250.720 to clarify that this requirement applies to 
drilling, workover, completion, and abandonment operations.
What are the source control and containment requirements? (Sec.  
250.462)
    This section and heading would be entirely revised. The existing 
content of this section entitled, What are the requirements for well-
control drills? would be moved to proposed Sec. Sec.  250.710 and 
250.711.
    This proposed new section would add requirements for the operator 
to demonstrate the ability to control or contain a blowout event at the 
sea floor. This section would apply to operations using a subsea BOP or 
a surface BOP on a floating facility.
    Paragraph (a) would require the operator to determine its source 
control and containment capabilities by evaluating the performance of 
the well design to determine if a full shut-in can be achieved without 
reservoir fluids broaching the sea floor. Based on this evaluation, if 
the well can only be partially shut-in, then the operator would be 
required to establish the ability to flow and capture any residual 
fluids to a surface production and storage system.
    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. The SCCE means the capping 
stack, cap and flow system, containment dome, and/or other subsea and 
surface devices, equipment, and vessels whose collective purpose is to 
control a spill source and stop the flow of fluids into the environment 
or to contain fluids escaping into the environment. This equipment 
would need to include, but not be limited to:

--Subsea containment and capture equipment, including containment domes 
and capping stacks;
--Subsea utility equipment, including hydraulic power, hydrate control, 
and dispersant injection equipment;
--Riser systems;

[[Page 21516]]

--ROVs;
--Capture vessels;
--Support vessels; and
--Storage facilities.
    Paragraph (c) would require submittal of a description of the 
source control and containment capabilities before BSEE would approve 
an APD. The submittal to the Regional Supervisor would need to include 
the following:
--The source control and containment capabilities for controlling and 
containing a blowout event at the seafloor,
--A discussion of the determination required by paragraph (a), and
--Information showing that the operator has access to, and the ability 
to deploy, all equipment necessary to regain control of the well.
    Paragraph (d) would require that operators contact the District 
Manager and Regional Supervisor for reevaluation of the source control 
and containment capabilities if there are any well design changes or if 
any of the approved SCCE is out of service.
    Paragraph (e) would outline the maintenance, inspection, and 
testing requirements of certain identified containment equipment as 
follows:

------------------------------------------------------------------------
                                                          Additional
           Equipment                 Requirements         information
------------------------------------------------------------------------
(1) Capping stacks.............  (i) Function test    Pressure holding
                                  all pressure         critical
                                  holding critical     components are
                                  components on a      those components
                                  quarterly            that will
                                  frequency (not to    experience
                                  exceed 104 days),    wellbore pressure
                                                       during a shut-in
                                                       after being
                                                       functioned.
                                 (ii) Pressure test   Pressure holding
                                  pressure holding     critical
                                  critical             components are
                                  components on a bi-  those components
                                  annual basis, but    that will
                                  not later than 210   experience
                                  days from the last   wellbore pressure
                                  pressure test. All   during a shut-in.
                                  pressure testing     These components
                                  must be witnessed    include, but are
                                  by BSEE and a BSEE-  not limited to:
                                  approved             all blind rams,
                                  verification         wellhead
                                  organization,        connectors, and
                                                       outlet valves.
                                 (iii) Notify BSEE
                                  at least 21 days
                                  prior to
                                  commencing any
                                  pressure testing.
(2) Production safety systems    (i) Meet or exceed   ..................
 used for flow and capture        the requirements
 operations.                      set forth in 30
                                  CFR 250.800
                                  through 250.808,
                                  Subpart H.
                                 (ii) Have all
                                  equipment unique
                                  to containment
                                  operations
                                  available for
                                  inspection at all
                                  times..
(3) Subsea utility equipment...  Have all equipment   Subsea utility
                                  unique to            equipment
                                  containment          includes, but is
                                  operations           not limited to:
                                  available for        hydraulic power
                                  inspection at all    sources, debris
                                  times,               removal, hydrate
                                                       control
                                                       equipment, and
                                                       dispersant
                                                       injection
                                                       equipment.
------------------------------------------------------------------------

    All of these changes in this section are necessary for BSEE to 
properly assess an operator's ability to access and deploy appropriate 
equipment sufficient to control and contain a blowout subsea. The 
Deepwater Horizon incident demonstrated a need for the capabilities to 
control and contain subsea blowouts. Following the Deepwater Horizon 
incident, operators did not resume certain drilling operations on the 
OCS until successfully demonstrating their ability to control and 
contain a subsea blowout. Industry quickly developed the capabilities 
and equipment, and satisfactorily demonstrated to BSEE the equipment 
capabilities to ensure subsea blowout control and containment.
    The BSEE is considering applying the requirements of this section 
to other operations besides those that use a subsea BOP or surface BOP 
on a floating facility. Specifically, BSEE is soliciting comments on 
whether the source control and containment requirements should be 
applicable to wells drilled in shallow water. Please provide reasons 
for your position. If your comment addresses anticipated costs 
associated with such a requirement, please provide any available 
supporting data.
When must I submit an Application for Permit to Modify (APM) or an End 
of Operations Report to BSEE? (Sec.  250.465)
    Paragraph (b)(3) would be revised to clarify that if there is a:
--Revision to the drilling plan;
--Major drilling equipment change; or
--Plugback,
operators would have to submit an EOR, Form BSEE-0125, as required in 
proposed Sec.  250.744, within 30 days after completing the work. This 
would help ensure that BSEE has the current well information.
What records must I keep? (Sec.  250.466)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.740.
How long must I keep records? (Sec.  250.467)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.741.
What well records am I required to submit? (Sec.  250.468)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec. Sec.  250.742 and 250.743.
What other well records could I be required to submit? (Sec.  250.469)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.745.

Subpart E--Oil and Gas Well-Completion Operations

General requirements. (Sec.  250.500)
    This section would be revised to add a requirement to follow the 
applicable requirements of new Subpart G in addition to Subpart E. With 
the development of new Subpart G, BSEE would consolidate similar 
requirements regarding drilling, workover, completion, and 
decommissioning activities into a separate subpart. It is BSEE's 
intention to include additional regulations regarding similar 
operations and equipment in the new Subpart G in future regulations.
    This section would also be revised to replace the word ``shall'' 
with ``must.'' This change would clarify that the provision is 
mandatory.
Equipment movement. (Sec.  250.502)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.723.
Crew instructions. (Sec.  250.506)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.710.

[[Page 21517]]

Well-control fluids, equipment, and operations. (Sec.  250.514)
    Paragraph (d) would be removed and its content would be moved to 
proposed Sec.  250.720.
What BOP information must I submit? (Sec.  250.515)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec. Sec.  250.731 and 250.732.
Blowout prevention equipment. (Sec.  250.516)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec. Sec.  250.730, 250.733, 
250.734, 250.735, and 250.736.
Blowout preventer system tests, inspections, and maintenance. (Sec.  
250.517)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec. Sec.  250.711, 250.737, 
250.738, 250.739, and 250.746.
Tubing and wellhead equipment. (Sec.  250.518)
    This section would be revised by removing paragraph (b), 
redesignating the rest of the paragraphs to reflect the removal of 
paragraph (b), and adding new paragraphs (e) and (f) to clarify packer 
and bridge plug requirements. The content of paragraph (b) would be 
moved to proposed Sec.  250.722 and would clarify that these 
requirements apply to drilling, workover, completion, and abandonment 
operations.
    New paragraph (e) would add packer and bridge plug requirements 
including:
--Adherence to newly incorporated API Spec. 11D1, Packers and Bridge 
Plugs;
--Production packer setting depth to allow for a sufficient column of 
weighted fluid for hydrostatic control of the well; and
--Production packer setting depth criteria.
    New paragraph (f) would require, in your APM, a description and 
calculations of how the production packer setting depth was determined.

Subpart F--Oil and Gas Well-Workover Operations

General requirements. (Sec.  250.600)
    This section would be revised to add the requirement to follow the 
applicable provisions of new Subpart G in addition to Subpart F. With 
the new development of Subpart G, BSEE is consolidating similar 
requirements regarding drilling, workover, completion, and 
decommissioning activities. It is BSEE's intention to include 
additional regulations regarding similar operations and equipment in 
new Subpart G in future regulations.
    This section would also be revised to replace the word ``shall'' 
with ``must.'' This change would clarify that the provision is 
mandatory.
Equipment movement. (Sec.  250.602)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.723.
Crew instructions. (Sec.  250.606)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.710.
Well-control fluids, equipment, and operations. (Sec.  250.614)
    Paragraph (d) would be removed and its content would be moved to 
proposed Sec.  250.720.
What BOP information must I submit? (Sec.  250.615)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec. Sec.  250.731 and 250.732.
Coiled tubing and snubbing operations. (Sec.  250.616)
    The section would be revised by renaming the section heading to 
``Coiled tubing and snubbing operations,'' removing paragraphs (a) 
through (e), and re-designating paragraphs (f) through (h) as (a) 
through (c). The content of existing paragraphs (a) through (e) would 
be moved to proposed Sec. Sec.  250.730 and 250.733 through 250.736.
Blowout preventer system testing, records, and drills. (Sec.  250.617)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec. Sec.  250.711, 250.737, and 
250.746.
What are my BOP inspection and maintenance requirements? (Sec.  
250.618)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.739.
Tubing and wellhead equipment. (Sec.  250.619)
    This section would be revised by removing paragraph (b), 
redesignating the rest of the paragraphs to reflect the removal of 
paragraph (b), and adding new paragraphs (e) and (f) to clarify packer 
and bridge plug requirements. The content of paragraph (b) would be 
moved to proposed Sec.  250.722.
    New paragraph (e) would add packer and bridge plug requirements for 
when operators pull and reinstall packers and bridge plugs, including:
--Adherence to newly incorporated API Spec. 11D1, Packers and Bridge 
Plugs;
--Production packer setting depth to allow for a sufficient column of 
weighted fluid for hydrostatic control of the well; and
--Production packer setting depth criteria.
    This new paragraph would codify existing BSEE policy to ensure 
consistent permitting. The incorporation of API Spec. 11D1 would 
enhance packer and bridge plug reinstallation and ensure conformance to 
industry specifications and good industry practices not previously 
covered in BSEE regulations.
    New paragraph (f) would require, in the APM, a description and 
calculation of how the production packer setting depth was determined.

Subpart G--Well Operations and Equipment

    This part of the section-by-section will not address any regulatory 
provisions that BSEE proposes to move without change from existing 
subparts to the new subpart G because the proposed moves in regulatory 
text are discussed above. However, this portion of the section-by-
section will explain existing language that BSEE proposes to revise or 
add as new provisions.
General Requirements
    What operations and equipment does this subpart cover? (Sec.  
250.700)
    This proposed section explains that new Subpart G would apply to 
drilling, completion, workover, and decommissioning activities and 
equipment. New Subpart G would contain common requirements for these 
activities. Every section in Subpart G would be applicable to drilling, 
completion, workover, and decommissioning activities, unless explicitly 
stated otherwise.
May I use alternate procedures or equipment during operations? (Sec.  
250.701)
    Content in this proposed section is similar to existing Sec.  
250.408. This proposed section would explain that operators may seek 
approval to use alternate procedures or equipment following the process 
set forth in Sec.  250.141. This section would also specify that the 
proposed alternate procedures and equipment must be discussed in the 
APD or APM. This section would make the information in

[[Page 21518]]

Sec.  250.408 applicable to all operations covered by this subpart.
May I obtain departures from these requirements? (Sec.  250.702)
    The content of this proposed section is similar to existing Sec.  
250.409. This proposed section would explain that operators may request 
departures from the regulations in this subpart by using the procedure 
set forth in Sec.  250.142. Also, this section would clarify what would 
be required for the departure request. Another addition to this section 
would require that the departure request be discussed in the APD or 
APM.
What must I do to keep wells under control? (Sec.  250.703)
    The content of this proposed section was moved from existing Sec.  
250.401. Language in this section would be revised to ensure 
applicability to all operations covered under this subpart, and to 
require the use of equipment that is designed, tested, and rated for 
the most extreme conditions to which the equipment will be exposed 
while in service. This section would also require that personnel be 
trained according to the provisions of Subparts O and S. These subparts 
outline minimum training requirements. The BSEE expects personnel 
performing operations to be trained and knowledgeable of their required 
actions and duties.
Rig Requirements
What instructions must be given to personnel engaged in well 
operations? (Sec.  250.710)
    The content of this proposed section was moved from existing 
Sec. Sec.  250.462, 250.506, and 250.606. This section would require 
personnel engaged in well operations to be instructed in safety 
requirements, possible hazards, and general safety considerations as 
required by Subpart S, prior to engaging in operations.
    This proposed section would clarify that the well-control plan must 
contain instructions for personnel about the use of each well-control 
component of the BOP system, and include procedures for shearing pipe 
and sealing the wellbore in the event of a well control or emergency 
situation before maximum anticipated surface pressure (MASP) conditions 
are reached. These changes would establish better proficiency for 
personnel using well-control equipment.
What are the requirements for well-control drills? (Sec.  250.711)
    The content of this proposed section was moved from existing 
Sec. Sec.  250.462, 250.517(f), 250.617(c), and 250.1707(c). This 
section would add minor revisions to make the requirement applicable to 
all drilling, completion, workover, and decommissioning operations 
covered under this subpart. This section would also clarify that the 
same drill may not be repeated consecutively. These proposed changes 
would establish better proficiency for personnel using well-control 
equipment.
What rig unit movements must I report? (Sec.  250.712)
    The content of this proposed section was moved from existing Sec.  
250.403 with the following revisions and additions:
    Paragraph (a) would be revised to add rig movement reporting 
requirements for all rig units moving on and off locations. Rig units 
include MODUs, platform rigs, snubbing units, wire-line units used for 
non-routine operations, and coiled tubing units. This paragraph would 
make rig movement reporting requirements applicable to all rigs 
conducting operations covered under proposed Subpart G. The deadline 
for notifying the District Manager about rig movements, using the Rig 
Movement Notification Report (Form BSEE-0144), would increase from 24 
to 72 hours. This proposed change would allow BSEE to better anticipate 
upcoming operations and coordinate applicable permitting.
    Paragraph (a)(2) would be revised to clarify that if operators 
anticipate moving off location less than 72 hours after initially 
moving onto location, the anticipated movement schedule may be included 
on Form BSEE-0144. This clarification would be necessary if you have, 
for example, coiled tubing and batch operations and there is not enough 
time to submit the rig movement 72 hours in advance. Form BSEE-0144 has 
been revised from its current version to reflect changes based on the 
proposed rule. Revised Form BSEE-0144 is included in the Appendix to 
this proposed rule.
    Existing paragraph (c) would be replaced with a new paragraph (c) 
requiring notifications if a MODU or platform rig is to be warm or cold 
stacked. The notifications for MODUs or platform rigs would include:
--Where the rig is coming from;
--Location where it would be positioned;
--If it would be manned or unmanned; and
--Any changes in the stacking location.
    Proposed paragraph (c) would also allow BSEE to have a better 
understanding of where MODUs and platform rigs are located in case of 
emergency situations possibly affecting surrounding infrastructure.
    New paragraph (d) would require 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.
    New paragraph (e) would also require notification to the District 
Manager if a drilling rig enters OCS waters regarding where the 
drilling rig is coming from. The BSEE expects that this notification 
would provide information about the last location where the drilling 
rig was conducting operations, or the shipyard location if it is coming 
from a shipyard, for either a new build or repair. This notification 
would assist BSEE in verifying the location and movement of the rigs. 
This notification would also help BSEE verify rig fitness and 
documentation requirements to allow the rig to conduct operations on 
the OCS as outlined in proposed Sec.  250.713.
    New paragraph (f) would clarify 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) would be 
required. This revision would clarify to operators when a revision or 
update would be required.
What must I provide if I plan to use a mobile offshore drilling unit 
(MODU) or lift boat for well operations? (Sec.  250.713)
    The content of this proposed section would be moved from existing 
Sec.  250.417. This section would make the requirements applicable to 
all operations covered under this subpart.
    Revised paragraph (g) would add current monitoring requirements. 
Current monitoring is discussed in BSEE NTL 2009-G02, Ocean Current 
Monitoring. These proposed changes would help provide better 
consistency in permits. Upon publication of the final rule, BSEE would 
rescind BSEE NTL 2009-G02.
Do I have to develop a dropped objects plan? (Sec.  250.714)
    This section would codify some of the language from BSEE NTL 2009-
G36, Using Alternate Compliance in Safety Systems for Subsea Production 
Operations, to help avoid prolonged damage to subsea infrastructure and 
aid operators' and BSEE's response to a dropped object.
    This proposed new section would outline the requirements for 
developing a dropped objects plan. This proposed section would be 
applicable to all floating rig units in an area with subsea

[[Page 21519]]

infrastructure. This section would specify the requirements of a 
dropped objects plans. The plan would be required to include:
--A description and plot of the path the rig would take while running 
and pulling the riser;
--A plat showing the location of any subsea wells, production 
equipment, pipelines, and any other identified debris;
--Modeling of a dropped object's path for various material forms, such 
as a tubular (e.g., riser or casing) and box (e.g., BOP or tree) with 
consideration given to metocean conditions;
--A description of 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
--Any additional information required by the District Manager.
Do I need a global positioning system (GPS) for MODUs and jack-ups? 
(Sec.  250.715)
    This proposed new section would codify existing BSEE NTL 2013-G01, 
Global Positioning System (GPS) for Mobile Offshore Drilling Units 
(MODUs). The proposed requirements for GPSs include:
--Providing a robust and reliable means of monitoring the position and 
tracking the path in real-time if the MODU or jack-up moves from its 
location during a severe storm;
--Installing and protecting the tracking system's equipment to minimize 
the risk of the system being disabled;
--Placing the GPS transponders in different locations for redundancy to 
minimize risk of system failure;
--Capability of transmitting data for at least 7 days after a storm has 
passed;
--Recording the GPS location data if the MODU or jack-up is moved off 
location in the event of a storm; and
--Providing BSEE with real-time access to the MODU or jack-up location 
data.
    The BSEE would use the GPS data in emergency situations to minimize 
potential damage to the offshore infrastructure.
Well Operations
When and how must I secure a well? (Sec.  250.720)
    The content of this proposed section would be moved from existing 
Sec. Sec.  250.402, 250.456(j), 250.514(d), 250.614(d), and 250.1709, 
and would contain the following revisions and additions:
    Paragraph (a) would add that the District Manager must be notified 
when operations are interrupted. This paragraph would also add an 
example to the list of events that would warrant interruption of 
operations (currently in Sec.  250.402(a)). Specifically, if there is 
any observed flow outside the well's casing, operators would have to 
interrupt operations. The requirement to interrupt operations for the 
additional event of observing flow outside the well's casing would 
protect against a failure of the well's structural foundation and a 
possible environmental incident. The requirement to notify the District 
Manager would give BSEE awareness of interrupted operations and allow 
for appropriate regulatory response. This paragraph would also require 
a negative test in accordance with proposed Sec.  250.721 to ensure 
wellbore and barrier integrity before removing a subsea BOP stack or 
surface BOP stack on a mudline suspension well.
    Paragraph (a)(2) would also clarify that if there is not enough 
time to install the required barriers or if special circumstances 
occur, the District Manager may approve alternate procedures or 
barriers in accordance with Sec.  250.141. Some options that could be 
considered include the use of:
--Blind or blind-shear rams;
--Pipe rams and an inside BOP (if hydrocarbons are not exposed in the 
open hole);
--A drill string hang-off tool; and/or
--Storm packers.

This section would help ensure that during the events previously 
discussed, the well would be properly secured.

    New paragraph (b) would be added to consolidate the content of 
existing Sec. Sec.  250.456(j), 250.514(d), 250.614(d), and 250.1709.
What are the requirements for pressure testing casing and liners? 
(Sec.  250.721)
    The content of this proposed section would be moved from existing 
Sec. Sec.  250.423 and 250.425, and would include the following 
revisions and additions:
    Paragraph (a) would increase the minimum test pressure 
specification for conductor casing, excluding subsea wellheads, from 
200 psi in existing regulations (Sec.  250.423(a)(2)) to 250 psi.
    Paragraph (b) would require operators to test each drilling liner 
and liner-lap before any further operations are continued in the well.
    Paragraph (c) would contain requirements for testing each 
production liner and liner-lap.
    Paragraph (d) would clarify that the District Manager may approve 
or require other casing test pressures.
    Proposed new paragraph (e) would add the requirement that operators 
follow additional pressure test requirements when they plan to produce 
a well. If a well would be fully cased and cemented, the operator would 
have to pressure test the well to the maximum anticipated shut-in 
tubing pressure before perforating the casing or liner. If a well would 
be an open-hole completion, the operator would have to pressure test 
the entire well to the maximum anticipated shut-in tubing pressure 
before drilling the open-hole section of the well.
    Proposed paragraph (f) would add a requirement for a PE 
certification of proposed plans to provide a proper seal if there is an 
unsatisfactory pressure test.
    Proposed paragraph (g) would require a negative pressure test on 
all wells that use a subsea BOP stack or wells with mudline suspension 
systems and outline the requirements for those tests.
What are the requirements for prolonged operations in a well? (Sec.  
250.722)
    The content of this proposed section would be moved from existing 
Sec. Sec.  250.424, 250.518(b), and 250.619(b), with revisions made to 
clarify the requirements for well integrity for operations continuing 
longer than 30 days from the previous casing test. If well integrity 
has deteriorated to a level below minimum safety factors, this section 
would require repairs or installation of additional casing and 
subsequent pressure testing, as approved by the District Manager. To 
obtain approval, a PE certification must be provided showing that he or 
she reviewed and approved the proposed changes. The results of the 
pressure test would be submitted to the appropriate District Manager. 
These changes help ensure a proper wellbore integrity determination to 
allow operations to continue.
What additional safety measures must I take when I conduct operations 
on a platform that has producing wells or has other hydrocarbon flow? 
(Sec.  250.723)
    This proposed section would reflect a combination of existing 
Sec. Sec.  250.406, 250.502, and 250.602.
    Paragraph (b) would be modified from existing Sec.  250.406(a) to 
clarify that the emergency shutdown station would be for the production 
system. This revision would ensure that rig units would be able to 
shut-in the production system of the host facility.
    Paragraphs (d) and (e) would make minor revisions to clarify 
applicability to all operations covered under proposed Subpart G and to 
divide the paragraphs to make them easier to read and understand.

[[Page 21520]]

What are the real-time monitoring requirements? (Sec.  250.724)
    This proposed new section would include a requirement covering 
real-time monitoring by onshore personnel of the BOP system, fluid 
handling system of the rig, and downhole conditions. This section would 
be added, in part, based on multiple recommendations from various 
Deepwater Horizon investigation reports. Having the real-time data 
available to onshore personnel would increase the level of oversight 
throughout operations. Onshore personnel could review data and help rig 
personnel conduct operations in a safe manner. Also, onshore personnel 
would be able to assist the rig crew in identifying and evaluating 
abnormalities or unusual conditions while conducting operations. This 
section would require that BSEE be provided access to the real-time 
monitoring facility, upon request. Operators would also be required to 
record and retain the data at an onshore location for recordkeeping 
purposes and to make it accessible to BSEE upon request. If real-time 
monitoring capability is lost during operations, the operator would be 
required to immediately notify the District Manager, who may require 
other measures until the real-time monitoring capability is restored.
    The BSEE is considering expanding the requirements of this section 
to other operations, not only those conducted with a subsea BOP or a 
surface BOP on a floating facility or on any BOP operating in an HPHT 
environment. The BSEE is specifically soliciting comments on whether 
the real-time monitoring should be required for all well operations, 
including shallow water shelf operations. Please provide reasons for 
your position. If your comment addresses anticipated costs associated 
with such a requirement, please provide any available supporting data.
Blowout Preventer (BOP) System Requirements
What are the general requirements for BOP systems and system 
components? (Sec.  250.730)
    This proposed section would reflect a combination of existing 
Sec. Sec.  250.416, 250.440, 250.516, 250.616, and 250.1706 and would 
also include the following revisions and additions:
--Require compliance with 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.
--Clarify that the working-pressure rating of each BOP component must 
exceed the MASP as defined for their operation, such as drilling, 
completion, or workover. For a subsea BOP, the MASP would be taken at 
the mudline.
--Add a new performance measure for operators which would require the 
BOP to be able to meet anticipated wellbore conditions and still be 
able to perform its expected function of sealing the well.
    Proposed paragraph (a) would require compliance with the following 
API and ANSI/API documents:
    API Standard 53--BOP system and components would have to be 
designed, installed, maintained, inspected, tested, and used according 
to API Standard 53. The API Standard 53 would be incorporated into the 
regulations; however, if there is a conflict between API Standard 53 
and these regulations, operators would have to follow the requirements 
of these regulations (i.e., BSEE is requiring that surface BOPs on 
floating facilities have the same dual shearing requirement as subsea 
BOPs; API Standard 53 allows for an opt out of this standard with a 
risk assessment that is not included in the proposed rule). Currently, 
BSEE regulations only incorporate select sections of API RP 53 
(accumulators, maintenance, and inspections). By incorporating new API 
Standard 53, BSEE would greatly enhance the BOP requirements. As 
previously discussed in the Background section, API Standard 53 is the 
latest industry consensus standard to update and enhance BOP 
requirements. After the Deepwater Horizon incident, multiple 
investigations focused on the BOP stack. Every investigation made 
multiple recommendations to improve the performance and regulation of 
BOPs. Industry recognized the need to update the previous edition of 
API RP 53. During the process of updating API RP 53, industry 
determined that the document needed more substantive content and needed 
to be raised from an RP to an industry standard. The current API 
Standard 53 contains the industry consensus standards concerning 
engineering and operating practices regarding BOP reliability and use. 
Included in API Standard 53 is a list of normative references (industry 
standards) that are indispensable to fully utilizing API Standard 53 
and to ensure safe and reliable equipment. The normative references 
include:
--ANSI/API Spec. 6A, Specification for Wellhead and Christmas Tree 
Equipment;
--API Spec. 16A, Specification for Drill-through Equipment;
--ANSI/API Spec. 16C, Specification for Choke and Kill Systems;
--API Spec. 16D, Specification for Control Systems for Drilling Well-
control Equipment and Control Systems for Diverter Equipment; and
--ANSI/API Spec. 17D, Design and Operation of Subsea Production 
Systems--Subsea Wellhead and Tree Equipment.
    Sections of these industry standards apply to BOP systems. The BSEE 
specifically proposes to incorporate these standards into the 
regulations as applied to BOP systems to emphasize their significance 
and make clear the industry standards that must be followed. The BSEE 
is also requesting comments concerning whether any sections of these 
documents should not be incorporated by reference.
    For general reference, the following table shows relevant topics 
from each of these industry standards. This table is not a complete 
list of applicable sections, but is intended to show how these sections 
interact with API Standard 53.

------------------------------------------------------------------------
                                             Applicable topics in API
           Industry standard               standard 53 (but not limited
                                                       to):
------------------------------------------------------------------------
ANSI/API Spec. 6A, Specification for     Flanges and hubs, Bolting and
 Wellhead and Christmas Tree Equipment;   clamps, Gaskets, Choke and
                                          kill lines, Equipment marking
                                          and storage, Equipment
                                          modifications, Maintenance and
                                          testing.
API Spec. 16A, Specification for Drill-  Flanges and hubs, Bolting and
 through Equipment;                       clamps, Gaskets, Choke and
                                          kill lines, Equipment marking
                                          and storage, Maintenance and
                                          testing.
ANSI/API Spec. 16C, Specification for    Choke manifolds, Choke and kill
 Choke and Kill Systems;                  lines.
API Spec. 16D, Specification for         Control systems, Maintenance
 Control Systems for Drilling Well-       and testing. Electro-hydraulic
 control Equipment and Control Systems    and multiplex control systems,
 for Diverter Equipment;                  Auxiliary equipment,
                                          Accumulators.

[[Page 21521]]

 
ANSI/API Spec. 17D, Design and           Flanges and hubs, Bolting and
 Operation of Subsea Production Systems   clamps, Choke and kill lines,
 -- Subsea Wellhead and Tree Equipment;   Equipment marking and storage,
                                          Maintenance and testing.
------------------------------------------------------------------------

    Paragraph (a)(3) would require that pipe and variable bore rams be 
capable of closing and sealing on drill pipe, workstrings, or tubing 
under MASP with the proposed regulator settings of the BOP control 
system. This new paragraph would help ensure the BOP control regulator 
set points are sufficient to ensure closure and sealing of the pipe 
rams.
    Paragraph (a)(4) would require a current set of approved schematics 
to be on the rig and at an onshore location. It would also require that 
if there are any modifications to the BOP or control system that will 
change your schematics, operations would be suspended until the 
operator obtains approval of the new schematics from the District 
Manager.
    Paragraph (b) would require that operators design, fabricate, 
maintain, and repair the BOP system pursuant to the requirements 
contained in this subpart, OEM recommendations unless otherwise 
directed by BSEE, and recognized engineering practices. Personnel 
performing any repair or maintenance would be required to follow any 
OEM training or certification recommendations unless otherwise directed 
by BSEE.
    Paragraph (c) would adopt the failure reporting procedures 
contained in certain API documents. The BSEE would add specific time 
frames for the completion of these procedures consistent with other 
previously incorporated API standards and add a requirement that BSEE 
be notified of any changes to operating or repair procedures adopted to 
address or in response to a failure. This would allow BSEE to notify 
the industry and international community of any significant safety 
issues related to equipment design, and potentially prevent future 
incidents.
    Paragraph (d) would require that if an operator plans to use a BOP 
stack manufactured after the effective date of the final rule, the 
operator must use one manufactured pursuant to API Spec. Q1, 
Specification for Quality Management System Requirements for 
Manufacturing Organizations for the Petroleum and Natural Gas Industry. 
Currently, BSEE uses API Spec. Q1 in association with the manufacture 
of safety and pollution prevention equipment. The API Spec. Q1 outlines 
the requirements for development of a quality management system that 
provides for continual improvement, emphasizing defect prevention and 
the reduction of variation. This quality management system facilitates 
consistent and reliable manufacture. Also added to this section is the 
option to seek approval to use quality assurance programs other than 
API Spec. Q1.
    The BSEE requests comments concerning whether other industry 
standards should be incorporated into the regulations that ensure that 
BOP equipment performs as designed during its service life.
What information must I submit for BOP systems and system components? 
(Sec.  250.731)
    This proposed section would reflect a combination of existing 
Sec. Sec.  250.416, 250.515, 250.615, and 250.1705 with the following 
revisions and additions:
    The introductory text would reflect that the requirements of BOP 
description submittals would apply to APDs, APMs, and other required 
submittals. The introductory text would also clarify that the BOP 
descriptions would not have to be resubmitted with any subsequent 
permit application or submittal after the initial application that BSEE 
approved or accepted when the operator moved onto location unless the 
operator makes changes to what was initially approved or the operator 
moves off location from that well. This introductory text would also 
clarify that if the operator is not required to resubmit the BOP 
information in subsequent applications, then the operator must document 
why the submittal is not required--in other words, the operator would 
need to reference the previously approved or accepted application or 
submittal and state that no changes have been made. The information 
required under this section would increase the quality of submitted 
documents and enhance BSEE's review and permitting process.
    Paragraph (a) would require submission of the following new BOP 
descriptions:

--Pressure ratings of BOP equipment;
--Both surface and corresponding subsea pressures for a subsea BOP 
test;
--Rated capacities of the fluid-gas separator system;
--Control fluid volumes needed to operate each component;
--Control system pressure and regulator settings needed to achieve an 
effective seal of each ram BOP under MASP;
--Number and volume of accumulator bottles and bottle banks (for subsea 
BOPs, include both surface and subsea bottles);
--Accumulator pre-charge calculations (for a subsea BOP system, include 
both the surface and subsea calculations);
--All locking devices; and
--Control fluid volume calculations for the accumulator system (for a 
subsea BOP system, include both the surface and subsea volumes).

    Submission of these descriptions would enhance BSEE's review and 
understanding of the entire BOP system.
    Paragraph (b) would add the following new schematic drawing 
requirements:

--Labeling the control system alarms and set points;
--Including all locking devices;
--Including control station locations;
--Labeling the type of shear ram(s), size range for variable bore 
ram(s), size of any fixed ram(s), size of choke and kill lines, and 
size of subsea BOP gas bleed line(s); and
--Including 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.

    Paragraph (c) would reflect content from existing Sec.  250.416(e) 
and require submission of the following certifications by a BSEE-
approved verification organization verifying that:

--Test data clearly demonstrates the shear ram(s) will shear the drill 
pipe at the water depth as required in Sec.  250.732;
--The BOP was designed, tested, and maintained to perform at the most 
extreme anticipated conditions; and
--The accumulator system has sufficient fluid to function the BOP 
system without assistance from the charging system.

    Paragraph (d) would require additional certification if an operator 
uses a subsea BOP, a BOP in an HPHT environment, or a surface BOP on a 
floating facility. The certification would include verification of the 
following:

--The BOP stack is designed for the specific equipment on the rig and 
for the specific well design;

[[Page 21522]]

--The BOP stack has not been compromised or damaged from previous 
service; and
--The BOP stack will operate in the conditions in which it will be 
used.

    The BSEE is considering expanding the requirements of this 
paragraph to all BOPs. The BSEE is specifically soliciting comments on 
whether this certification requirement should be applied to all well 
operations, including shallow water shelf operations and operations 
with surface BOPs. Please provide reasons for your position. If your 
comment addresses anticipated costs associated with such a requirement, 
please provide any available supporting data.
    Paragraph (e) would be entirely new for subsea BOPs. This paragraph 
would require a listing of the functions with sequences and timing of 
autoshear, deadman, and emergency disconnect sequence (EDS) systems. 
These emergency systems were the topic of many Deepwater Horizon 
investigations and multiple associated recommendations. It is BSEE's 
position that submission of this additional information would improve 
BSEE's ability to oversee the use of these critical systems.
    Paragraph (f) would add a certification requirement stating that 
the Mechanical Integrity Assessment Report required in proposed 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.
    The items covered under this section have not been routinely 
submitted to BSEE or obtained by the operators charged with 
responsibility to maintain well control, and BSEE believes these items 
are important to fully understand the entire BOP system and to verify 
that it would perform in an acceptable manner.
What are the BSEE-approved verification organization requirements for 
BOP systems and system components? (Sec.  250.732)
    This proposed section would reflect a combination of existing 
Sec. Sec.  250.416, 250.515, 250.615, and 250.1705, along with new 
requirements. This proposed section 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. The third-party 
verification and documentation by a BSEE-approved verification 
organization would enhance the BSEE review during the permitting 
process. The objective is to have this equipment monitored during its 
entire lifecycle by an independent third-party to verify compliance 
with BSEE requirements, OEM recommendations, and recognized engineering 
practices. The BSEE believes that the importance and complexity of BOP 
systems and the fact that they might be operated at various worldwide 
locations throughout their service life warrants a thorough and regular 
assessment of the systems and verification that design, installation, 
maintenance, inspection, and repair activities are documented and 
traceable.
    The list of approved verification organizations would be limited to 
those that can clearly demonstrate the capability to perform this 
comprehensive detailed technical analysis.
    Paragraph (a) would clarify that BSEE will maintain a list of BSEE-
approved verification organizations, and also outline criteria to 
become a BSEE-approved verification organization.
    Paragraph (b) would be applicable to any operation that requires 
any type of BOP, and would require verification of shear testing, 
pressure integrity testing, and calculations for shearing and sealing 
pressures for all pipe to be used. Each of these verifications must 
demonstrate outlined specific requirements.
    Paragraph (c) would require a special verification process for BOP 
and related equipment being used in HPHT environments because the 
design conditions required for an HPHT environment exceed the limits of 
existing engineering standards. The use of a BSEE-approved verification 
body would provide BSEE with an additional layer of review and 
verification at all steps in the development process. The paragraph 
makes it clear that the operator has the burden of clearly 
demonstrating the reliability of the equipment through a comprehensive 
review of the design, testing, and fabrication process.
    Paragraph (d) would require an annual submittal of a Mechanical 
Integrity Assessment Report for a subsea BOP, a BOP used in HPHT 
environment, or a surface BOP on a floating facility. This paragraph 
would outline the requirements of a Mechanical Integrity Assessment 
report.
    Paragraph (e) would require operators to make all documentation 
that supports the requirements of this section available to BSEE upon 
request.
    The BSEE believes that using a third-party to verify the testing 
and qualification of BOP equipment would ensure consistent results and 
provide a reasonable assurance of the performance of this equipment. 
Based on previous studies available on the Web site of BSEE's 
Technology Assessment Program (available at: https://www.bsee.gov/Technology-and-Research/Technology-Assessment-Programs/Index), BSEE 
believes that the development of more rigorous industry testing 
protocols is critical to demonstrating the performance of BOP 
equipment.
    The BSEE requests comments on the following issues associated with 
this section:

--On the issue of standardized test protocols and whether there are any 
specific procedures that should be considered for adoption.
--On the importance of applying forces in tension or compression during 
the actual shearing tests.
--On what criteria should be used to qualify a BSEE-approved 
verification organization and whether OEMs should be considered for the 
program.
--On the issue of updating test protocols and criteria used by 
verification organizations, given the likelihood of future improvements 
to BOP technology.
What are the requirements for a surface BOP stack? (Sec.  250.733)
    This proposed section would be a combination of existing Sec. Sec.  
250.441, 250.443, 250.516, 250.616, and 250.1706 with the following 
revisions and additions:
    Paragraph (a) would contain revisions clarifying its applicability 
to all operations covered under Subpart G.
    Paragraph (a) would also clarify that the blind-shear rams would 
have to be able to shear the drill pipe, workstring, tubing, and any 
electric-, wire-, or slick-line. If the blind-shear ram could not cut 
and seal electric-, wire-, or slick-line under MASP, an alternative 
cutting device would be required on the rig floor during operations 
that require their use, to cut the wire before closing the BOP. This 
requirement would be necessary to ensure that there are means to cut 
the wire in the hole, even if it is an external cutting device.
    Paragraph (b) would codify BSEE policy and would:

--Clarify that when using a surface BOP on a floating production 
facility:
--the same BOP requirements apply as in Sec.  250.734(a)(1), and
--a dual bore riser configuration would be required for risers 
installed after the effective date of this rule before drilling or 
operating in any hole section or interval where hydrocarbons may be 
exposed to the well;
--Require risers to meet the design requirements of API RP 2RD;

[[Page 21523]]

--Clarify that the annulus between the risers must be monitored during 
operations;
--Require a description of the monitoring plan in the APD or APM, 
including how you would secure the well if a leak is detected; and
--Clarify that the inner riser for a dual riser configuration is 
subject to the requirements for testing the casing or liner.

    API Standard 53 does not impose dual shear requirements for surface 
BOPs on floating facilities; however, this proposed rule would require 
dual shears. If there is any conflict between the documents 
incorporated by reference and these regulations, the operator would be 
required to follow these regulations.
    Proposed paragraph (c) would contain content from current Sec.  
250.443(c) for surface BOP stacks to contain one side outlet for a 
choke line and one side outlet for a kill line. There would be a new 
requirement that the outlet valves must hold pressure from both 
directions.
    Existing Sec.  250.441(d) would not be carried forward to proposed 
Sec.  250.733 because it is unnecessary to state that the regulations 
covered under this subpart are required.
    Proposed paragraph (d) would contain content from a portion of 
existing Sec.  250.443(d). An addition, this paragraph would require 
that the outlet valves must be full-bore, full-opening. This would 
prevent leaks into and out of the BOP stacks.
    Proposed paragraph (e) would require installation of hydraulically 
operated locks.
    Proposed Paragraph (f) would add specific requirements for a 
surface BOP used in HPHT environments, if operations are suspended to 
make repairs to any part of the BOP system. The BSEE is considering 
requiring the same dual shear ram requirements in proposed Sec.  
250.734(a)(1) for BOPs used in HPHT environments. The BSEE is 
requesting comments on requiring dual shear rams for BOPs used in HPHT 
environments, and how long it would take to comply with the dual shear 
requirement for BOPs used in HPHT environments. If your comment 
addresses anticipated costs associated with such a requirement, please 
provide any available supporting data.
What are the requirements for a subsea BOP system? (Sec.  250.734)
    This proposed section would reflect a combination of existing 
Sec. Sec.  250.442, 250.443, 250.516, 250.616, and 250.1706.
    Proposed paragraph (a)(1) would require two BOPs equipped with 
shear rams. This new requirement would correspond to API Standard 53, 
and would increase the shearing capabilities of a BOP stack. This 
paragraph would also clarify that both shear rams would have to be able 
to shear at any point along the tubular body of any drill pipe 
(excluding tool joints, bottom-hole tools, and bottom hole assemblies, 
which include heavy-weight pipe or collars), workstring, and tubing, as 
well as be able to shear the liner casing landing string, shear sub on 
subsea test tree, and any electric-, wire-, or slick-line in the hole 
under MASP. At least one shear ram would have to be capable of sealing 
the wellbore under MASP after shearing. Any non-sealing shear rams 
would have to be installed below the sealing shear rams. These 
requirements would help ensure that shearing the pipe and sealing the 
wellbore could be achieved.
    Proposed paragraph (a)(3) would clarify that the accumulator 
capacity would have to be located subsea to provide closure of the BOP 
components and operate critical functions in case of a loss of the 
power fluid connection to the surface. The critical functions and 
components would be defined as each shear ram, choke and kill side 
outlet valves, one pipe ram, and lower marine riser package (LMRP) 
disconnect. This paragraph would also require that the subsea 
accumulator system have the capability of delivering fluid to each ROV 
function i.e., flying leads. The accumulator would be required to have 
dedicated independent bottles for the autoshear, deadman, and EDS 
systems. The subsea accumulator would have to be capable of performing 
under MASP. These new requirements would ensure that the subsea 
accumulators would be able to provide fluid to each ROV function. The 
reference to API RP 53 in current Sec.  250.442(c) would not be carried 
forward to the proposed paragraph.
    Proposed paragraph (a)(4) would include requirements that the ROV 
would have to be able to perform critical BOP functions, including 
opening and closing each shear ram, choke and kill side outlet valves, 
all pipe rams, and the LMRP disconnect under MASP conditions. This 
paragraph would also include a new requirement that the ROV panels must 
be compliant with API RP 17H.
    Proposed paragraph (a)(5) would require communication between the 
ROV crew and the rig personnel familiar with the BOP. This 
communication would help ROV crews perform proper operations and better 
determine appropriate BOP conditions.
    Proposed paragraph (a)(6) would include requirements of an 
autoshear, deadman, and EDS system for dynamically positioned rigs, and 
autoshear and deadman systems for moored rigs. This paragraph would 
also require each emergency function to include both shear rams closing 
under MASP. The sequencing of each emergency function would have to 
provide for the lower shear ram beginning closure before the upper 
shear ram would begin closure. Also, the control system for the 
emergency functions would be required to be a fail-safe design, and 
each step in the logic would have to be independent of the previous 
step being completed. These revisions to the emergency functions would 
help provide the best means to carry out the intended functions. In the 
past, some BOP systems have only included one shear ram in the 
emergency functions, and these additions would ensure including both 
shear rams in those functions.
    Proposed paragraph (a)(7) would add acoustic system requirements 
similar to current Sec.  250.442(f)(3). The revision puts the acoustic 
system option into its own designated paragraph. It would expand what 
must be provided to the BSEE District Manager if an acoustic system is 
to be used for a subsea BOP.
    Proposed paragraph (a)(12) would be revised to connect this 
paragraph to Sec.  250.720(b). This revision would clarify the intent 
of this existing regulation and ensure that procedures are submitted 
for review and approval in permits.
    Proposed paragraph (a)(14) would revise a current requirements from 
Sec. Sec.  250.443(c) and (d), 250.516, 250.616, and 250.1706. The 
proposed rule would require subsea BOPs to contain two side outlets for 
the choke line and two side outlets for the kill line. Each side outlet 
would be required to have two full-bore, full-opening valves. The 
proposed section would require these valves to be pressure-holding from 
both directions. This section would also require a side outlet below 
each sealing shear ram. Operators may have a pipe ram or rams between 
the shearing ram and side outlet. This would enhance well-control 
capability for subsea BOPs.
    Proposed paragraph (a)(15) would require operators to install a gas 
bleed line with two valves for the annular preventer. If dual annulars 
would be installed with one on the LMRP and one on the lower BOP stack, 
each annular would have to have a gas bleed line. The two valves would 
need to be able to hold pressure from both directions.

[[Page 21524]]

    Proposed paragraph (a)(16) would require subsea BOP systems to have 
mechanisms capable of:

--Positioning the entire pipe, including connection, completely within 
the area of the shearing blade necessary to ensure shearing would occur 
any time the shear rams are activated. This mechanism could not be 
another ram BOP or annular preventer;
--Mitigating compression of the pipe stub between the shearing rams. 
(This provision was added based upon multiple Deepwater Horizon 
investigation recommendations; the blind shear ram (BSR) could not 
fully close and seal because the drill pipe was forced to the side of 
the wellbore and outside of the BSR cutting surface); and
--Monitoring the subsea electronic module batteries in the BOP control 
pods.

    New paragraph (b) would codify BSEE policy and require that if 
operations are suspended to make repairs to the BOP, operations would 
have to be stopped at a safe downhole location. This section would also 
require that before resuming operations, the operator would need to do 
the following:

--Submit a revised permit with a report from a BSEE-approved 
verification organization documenting the repairs and that the BOP is 
fit for service;
--Perform a new BOP test upon relatch; and
--Receive approval from the District Manager.

Paragraph (b) would help BSEE ensure the BOPs have proper verification 
after repairs and that BSEE would be aware of the repairs.

    New paragraph (c) would codify BSEE policy. Additions to this 
section would provide that if an operator plans to drill a new well 
with a subsea BOP, the operator does not need to submit with its APD 
the verifications required by this subpart for the open water drilling 
operation. However, before drilling out the surface casing, the 
operator would be required to submit for approval a revised APD, 
including the third-party verifications required in this subpart. This 
paragraph would allow operators to perform certain operations prior to 
verification to facilitate the timing and scheduling of work.
    The BSEE is also soliciting specific comments on the following 
possible additional requirements:

--Under proposed paragraph (a)(1)(ii) of this section, requiring that 
both shear rams be able to shear the appropriate area for the casing 
landing string. Also please comment on whether there would be utility 
in installing the non-sealing shear ram above the sealing shear ram, 
and how it would affect the sequence of ram closure;
--Under proposed paragraph (a)(16) of this section, requiring a 
position indicator for each ram BOP, wellhead connector, and LMRP 
connector. The position indicator would have to be viewable by the ROV 
during operations and in the event of a disconnect of the LMRP; and
--Under proposed paragraph (a)(16) of this section, requiring sensing 
and displaying pressure within the BOP. This mechanism would have to be 
viewable by the ROV during operations and in the event of a disconnect 
of the LMRP.

    These proposed requirements are in part based on various Deepwater 
Horizon investigation recommendations.\3\ These proposed requirements 
would help identify the status of various BOP components under 
emergency situations to assist in emergency well control. If your 
comment addresses anticipated costs associated with any of the above 
requirements, please provide any available supporting data.
---------------------------------------------------------------------------

    \3\ For example, BOP position indicator and display of 
pressures--National Oil Spill Commission recommendation D4; 
Centering pipe for shearing--DOI JIT recommendation D6; ROV 
functions and capabilities--Offshore Energy Safety Advisory 
Committee recommendation 07; Monitoring Subsea electronic module 
batteries--DOI JIT recommendation D2.
---------------------------------------------------------------------------

    The BSEE is also soliciting comments on whether there are other 
options besides the use of shear rams to provide redundant shearing 
capability while ensuring the same level of safety and environmental 
protection.
What associated systems and related equipment must all BOP systems 
include? (Sec.  250.735)
    This proposed section would reflect a combination of existing 
Sec. Sec.  250.441, 250.443, 250.516, 250.616, and 250.1706.
    Proposed paragraph (a) would contain content from existing Sec.  
250.441(c), with the following changes:

--Clarification that the requirements are for a surface accumulator 
system;
--Clarification that the system would have to operate all BOP 
functions, including shearing pipe and sealing the well against MASP 
without assistance from a charging system; and
--Clarification that these provisions would apply to all BOP systems, 
not just surface BOP stacks.

This revision would clarify existing regulations and ensure the BOP 
system is capable of operating all critical functions.

    Proposed paragraph (b) would add that the independent power source 
must possess sufficient capability to close and hold closed all BOP 
components under MASP.
    Proposed paragraph (e) would add that the kill line must be 
installed beneath at least one pipe ram.
What are the requirements for choke manifolds, kelly valves, inside 
BOPs, and drill string safety valves? (Sec.  250.736)
    This proposed section would reflect a combination of existing 
Sec. Sec.  250.444, 250.445, 250.516, 250.616, 250.1707, with minor 
edits to clarify applicability to all operations covered under this 
subpart.
What are the BOP system testing requirements? (Sec.  250.737)
    This proposed section would reflect a combination of existing 
Sec. Sec.  250.447, 250.448, 250.449, 250.517, 250.617, 250.1707, and 
be revised as follows:
    Proposed paragraph (a) would reorganize pressure testing frequency 
requirements into one section. A new provision would be added that the 
District Manager may require more frequent testing for the BOP system 
if conditions or BOP performance warrant. Additionally, by 
consolidating the pressure test requirements for drilling, workovers, 
completions, and decommissioning into one section, BSEE would revise 
the workover and decommissioning BOP testing frequency to be consistent 
with the 14-day frequency for drilling and completions. Some operations 
use the same rigs and BOP systems; therefore, to ensure consistency 
among different operations involving the same equipment, BSEE proposes 
harmonizing the requirements for that type of equipment. Also, BOP 
equipment that meets the new requirements of this proposed rule would 
perform in a more reliable manner and provide additional assurances 
that wells can be safely shut-in when necessary. The BSEE requests 
comments on whether this increase in equipment reliability justifies 
expanding the workover and decommissioning BOP testing frequency.
    Proposed paragraph (b) would add a table to organize pressure 
testing requirements. Paragraph (b)(1) would be for a low-pressure 
test, and the required test pressure range would increase 50 psi to be 
between 250 to 350 psi. Paragraph (b)(2) would add high-pressure test 
requirements for BSR-type

[[Page 21525]]

BOPs, outside of all choke and kill side-outlet valves (and annular 
gas-bleed valves for subsea BOP), and inside of all choke and kill 
side-outlet valves below the uppermost ram. Paragraph (b)(3) would add 
high-pressure test requirements for inside of choke or kill valves (and 
annular gas bleed valves for subsea BOP) above the uppermost ram BOP 
and would clarify test pressure procedures.
    Proposed paragraph (c) would require that each test must hold 
pressure for 5 minutes, which must be recorded on a 4-hour chart. This 
would allow the chart to display enough line curvature length to detect 
a leak during the test.
    Proposed paragraph (d) would be reorganized into a table and 
additional testing requirements would be added. Revisions to the 
existing testing requirements would be:
    Proposed paragraph (d)(1) would add a reference to the testing 
requirements in API Standard 53. Operators would be required to follow 
all testing requirements covered in API Standard 53, unless testing 
requirements conflict with BSEE regulations, in which case operators 
would be required to follow BSEE regulations.
    Proposed paragraph (d)(2) would add requirements to use water to 
test a surface BOP system. This paragraph would also require that 
operators submit test procedures in their APD or APM for District 
Manager approval and contact the District Manager at least 72 hours 
prior to beginning the test to allow a BSEE representative to witness 
testing.
    Proposed paragraph (d)(3) would require that operators submit stump 
test procedures for a subsea BOP system in their APD or APM for 
District Manager approval and require that stump tests follow the 
pressure test procedures set forth in paragraphs (b) and (c).
    Proposed paragraph (d)(4) would outline the requirements for 
performing the initial subsea BOP test on the seafloor.
    Proposed paragraph (d)(5) would expand testing requirements for two 
BOP control stations. The operator would be required to designate the 
control stations as primary and secondary and function-test each 
station weekly. The control station used to perform the pressure test 
would be required to be alternated between each pressure test. For a 
subsea BOP, the operator would be required to rotate the pods between 
each control station during the weekly function tests and alternate the 
pod used for pressure testing between each pressure test. If additional 
control stations are installed, they would have to be tested every 14 
days.
    Proposed paragraph (d)(7) would be a new requirement to pressure 
test annular type BOPs against the smallest pipe in use.
    Proposed paragraph (d)(10) would be a new requirement to function 
test BSR BOPs every 14 days. This requirement would align the timing of 
the function and pressure tests.
    Proposed paragraph (d)(12) would expand criteria for ROV testing to 
include testing and verifying closure capability of all intervention 
functions of the subsea BOP. These new provisions include requirements 
that:

--Each ROV must be fully compatible with the BOP stack ROV intervention 
panels;
--Operators must submit test procedures, including how they will test 
each ROV intervention function; and
--Operators must document all test results and make them available to 
BSEE upon request.

    Proposed paragraph (d)(13) would expand requirements for function 
testing autoshear, deadman, and EDS systems on subsea BOPs. The test 
procedures must be submitted for District Manager approval, and the 
proposed rule would require that the procedures include:

--Schematics of the circuitry of the system that would be used during 
an autoshear or deadman event;
--The approved schematics of the BOP control system with the actions 
and sequence of events that would take place; and
--How the ROV would be used during the well-control operations.

    Prior to conducting the test, the well is to be in a secure 
configuration with appropriate barriers. The testing of the deadman 
system on the seafloor would have to indicate the discharge pressure of 
the subsea accumulator system throughout the test. During the initial 
test of the deadman system, the operator would need to have the ability 
to quickly disconnect the LMRP. The operators would also have to submit 
the quick-disconnect procedures with the deadman test procedures in the 
APD or APM. The BSR(s) would need to be pressure tested according to 
paragraphs (b) and (c) of this section. The operator would have to 
include in its procedure a description of how it plans to verify 
closure of a casing shear ram if installed. All test results would have 
to be documented and submitted to BSEE upon request.
    Proposed paragraph (e) would require that operators notify BSEE at 
least 72 hours in advance of any shear ram tests in which the operators 
will shear pipe. This would allow better scheduling for BSEE personnel 
to witness these tests.
What must I do in certain situations involving BOP equipment or 
systems? (Sec.  250.738)
    This proposed section would be a combination of existing Sec. Sec.  
250.451 and 250.517. Additional requirements would be added as follows:
    As recommended by the DOI JIT investigation recommendation E2, 
proposed paragraph (a) would require the operator to notify the 
District Manager of any problems or irregularities, including leaks, if 
BOP equipment does not hold the required pressure during testing.
    Proposed paragraph (b) would require the operator to receive 
approval from the District Manager prior to resuming operations after 
replacing, repairing, or reconfiguring the BOP system. To obtain 
approval, the operator would have to submit a report from a BSEE-
approved verification organization attesting that the BOP system is fit 
for service. Any repair or replacement parts would have to be 
manufactured under a quality assurance program and would have to meet 
or exceed the performance of the original part produced by the OEM.
    Proposed paragraph (d) would require the operator to notify the 
District Manager of any problems or irregularities, including leaks, if 
a BOP control station or pod does not function properly and suspend 
operations until the station or pod operates properly.
    Proposed paragraph (e) would be revised to clarify that two sets of 
pipe rams must be capable of sealing around the smaller size pipe to be 
consistent with Sec. Sec.  250.733(a) and 250.734(a)(1), which require 
the capability to close and seal on the tubular body of any drill pipe, 
workstring, and tubing.
    Proposed paragraph (f) would add new requirements if the operator 
proposes to install casing rams or casing shear rams in a surface BOP 
stack. The ram bonnets would have to test to the rated working pressure 
or MASP plus 500 psi and be tested before running casing. The BOP would 
still need to be capable of sealing the well after the casing is 
sheared. If the installation would be a change from the approved APM or 
APD, the operator must notify and receive approval from the District 
Manager.
    Proposed paragraph (i) would require that, after pipe or casing is 
sheared either intentionally or unintentionally, the operator would 
have to retrieve, inspect, and test the BOP as well as submit a report 
to the District Manager from a BSEE-approved verification

[[Page 21526]]

body, stating that the BOP is fit to return to service.
    Proposed paragraph (j) would add a requirement that an operator 
must have a minimum of two barriers in place prior to removal of the 
BOP stack. The District Manager would have to approve the two barriers 
and may require additional barriers prior to removal. This requirement 
is consistent with similar requirements in current Sec.  250.420(b)(3), 
and is necessary to ensure that the well is placed in a safe condition 
prior to BOP removal.
    Proposed paragraph (k) would add new requirements for re-
establishing power to a BOP stack after a deadman or autoshear 
activation. Prior to re-establishing power, the operator would have to 
examine the system to determine if the possibility exists for the BSR 
opening immediately upon re-establishing power to the BOP stack. If 
this is a possibility, the opening function would have to be placed in 
the block position before power is re-established to the stack. The 
operator would have to contact the District Manager to receive approval 
of procedures for re-establishing power and functions prior to latching 
up the BOP stack or re-establishing power to the stack.
    Proposed paragraph (l) would establish requirements for test rams. 
The initial BOP test after latch-up would have to be done with a test 
tool, and the wellhead/BOP connection would have to be tested to the 
maximum ram-test pressure approved for the well in the APD or APM. All 
hydraulically operated BOP components would have to function as 
designed during the well connection test.
    Proposed paragraph (m) would add requirements for additional well-
control equipment that operators may use, but which are not required in 
this subpart. The operator would have to request approval from the 
appropriate District Manager, submit a report from a BSEE-approved 
verification organization on the design and suitability of the 
equipment for its intended use, and submit any other information 
required by the District Manager. The District Manager may impose 
requirements concerning the equipment's capabilities, operation, and 
testing.
    Proposed paragraph (n) would clarify that pipe and variable bore 
rams that have no current utility and would not be used for well-
control purposes would not have to be pressure and function tested, 
until they are intended to be used during operations. Operators would 
have to indicate which pipe and variable bore rams meet this criteria 
in their APD or APM and label those rams on all BOP control panels.
    Proposed paragraph (o) would include new requirements applicable to 
redundant well-control components in BOP systems that are in addition 
to components required in Subpart G. If any redundant component fails a 
test, you must submit a report from a BSEE-approved verification 
organization that describes the failure and confirms that there is no 
impact on the BOP that will make it unfit for well-control purposes. 
This report would have to be submitted to the District Manager, and 
operators may not resume operations until they receive the District 
Manager's approval. The District Manager may require operators to 
submit additional information before approving continued operations.
    Proposed paragraph (p) would add new requirements that operators 
would have to meet if they need to position the bottom hole assembly 
across the BOP for tripping or any other operations, including:

--Ensuring that the well is stable at least 30 minutes before 
positioning the bottom hole assembly across the BOP, and
--Including in the well-control plan (required by proposed Sec.  
250.710(b)) procedures for immediately removing the bottom hole 
assembly from across the BOP in the event of a well control or 
emergency situation before exceeding MASP conditions. This would ensure 
that the operational conditions would not exceed the BOP design 
specifications.
What are the BOP maintenance and inspection requirements? (Sec.  
250.739)
    This proposed section would reflect a combination of existing 
Sec. Sec.  250.446, 250.517, 250.618, and 250.1708 with the following 
revisions:
    Proposed paragraph (a) would add that the BOP maintenance and 
inspections must meet or exceed OEM recommendations, recognized 
engineering practices, and industry standards incorporated by reference 
into the regulations, including all provisions in API Standard 53. In 
the past, BSEE has only required compliance with select sections of API 
RP 53. By incorporating the updated edition (API Standard 53), BSEE 
would increase the overall maintenance and inspection requirements.
    Proposed paragraph (b) would be a new requirement that details the 
procedures for a complete breakdown and inspection of the BOP and every 
associated component every 5 years. This paragraph would also clarify 
that the complete breakdown and inspection may not be performed in 
phased intervals. Also, during this complete breakdown and inspection, 
a BSEE-approved verification organization would have to be present 
documenting the inspection and any problems encountered and produce a 
detailed report. This independent third-party report would have to be 
available to BSEE upon request. The BSEE is aware that, in the past, 
various components of BOP stacks have not had this type of inspection 
for more than 10 years. However, BSEE feels it is essential to ensure 
that every component on the BOP stack has a complete breakdown and 
detailed inspection every 5 years.
    Proposed paragraph (c) would revise the subsea BOP inspection 
requirement to include visual inspection of the wellhead and remove the 
word ``television.''

    Proposed paragraph (d) would require that the personnel who 
maintain, inspect, or repair BOPs or other critical components meet the 
qualifications and training criteria specified by the OEM and that such 
maintenance, inspection, and repair be undertaken in accordance with 
recognized engineering practices. This provision is necessary to ensure 
that any personnel working on BOPs are properly qualified to perform 
any maintenance, inspections, or repairs.
    Proposed paragraph (e) would require that all records be made 
available to BSEE upon request. This provision would also require 
operators to ensure, by contract or otherwise, that a rig owner 
maintains BOP records on the rig for 2 years from the date the records 
are created or longer if directed by BSEE. Also, all design, 
maintenance, inspection, and repair records must be maintained at an 
onshore location for the service life of the equipment.
Records and Reporting
What records must I keep? (Sec.  250.740)
    This proposed section would include content from existing Sec.  
250.466 and would make the requirements applicable to all operations 
covered under this subpart. This section would also include 
recordkeeping of all tests conducted and real-time monitoring data 
gathered during operations.
How long must I keep records? (Sec.  250.741)
    This proposed section would contain content from existing Sec.  
250.467 with minor edits to clarify applicability to all operations 
covered under this subpart. This section would also include how long 
records for real-time monitoring data must be kept.

[[Page 21527]]

What well records am I required to submit? (Sec.  250.742)
    This proposed section would contain some content from existing 
Sec.  250.468. The remainder of the existing Sec.  250.468 would be 
included in proposed Sec.  250.743.
What are the well activity reporting requirements? (Sec.  250.743)
    This proposed section would include content from existing 
paragraphs (b) and (c) of existing Sec.  250.468, BSEE NTL 2009-G20, 
Standard Reporting Period for the Well Activity Report, and BSEE NTL 
2009-G21, Standard Conditions of Approval for Well Activities with the 
following changes:
    Proposed paragraph (a) would clarify the well activity reporting 
timeframe for the GOM OCS Region as currently set forth in NTL 2009-
G20. This new revision would help clarify when to submit the WARs (Form 
BSEE-0133) and accompanying Form BSEE-0133S, Open Hole Data Report. The 
District Manager may require more frequent submittal of the WAR on a 
case-by-case basis.
    Proposed paragraph (c) would be revised to include in the WAR, 
information from NTL 2009-G21 describing the operations conducted, any 
abnormal or significant events that affect the permitted operation, 
verbal approvals, the wells as-built drawings, casing fluid weights, 
shoe tests, test pressures at surface conditions, and status of the 
well at the end of the reporting period. The final WAR would include 
the date operations finished. This paragraph would also require 
describing the returns for casing cementing operations. This data would 
provide BSEE with accurate information regarding the operations and 
well conditions and verify the operator's compliance with past 
approvals.

    Upon final publication of this rule, BSEE will rescind any NTLs 
that are superseded by this section in the final rule.
What are the end of operation reporting requirements? (Sec.  250.744)
    This proposed section would combine provisions from existing 
Sec. Sec.  250.465, 250.1712, 250.1717, and NTL 2009-G21, Standard 
Conditions of Approval for Well Activities, and include clarifications 
concerning the contents of the EOR (Form BSEE-0125). This information 
would provide BSEE with important well data and provide a better 
understanding of the operations and well conditions.
What other well records could I be required to submit? (Sec.  250.745)
    This proposed section would reflect content from existing Sec.  
250.469.
What are the recordkeeping requirements for casing, liner, and BOP 
tests, and inspections of BOP systems and marine risers? (Sec.  
250.746)
    This proposed section would reflect a combination of existing 
Sec. Sec.  250.426, 250.450, 250.517, 250.617, and 250.1707, with the 
following revisions:
    Proposed paragraph (b) would add the requirement for the designated 
rig or contractor representative (e.g., the offshore installation 
manager) and pump operator to sign and date the pressure charts and 
reports as correct in addition to the onsite lessee representative 
(e.g., the company man).
    Proposed paragraph (d) would be clarify that identification of the 
pods would not apply to coiled tubing and snubbing units.
    Proposed paragraph (e) would clarify that any leaks observed during 
testing or observed from the control station are considered 
irregularities and would have to be reported to BSEE. Operations would 
have to be suspended until BSEE grants approval to continue. This 
revision would allow BSEE to be notified of the BOP irregularities to 
help determine BOP operability.
    Proposed paragraph (f) would add the timeframe for keeping the 
records for a minimum of 2 years after completion of the operation and 
require that the records would have to be made available to BSEE upon 
request. The BSEE would be able to use this data as a tool to verify 
the operator's compliance with past approvals and regulations.

Subpart P--Sulphur Operations

Well-control drills (Sec.  250.1612)
    This section would update the reference for the drilling crew 
requirements under proposed Sec.  250.711.

Subpart Q--Decommissioning Activities

What are the general requirements for decommissioning? (Sec.  250.1703)
    This section would be revised as follows:
    Paragraph (b) would include a new requirement that all packers and 
bridge plugs would have to comply with API Spec. 11D1, which would help 
ensure that packers and bridge plugs conform to design, manufacture, 
and testing criteria to increase reliability and to ensure appropriate 
use of the equipment. Currently, BSEE does not have specific guidelines 
for packers and bridge plugs, and this addition would help BSEE verify 
that wells have been properly plugged in accordance with API Spec. 
11D1.
    Paragraph (f) would be revised to add reference to the requirements 
of new Subpart G. This would make Subpart G applicable to 
decommissioning.
When must I submit decommissioning applications and reports? (Sec.  
250.1704)
    Paragraph (g) would be revised by removing current paragraphs 
(g)(2), (g)(4), and (g)(6) and the associated instructions in the third 
column, as well as by revising the numbering of current paragraphs 
(g)(3) and (g)(5) to (g)(2) and (g)(3), respectively, and by updating 
the applicable citations. Proposed paragraph (h) would be added to 
state the requirements for when to submit the EOR, making it clear when 
operators would have to submit the EOR versus an APM.
What BOP information must I submit? (Sec.  250.1705)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec. Sec.  250.731 and 250.732.
Coiled tubing and snubbing operations. (Sec.  250.1706)
    Paragraphs (a) through (e) would be moved to proposed Sec. Sec.  
250.730, 250.733, 250.734, and 250.735. The section heading would be 
renamed from, What are the requirements for blowout prevention 
equipment? to Coiled tubing and snubbing operations. Remaining 
paragraphs (f) through (h) would be redesignated as (a) through (c).
What are the requirements for blowout preventer system testing, 
records, and drills? (Sec.  250.1707)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec. Sec.  250.711, 250.736, 
250.737, and 250.746.
What are my BOP inspection and maintenance requirements? (Sec.  
250.1708)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.739.
What are my well-control fluid requirements? (Sec.  250.1709)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.720.
How must I permanently plug a well? (Sec.  250.1715)
    Paragraph (a)(3)(iii)(B) of this section would be revised to add 
that a ``casing'' bridge plug would be set 50 to 100 feet

[[Page 21528]]

above the top of the perforated interval. Adding the word ``casing,'' 
clarifies the plug requirements for the applicable scenario. The BSEE 
has been contacted by multiple companies requesting clarification of 
this type of requirement. The BSEE believes that the proposed addition 
of ``casing'' adequately addresses the concerns stated by industry 
participants and explains the correct intention of this proposed 
section.
After I permanently plug a well, what information must I submit? (Sec.  
250.1717)
    This section would be removed and reserved. The content of this 
section would be moved to proposed Sec.  250.744.
If I temporarily abandon a well that I plan to re-enter, what must I 
do? (Sec.  250.1721)
    This section would remove existing paragraph (g) and redesignate 
paragraph (h) as (g). The content of existing paragraph (g) would be 
required by proposed Sec.  250.744.
Additional Comments Solicited
    In addition to the input previously requested, BSEE requests public 
comment on the following issues.
(1) Rig Daily Operating Rates
    Throughout the proposed rule and corresponding economic analysis, 
the BSEE has estimated the daily rig rates and made assumptions based 
on that estimation. The BSEE is soliciting comments on the 
appropriateness of the values presented and is further requesting 
corresponding data to substantiate any comments. The BSEE can use this 
data to update the values in the final rule. The following chart shows 
the daily operating costs used within the economic analysis.

------------------------------------------------------------------------
                                              Estimated daily operating
                 Rig type                               cost
------------------------------------------------------------------------
Rigs that utilize a subsea BOP (e.g.                          $1,000,000
 drillships, semi-submersibles)...........
Rigs that utilize a surface BOP (e.g. jack-                      200,000
 ups, lift boats).........................
------------------------------------------------------------------------

(2) Failure of Equipment Reporting and Information Dissemination
    Several of the standards that are being incorporated by reference 
include a process for the reporting of failures of equipment back to 
the OEM. The BSEE proposes to adopt these processes and add a 
requirement that BSEE be notified of major issues that require a design 
change. This notification would help to ensure that the domestic and 
international communities are able to react quickly to address 
potential safety issues.
    Because identical equipment designs are often used by multiple 
operators, ensuring the timely reporting of failures involving critical 
equipment can assist in identifying trends and play an important role 
preventing future incidents. The BSEE believes that a more formalized 
method of collecting, analyzing, and disseminating failure data is 
warranted, especially for equipment failures that do not result in a 
reportable incident. The need for this type of program was clearly 
demonstrated following the December 2012 failures of certain bolts in 
the GOM. Subsequent investigations revealed that although these 
failures had been occurring over a period of years, most of the 
industry was not aware of the safety issues. Even after safety alerts 
were issued by BSEE and the OEM, some operators claimed that the amount 
and quality of data that was released was not sufficient. The BSEE has 
received comments from the industry stating that legal and commercial 
barriers discouraged the voluntary reporting of this type of data.
    The BSEE requests comments on whether this information should be 
provided to the agency or a third-party to ensure the timely analysis 
and wide-spread communication of the data. For example, are there 
programs in other industries that could serve as a model for reporting 
failure of OCS equipment? Are there third-party organizations that 
would be good candidates for collecting and analyzing information and 
issuing safety alerts? What type of data should be collected and 
disseminated? How should information on international operations be 
collected and disseminated?
(3) Maintenance and Training
    Preventative and remedial maintenance is critical to maintaining a 
satisfactory level of reliability during the operational life of 
critical equipment. A lifecycle management approach toward safety 
critical equipment is especially important as the industry moves into 
the development of deepwater and HPHT reservoirs. More rigorous 
inspection, maintenance, and repair practices and methods may be needed 
to ensure the reliable performance of this equipment in these 
environments.
    The BSEE requests comments on whether there are any additional 
standards or practices related to the repair and maintenance of this 
equipment that should be considered by BSEE. The BSEE has completed a 
major study related to maintenance, inspection and test activities, and 
management systems. The BSEE requests information on any work that is 
being conducted by the industry to develop industry standards 
concerning these activities. The BSEE also requests comments on whether 
there are predictive maintenance techniques or risk-based maintenance 
approaches that should be used to supplement the proposed requirements.
    The proposed regulation requires the use of real-time monitoring 
systems for operations with a subsea BOP stack or involving HPHT 
environments. The BSEE requests comments on the use of continuous 
remote monitoring and diagnostic analysis of critical equipment using 
condition-based maintenance (CBM). With CBM, critical equipment can be 
monitored and maintenance actions performed based on information 
collected through constant real-time monitoring of critical equipment. 
These systems may provide early warning of potential problems that 
could be addressed before costly and dangerous catastrophic failures. 
The BSEE believes that these systems may help to verify the integrity 
of the overall system during drilling operations in a more timely and 
efficient manner.
    The BSEE believes that it is important that components and 
replacement parts for critical equipment meet quality design and 
engineering standards that ensure that this equipment operates safely 
and as originally designed during its service life. Additionally, the 
equipment must be repaired and maintained by highly trained personnel 
that understand the OEM design and repair standards. These requirements 
are implicit in the Safety and Environmental Management Systems (SEMS) 
requirements contained in existing BSEE regulations. The BSEE requests 
comments on what type of training and certification programs

[[Page 21529]]

should be required for personnel working on this critical equipment. 
Are there training and certification programs being used in other 
industries that can serve as a model for the OCS personnel? How should 
repairs being performed outside U.S. waters be monitored? Are there any 
existing oil and gas training and certification programs that should be 
incorporated into the regulations?
(4) Verification of BOP Performance
    The BSEE believes that the proposed requirements would provide the 
agency with additional assurance related to the overall reliability of 
equipment in the future. The industry and BSEE currently rely on 
function and hydrostatic tests to verify the performance of BOP 
equipment in the field. These tests have traditionally been the primary 
method of verifying the capability of in-service equipment.
    In recent years, the industry has raised concerns related to 
benefits of pressure and functional testing of subsea BOPs versus the 
costs and potential operational issues. The BSEE requests comments on 
the adequacy of the current functional and pressure test requirements 
in predicting the performance of this equipment in subsequent drilling 
operations. Under what circumstances or environments should the testing 
frequency be increased or decreased? Are there additional technologies, 
processes, or procedures that can be used to supplement existing 
requirements and provide additional assurances related to the 
performance of this equipment?
    The latest industry study on BOP reliability and testing frequency 
was submitted to the MMS in 2009. What type of additional research and 
data collection is needed or has already been conducted to verify the 
reliability of this equipment? Can the combination of real-time 
monitoring and condition based maintenance justify reduced pressure 
testing? Does testing too frequently result in a shorter BOP 
operational lifespan?
    Please provide supporting reasons and data for your responses.
(5) Increased Severing Capability
    The BSEE is proposing a variety of requirements that will increase 
the likelihood that a BOP will be able to severe a drill string in an 
emergency situation to shut-in the well and prevent a catastrophic 
blowout.\4\ However, there are a variety of components in the drill 
string (e.g., drill collars) that cannot be severed using technology 
that is currently being used in offshore operations. Accordingly, BSEE 
is considering including the following requirement in Sec.  250.734 of 
the final rule for subsea BOPs:
---------------------------------------------------------------------------

    \4\ See recommendations of Offshore Energy Safety Advisory 
Committee, August 2012 meeting, available at: https://www.bsee.gov/uploadedFiles/BSEE/About_BSEE/Public_Engagement/Ocean_Energy_Safety_Advisory_Committee/OESC%20Recommendations%20August%202012%20Meeting%20Chairman%20Letter%20to%20BSEE%20101512.pdf.

    You must install technology that is capable of severing any 
components of the drill string (excluding drill bits). You must 
install this technology within 10 years from the publication of the 
---------------------------------------------------------------------------
final rule.

    Such a severing requirement would provide additional protection 
against the potential loss of well control by requiring that operators 
install supplemental technology that ensures all components of a drill 
string, including those components that cannot be sheared with current 
shear rams, could be severed in an emergency to allow the well to be 
safely shut-in. The operator would have the flexibility to develop or 
select the technology and equipment to accomplish this performance-
based requirement. The BSEE is aware of at least one candidate 
technology that is currently being evaluated and believes that other 
innovative or improved technologies would be developed to accomplish 
this objective, if such a requirement is adopted in the final rule. The 
industry has demonstrated that it has the financial resources and 
technical expertise to develop the innovative technology needed to 
explore and produce oil and gas resources in challenging deepwater and 
HTHP environments.\5\
---------------------------------------------------------------------------

    \5\ For example, soon after the Deepwater Horizon incident, 
several of the largest oil companies created the Marine Well 
Containment Co., and agreed to spend $1billion to develop and build 
new containment technology for deepwater drilling. See https://www.npr.org/2011/04/19/135513456/oil-firms-seek-to-prove-they-can-contain-spills. In addition, BP initiated ``Project 20K''--a major 
research and development initiative involving Maersk Drilling and 
other companies--to develop new technologies, within a decade, for 
drilling safely in deepwater under HPHT conditions. See https://www.maersk.com/en/the-maersk-group/about-us/maersk-post/2014-5/pushing-technological-boundaries. Similarly, McMoran has already 
invested over $1.2 billion in deepwater drilling sites in the GOM 
and is working with researchers and manufacturers to develop heavy 
duty BOPs and make other necessary technological advances. See 
https://www.forbes.com/sites/christopherhelman/2013/05/08/mcmoran-gives-update-on-davy-jones-the-1-billion-ultradeep-well/; https://www.spe.org/tech/2012/04/high-pressurehigh-temperature-challenges/. 
See also https://www.shell.com/global/aboutshell/major-projects-2/perdido/unlocking-energy.html (Shell uses innovative, first-of-its-
kind technology to produce ultra-deep Perdido well).
---------------------------------------------------------------------------

    In addition, BSEE is considering whether to also make this type of 
requirement applicable to surface BOPs in Sec.  250.733 in the final 
rule. The BSEE is requesting comments on the following issues:

--Please comment on whether BSEE should include a severing provision 
for subsea BOPs in the final rule, as previously described. If BSEE 
does so, please address whether that requirement should also apply to 
surface BOPs, given the number of blowouts involving surface stacks.
--What incentives or other actions could be used to assist in the 
development and implementation of this technology? What should BSEE's 
role, if any, be in this development process?
--If BSEE includes a severing provision in the final rule, what would 
be an appropriate effective date for such a requirement? In particular, 
please comment on whether 10 years would be appropriate to develop 
technology that could meet the severing requirement, or whether the 
timeframe for development of such technology and for compliance with 
the requirement could be shortened (e.g., to 5 years).

    Please provide an explanation and data with your responses.
    The BSEE is unable to locate any applicable comparative cost 
estimates or other data to estimate the labor or other costs to 
industry that would be associated with the installation of technology 
capable of severing any components of the drill string (excluding drill 
bits). Also, assessing or quantifying the potential benefits that could 
arise from the reduction of risks over the 10-year period covered by 
the economic analysis for this proposed rule would require additional 
data. Accordingly, BSEE is also requesting comments on the following 
issues associated with this potential severing provision:

--Please provide comments on any costs related to the development and 
installation of technology that would be needed to satisfy this type of 
performance-based requirement within 10 years. Assuming the final rule 
includes such a provision, how should BSEE include such costs in the 
final economic analysis for this rulemaking, given that the analysis 
uses a 10-year period to estimate all costs and benefits?
--What would be the costs of developing and installing appropriate 
technology to meet such a severing requirement in 5 years? If it would 
not be feasible to comply with this requirement in 5 years, what would 
be the incremental increase in costs of

[[Page 21530]]

any implementation deadline between 5 years and 10 years?
--How much would a severing requirement, whether applicable only to 
subsea BOPs or to subsea and surface BOPs, reduce the risk or 
consequences of a blowout? If BSEE includes such a requirement in the 
final rule, to be effective 10 years after the final rule takes effect, 
how could BSEE estimate the benefits of such risk reduction given that 
those benefits would not be realized until after the 10-year economic 
analysis period used in this proposed rule? If BSEE included such a 
severing requirement with a shorter time period for compliance (e.g., 5 
years from the final rule effective date), how could BSEE estimate the 
potential risk reduction benefits?
--Please describe any alternative method (other than the potential 
severing requirement) to protect against the potential loss of well 
control. Please discuss whether such an alternative would be more or 
less costly than the proposed requirement.

    Please explain your conclusions and provide supporting information.

 Appendix

    The following appendix will not appear in the Code of Federal 
Regulations. Appendix A is included in this proposed rule so we may 
solicit your comments on proposed revisions to an existing form for use 
in reporting some of the information required in proposed subpart G.

Appendix--Department of the Interior--Form BSEE-0144, ``Rig Movement 
Notification Report.''

[[Page 21531]]

[GRAPHIC] [TIFF OMITTED] TP17AP15.005


[[Page 21532]]


[GRAPHIC] [TIFF OMITTED] TP17AP15.006


[[Page 21533]]


[GRAPHIC] [TIFF OMITTED] TP17AP15.007

BILLING CODE 4310-VH-C

VI. Derivation Tables

    The following tables are intended to provide information about the 
derivation of proposed requirements in Subparts A, B, D, E, F, proposed 
G, P, and Q. These tables provide guidance on the following:

--The destination of various current requirements.
--The organization and content of the proposed revisions.

    These tables do not provide definitive or exhaustive guidance, and 
should be used in conjunction with the section-by-section discussion 
and regulatory text of this proposed rule.
    The following sections in 30 CFR part 250, subparts D, E, F, and Q 
have either been [Removed and/or Reserved] according to the following 
table.

------------------------------------------------------------------------
                                          Removed and/or Reserved in 30
                Subpart                            CFR Part 250
------------------------------------------------------------------------
D......................................  401, 402, 403, 406, 417, 424,
                                          425, 426, 440 through 451, 466
                                          through 469.
E......................................  502, 506, 515 through 517.
F......................................  602, 606, 615, 617, 618.
Q......................................  1705, 1707 through 1709, 1717.
------------------------------------------------------------------------

    The proposed rule would make changes as outlined in the following 
table:

------------------------------------------------------------------------
                                  Proposed rule
  Current regulations section        section          Nature of change
------------------------------------------------------------------------
                                Subpart A
------------------------------------------------------------------------
250.102(b)....................  250.102(b).......  Added reference to
                                                    new subpart G.
NEW...........................  250.107(a)(3),     Added the use of
                                 (a)(4); (e).       recognized industry
                                                    practices and BSEE-
                                                    issued orders.
250.125(a)(2).................  250.125(a)(2)....  Revised (2) to
                                                    reflect the
                                                    redesignation of
                                                    250.292(q).
250.198(h)....................  250.198(h).......  Updated citations in
                                                    (h)(51), (68), (70);
                                                    removed the RP and
                                                    added in its place
                                                    the Standard in
                                                    (h)(63); added new
                                                    (h)(89-94).
250.199(e)....................  250.199(e).......  Updated OMB control
                                                    numbers and reword,
                                                    for plain language,
                                                    the reasons BSEE
                                                    collects the data.
                                                    And added paragraphs
                                                    for APDs, APMs, and
                                                    Subpart G.
------------------------------------------------------------------------

[[Page 21534]]

 
                                Subpart B
------------------------------------------------------------------------
250.292(p)....................  250.292(q).......  Redesignated.
NEW...........................  250.292(p).......  New section that
                                                    specifies FSHR
                                                    requirements within
                                                    the DWOP.
------------------------------------------------------------------------
                                Subpart D
------------------------------------------------------------------------
250.400.......................  250.400..........  Revised section
                                                    heading and
                                                    requirements to
                                                    encompass General
                                                    Requirements for
                                                    drilling and clarify
                                                    that Subpart G has
                                                    applicable
                                                    requirements as
                                                    well.
250.401.......................  250.703..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.402.......................  250.720..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.403.......................  250.712..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.406.......................  250.723..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.411.......................  250.411..........  Revised to separate
                                                    the diverter and the
                                                    BOP descriptions;
                                                    updating citations.
250.413(g)....................  250.413(g).......  Revised to add the
                                                    phrase ECD.
250.414.......................  250.414..........  Revised paragraphs
                                                    (c), (h), (i); added
                                                    new paragraphs (j)
                                                    and (k) to help
                                                    ensure the well's
                                                    structural integrity
                                                    and submission of
                                                    any additional
                                                    information required
                                                    by the District
                                                    Manager.
250.415(a)....................  250.415(a).......  Revised paragraph (a)
                                                    for casing
                                                    information in all
                                                    sections for each
                                                    casing interval.
250.416.......................  250.416(a), (b);   Revised to remove
                                 250.730;           only the BOP
                                 250.731; 250.732.  descriptions in the
                                                    regulatory text and
                                                    section heading.
250.417.......................  250.713..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.418(g)....................  250.418(g).......  Revised to include a
                                                    description of how
                                                    far below the
                                                    mudline the operator
                                                    proposes to displace
                                                    cement in the
                                                    request for
                                                    approval; revised
                                                    citation.
250.420.......................  250.420..........  Revised the
                                                    introductory
                                                    paragraph to include
                                                    applicable casing
                                                    and cementing
                                                    requirements in
                                                    Subpart G; added new
                                                    paragraph (a)(6) to
                                                    require adequate
                                                    centralization to
                                                    ensure proper
                                                    cementation; added
                                                    new paragraph (b)(4)
                                                    requiring District
                                                    Manager approval
                                                    before installing a
                                                    different casing
                                                    than what was
                                                    approved in the APD;
                                                    modified paragraph
                                                    (c) requiring the
                                                    use of a weighted
                                                    fluid.
250.421.......................  250.421(b) and     Revised paragraph (b)
                                 (f).               so casing would have
                                                    to be set
                                                    immediately and set
                                                    above the
                                                    encountered zone,
                                                    even if it is before
                                                    the planned casing
                                                    point if oil or gas
                                                    or unexpected
                                                    formation pressure
                                                    arises. Revised
                                                    paragraph (f) to no
                                                    longer allow liners
                                                    to be installed as
                                                    conductor casing.
250.423.......................  250.423..........  Revised the section
                                                    heading and removed
                                                    the pressure testing
                                                    and negative
                                                    pressure testing
                                                    requirements; added
                                                    clarification about
                                                    latching mechanisms.
                                                    Edited the remaining
                                                    paragraphs of
                                                    250.423 for
                                                    organization.
250.423(a) and (c)............  250.721..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.424.......................  250.722..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.425.......................  250.721..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.426.......................  250.746..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.427(b)....................  250.427(b).......  Revised paragraph (b)
                                                    to clarify that
                                                    operators must
                                                    maintain two
                                                    drilling margins.
250.428.......................  250.428..........  Revised paragraphs
                                                    (b) through (d).
                                                    Paragraph (b)
                                                    requires approval
                                                    for hole interval
                                                    drilling depth
                                                    changes greater than
                                                    100 ft. TVD, and the
                                                    submittal of a PE
                                                    certification that
                                                    the certifying PE
                                                    reviewed and
                                                    approved the
                                                    proposed changes;
                                                    paragraph (c)
                                                    clarifies
                                                    requirements when
                                                    there is any
                                                    indication of an
                                                    inadequate cement
                                                    job; and paragraph
                                                    (d) clarifies that
                                                    if there is an
                                                    inadequate cement
                                                    job, the District
                                                    Manager has to
                                                    review and approve
                                                    all remedial
                                                    actions; that the
                                                    changes to the well
                                                    program are
                                                    reviewed, approved,
                                                    and certified by a
                                                    PE; and any other
                                                    requirements of the
                                                    District Manager.
                                                    New paragraph (k)
                                                    adds requirements
                                                    concerning the use
                                                    of values on drive
                                                    pipe during
                                                    cementing
                                                    operations.
250.440.......................  250.730..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.441.......................  250.733; 250.735.  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.442.......................  250.734..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.443.......................  250.734; 250.735.  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.443(c) and (d)............  250.733..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.444.......................  250.736..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.445.......................  250.736..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.446.......................  250.739..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.447.......................  250.737..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.448.......................  250.737..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.449.......................  250.737..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.450.......................  250.746..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.451.......................  250.738..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.456(k)....................  250.456(j).......  Redesignated.

[[Page 21535]]

 
250.456(j)....................  250.720..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
NEW...........................  250.462..........  New section heading
                                                    and requirements to
                                                    demonstrate
                                                    deepwater well
                                                    containment.
250.462.......................  250.710 and        Removed heading and
                                 250.711.           requirements for
                                                    well- control
                                                    drills--similar
                                                    language found in
                                                    new Subpart G.
250.465(b)(3).................  250.465(b)(3)....  This paragraph was
                                                    revised to update
                                                    the citation for the
                                                    EOR form, BSEE-0125.
250.466.......................  250.740..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.467.......................  250.741..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.468(a)....................  250.742..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.468(b) and (c)............  250.743..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.469.......................  250.745..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
------------------------------------------------------------------------
                                Subpart E
------------------------------------------------------------------------
250.500.......................  250.500..........  Revised section
                                                    heading and
                                                    requirements to
                                                    encompass General
                                                    Requirements and
                                                    direct compliance
                                                    with new Subpart G
                                                    where applicable.
250.502.......................  250.723..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.506.......................  250.710..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.514(d)....................  250.720..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.515.......................  250.731; 250.732.  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.516.......................  250.730; 250.733;  Removed--similar
                                 250.734;           language found in
                                 250.735; 250.736.  new Subpart G.
250.517.......................  250.711; 250.737,  Removed--similar
                                 250.738,           language found in
                                 250.739; 250.746.  new Subpart G.
250.518.......................  250.518(e), (f)..  Removed paragraph (b)
                                                    and redesignated the
                                                    remaining
                                                    paragraphs. Added
                                                    new paragraphs (e)
                                                    and (f) to add API
                                                    Spec. 11D1, packer
                                                    and bridge plug
                                                    requirements, and a
                                                    description of
                                                    calculations of
                                                    packer setting
                                                    depth.
250.518(b)....................  250.722..........  Redesignated and
                                                    revised to include
                                                    additional
                                                    requirements for
                                                    prolonged
                                                    operations.
------------------------------------------------------------------------
                                Subpart F
------------------------------------------------------------------------
250.600.......................  250.600..........  Revised section
                                                    heading and
                                                    requirements to
                                                    encompass General
                                                    Requirements and
                                                    direct compliance
                                                    with new Subpart G
                                                    where applicable.
250.602.......................  250.723..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.606.......................  250.710..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.614(d)....................  250.720..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.615.......................  250.731; 250.732.  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.616(a) through (e)........  250.730; 250.733;  Removed--similar
                                 250.734;           language found in
                                 250.735; 250.736.  new Subpart G.
250.616(f) through (h)........  250.616(a)         Redesignated with no
                                 through (c).       changes made to
                                                    regulatory text.
250.617.......................  250.711; 250.737;  Removed--similar
                                 250.746.           language found in
                                                    new Subpart G.
250.618.......................  250.739..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.619.......................  250.619..........  Removed paragraph (b)
                                                    and redesignated the
                                                    section. Added new
                                                    paragraphs (e) and
                                                    (f) to add packers
                                                    and bridge plug
                                                    requirements, API
                                                    Spec. 11D1, and a
                                                    description of
                                                    calculations of
                                                    packer setting
                                                    depth.
250.619(b)....................  250.722..........  Redesignated and
                                                    revised to include
                                                    additional
                                                    requirements for
                                                    prolonged
                                                    operations.
------------------------------------------------------------------------
                              New Subpart G
------------------------------------------------------------------------
                          General requirements
------------------------------------------------------------------------
NEW...........................  250.700..........  New section
                                                    describing what
                                                    operations and
                                                    equipment are
                                                    subject to the
                                                    requirements.
250.408.......................  250.701..........  Similar language
                                                    pertaining to
                                                    alternative
                                                    procedures or
                                                    equipment.
250.409.......................  250.702..........  Similar language
                                                    pertaining to
                                                    departures.
250.401.......................  250.703..........  Similar language
                                                    containing
                                                    requirements to keep
                                                    wells under control.
------------------------------------------------------------------------
                            Rig Requirements
------------------------------------------------------------------------
250.462; 250.506; 250.606.....  250.710..........  Similar language was
                                                    revised and
                                                    incorporated into
                                                    this section about
                                                    instructions for rig
                                                    personnel.
250.462; 250.517; 250.617;      250.711..........  Similar language was
 250.1707.                                          revised and
                                                    incorporated into
                                                    this section about
                                                    well-control drills.
250.403.......................  250.712..........  Similar language was
                                                    revised and
                                                    incorporated into
                                                    this section about
                                                    rig movement
                                                    notifications.
250.417.......................  250.713..........  Similar language was
                                                    revised and
                                                    incorporated into
                                                    this section about
                                                    MODUs or lift boat
                                                    requirements for
                                                    well operations.

[[Page 21536]]

 
NEW...........................  250.714..........  New section about
                                                    dropped objects
                                                    plans.
NEW...........................  250.715..........  New section about GPS
                                                    for MODUs and jack-
                                                    ups.
------------------------------------------------------------------------
                             Well Operations
------------------------------------------------------------------------
250.402; 250.456(j);            250.720..........  Similar language was
 250.514(d); 250.614(d);                            revised and
 250.1709.                                          incorporated into
                                                    this section about
                                                    securing a well.
250.423(a), (c); 250.425......  250.721..........  Similar language was
                                                    revised and
                                                    incorporated into
                                                    this section about
                                                    pressure testing
                                                    casing and liners.
250.424; 250.518; 250.619.....  250.722..........  Similar language was
                                                    revised and
                                                    incorporated into
                                                    this section
                                                    pertaining to
                                                    prolonged well
                                                    operations.
250.406; 250.502; 250.602.....  250.723..........  Similar language from
                                                    250.406, 250.502,
                                                    and 250.602 was
                                                    revised and
                                                    incorporated into
                                                    this section
                                                    relating to safety
                                                    measures on a
                                                    platform producing
                                                    wells or other
                                                    hydrocarbon flow.
NEW...........................  250.724..........  New section relating
                                                    to real-time
                                                    monitoring
                                                    requirements.
------------------------------------------------------------------------
               Blowout Preventer (BOP) System Requirements
------------------------------------------------------------------------
250.416; 250.440; 250.516;      250.730..........  Similar language was
 250.616(a) through (e);                            revised and
 250.1706.                                          incorporated into
                                                    this section about
                                                    general requirements
                                                    for BOP systems and
                                                    their components.
250.416; 250.515; 250.615;      250.731..........  Similar language was
 250.1705.                                          revised and
                                                    incorporated into
                                                    this section about
                                                    submittal
                                                    requirements for
                                                    information about
                                                    BOP systems and
                                                    their components.
250.416; 250.515; 250.615;      250.732..........  Similar language was
 250.1705.                                          revised and
                                                    incorporated into
                                                    this section
                                                    relating to third-
                                                    party information
                                                    for BOP systems and
                                                    their components.
250.441; 250.443(c), (d);       250.733..........  Similar language was
 250.516; 250.616(a) through                        revised and
 (e); 250.1706.                                     incorporated into
                                                    this section and new
                                                    language was added
                                                    relating to
                                                    requirements for a
                                                    surface BOP stack.
250.442; 250.443(c), (d);       250.734..........  Similar language was
 250.516; 250.616(a) through                        revised and
 (e); 250.1706.                                     incorporated into
                                                    this section and new
                                                    language was added
                                                    relating to
                                                    requirements for a
                                                    subsea BOP system.
250.441; 250.443; 250.516;      250.735..........  Similar language was
 250.616; 250.1706.                                 revised and
                                                    incorporated to this
                                                    section and new
                                                    language was added
                                                    relating to
                                                    equipment and
                                                    systems all BOPs
                                                    must have.
250.444; 250.445; 250.516;      250.736..........  Similar language was
 250.616(a) through (e);                            revised and
 250.1707.                                          incorporated into
                                                    this section
                                                    pertaining to
                                                    requirements for
                                                    choke manifolds,
                                                    kelly valves, inside
                                                    BOPs, and drill
                                                    string safety
                                                    valves.
250.447; 250.448; 250.449;      250.737..........  Added new language
 250.517; 250.617; 250.1707.                        and similar language
                                                    was revised and
                                                    incorporated into
                                                    this section
                                                    relating to BOP
                                                    system testing
                                                    requirements.
250.451 and 250.517...........  250.738..........  Added new language
                                                    and similar language
                                                    was revised and
                                                    incorporated into
                                                    this section for
                                                    situations arising
                                                    involving BOP
                                                    equipment or
                                                    systems.
250.446; 250.517; 250.618;      250.739..........  Similar language was
 250.1708.                                          revised and
                                                    incorporated into
                                                    this section
                                                    pertaining to BOP
                                                    maintenance and
                                                    inspection
                                                    requirements.
------------------------------------------------------------------------
                          Records and Reporting
------------------------------------------------------------------------
250.466.......................  250.740..........  Redesignated and
                                                    revised the types of
                                                    records to keep.
250.467.......................  250.741..........  Redesignated and
                                                    added records
                                                    relating to real-
                                                    time monitoring
                                                    data.
250.468(a)....................  250.742..........  Redesignated.
250.468(b) and (c)............  250.743..........  Redesignated and
                                                    revised to include
                                                    more requirements
                                                    for the well
                                                    activity reporting.
250.465; 250.1712; 250.1717...  250.744..........  Redesignated and
                                                    revised to include
                                                    additional end of
                                                    operation reporting
                                                    requirements.
250.469.......................  250.745..........  Redesignated and
                                                    revised to update
                                                    references.
250.426; 250.450; 250.517;      250.746..........  Similar language was
 250.617; 250.1707.                                 revised and
                                                    incorporated into
                                                    this section
                                                    pertaining to record-
                                                    keeping for casing,
                                                    liner, and BOP
                                                    tests.
------------------------------------------------------------------------
                                Subpart P
------------------------------------------------------------------------
250.1612......................  250.1612.........  Revised to update
                                                    references.
------------------------------------------------------------------------
                                Subpart Q
------------------------------------------------------------------------
250.1703......................  250.1703.........  Revised paragraph (b)
                                                    to have new packers
                                                    and bridge plug
                                                    requirements,
                                                    including API Spec.
                                                    11D1. Revised
                                                    paragraph (e);
                                                    Redesignated
                                                    existing paragraph
                                                    (f) as (g); and
                                                    added a new
                                                    paragraph (f) to
                                                    follow the
                                                    applicable
                                                    requirements of
                                                    Subpart G.
250.1704......................  250.1704.........  Revised paragraphs
                                                    (g) and added new
                                                    paragraph (h) about
                                                    APMs and EORs.
250.1705......................  250.731, 250.732.  Removed--similar
                                                    language found in
                                                    new Subpart G.

[[Page 21537]]

 
250.1706(a) through (e).......  250.730; 250.733,  Removed--similar
                                 250.734, and       language found in
                                 250.735.           new Subpart G.
250.1706(f) through (h).......  250.1706(a)        Revised the section
                                 through (c).       heading;
                                                    redesignated.
250.1707......................  250.711, 250.736,  Removed--similar
                                 250.737, 250.746.  language found in
                                                    new Subpart G.
250.1708......................  250.739..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.1709......................  250.720..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.1715(a)(3)(iii)(B)........  250.1715(a)(3)(ii  Added the word
                                 i)(B).             ``casing.''
250.1717......................  250.744..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.1721(g)...................  250.744..........  Removed--similar
                                                    language found in
                                                    new Subpart G.
250.1721(h)...................  250.1721(g)......  Redesignated and text
                                                    remains unchanged.
------------------------------------------------------------------------

VII. 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 (OIRA) in the OMB will review all significant rules. To 
determine if this proposed rulemaking is a significant rule, BSEE had 
an outside contractor prepare an economic analysis to assess the 
anticipated costs and potential benefits of the proposed rulemaking. 
The following discussion summarizes the economic analysis; a complete 
copy of the economic analysis can be viewed at www.Regulations.gov (use 
the keyword/ID ``BSEE-2015-0002'').
    Changes to Federal regulations must undergo several types of 
economic analyses. First, E.O.s 12866 and 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 the E.O. and 
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.

    The BSEE has determined that the proposed 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 1 year 
of the 10-year analysis period. Accordingly, OMB has reviewed this 
proposed regulation.
1. Need for Regulation
    As previously explained, BSEE has identified a need to amend the 
existing well-control regulations to ensure that oil and gas operations 
on the OCS are conducted in a safe and environmentally responsible 
manner. In particular, BSEE considers the proposed 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.\6\ The government and industry conducted 
multiple investigations to determine the cause of the Deepwater Horizon 
incident; many of these investigations identified BOP performance as a 
concern. The 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 
this concern. The investigations and the forum resulted in a set of 
recommendations to enhance safety and environmental protection of 
offshore operations by improving BOP performance.
---------------------------------------------------------------------------

    \6\ 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 paid over $14 billion to Federal, State, and local 
governments as well as private parties for economic claims and other 
expenses. See ``Deepwater Horizon Oil Spill: Recent Activities and 
Ongoing Developments,'' J. Ramseur & C. Hagerty (2014), 
Congressional Research Office, available at: https://www.fas.org/sgp/crs/misc/R42942.pdf.
---------------------------------------------------------------------------

    As the 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 industry's responses to the incident, BSEE has determined that the 
requirements contained in this proposed rule are critical to address 
risks associated with offshore operations. BSEE has determined that the 
well-control regulations needed to be updated to incorporate some of 
these recommendations. Other recommendations are being studied for 
consideration in future rulemakings.
    The proposed rule would create a new Subpart G in 30 CFR part 250 
to consolidate requirements for drilling, completion, workover, and 
decommissioning operations. Consolidating the requirements would 
improve efficiency and consistency of the regulations and allow for 
flexibility in future rulemakings. The proposed rule would also revise 
provisions in Subparts D, E, F, and Q of part 250 to address concerns 
raised in the investigations, internally within BSEE, and at the public 
forum. Finally, the proposed rule would incorporate API Standard 53 to 
ensure better BOP operability and more robust regulatory oversight.
 2. Alternatives
    The BSEE has considered three regulatory alternatives:
    (1) Promulgate the requirements contained within the proposed rule, 
including increasing the BOP testing frequency for workover and 
decommissioning operations from the current requirement of once every 7 
days to the proposed requirement of

[[Page 21538]]

once every 14 days. The following chart identifies the BOP testing 
changes related to Alternative 1:

                                              BOP Pressure Testing
----------------------------------------------------------------------------------------------------------------
           Operation                   Current testing frequency                Proposed testing 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 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. The following chart identifies the BOP testing changes 
related to Alternative 2:

                                                                  BOP Pressure Testing
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Proposed testing frequency
           Operation                   Current testing frequency                     (alternative 1)                  Alternative 2 testing 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.*
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Includes change from current 7 days to proposed 14 days

    (3) Take no regulatory action and continue to rely on existing 
well-control regulations in combination with permit conditions, DWOPs, 
operator prudence, and industry standards.
    By taking no regulatory action, BSEE would leave unaddressed most 
of the concerns and recommendations that were raised \7\ regarding the 
safety of offshore oil and gas operations and the potential for another 
event with consequences similar to those of the Deepwater Horizon 
incident.
---------------------------------------------------------------------------

    \7\ See the DOI JIT report, REPORT REGARDING THE CAUSES OF THE 
APRIL 20, 2010 MACONDO WELL BLOWOUT, September 14, 2011.; The 
National Commission final report, DEEP WATER, The Gulf Oil Disaster 
and the Future of Offshore Drilling, January 11, 2011; The Chief 
Counsel for the National Commission report, Macondo The Gulf Oil 
Disaster, February 17, 2011; National Academy of Engineering final 
report, Macondo Well-Deepwater Horizon Blowout, December 14, 2011; 
BSEE public offshore energy safety forum, May 22, 2012.
---------------------------------------------------------------------------

    Alternative 2 was not selected because BSEE is lacking critical 
data on testing frequency and equipment reliability. This issue may be 
considered in the final rulemaking if BSEE receives sufficient data to 
support Alternative 2.
    The BSEE has elected to move forward with Alternative 1--the 
proposed rule--which would incorporate recommendations provided by 
government, industry, academia and other stakeholders, as well as API 
Standard 53. In addition to addressing concerns and aligning with 
industry standards, BSEE is functioning in a prudent capacity with this 
proposed rule by advancing several of the more critical capabilities 
beyond current industry standards based on internal knowledge and 
experience. The proposed rule would also improve efficiency and 
consistency of the regulations and allow for flexibility in future 
rulemakings.
    The BSEE is requesting comments on how long it would take to come 
into compliance with the proposed rule as well as any other 
alternatives BSEE may reasonably consider, including alternatives to 
the specific provisions contained in the proposed rule.
3. Economic Analysis
    The BSEE's economic analysis evaluated the expected impacts of the 
proposed rule compared with the baseline. The baseline refers to 
current industry practice in accordance with existing regulations, 
industry permits, DWOPs, and industry standards with which operators 
already comply.\8\ Impacts that exist as part of the baseline were not 
considered costs or benefits of the proposed rule. Thus, the cost 
analysis evaluates only activities and capital investments required by 
the proposed rule that represent a change from the baseline. These 
estimated compliance costs are discussed more specifically in the 
associated full initial regulatory impact analysis (RIA), which can be 
viewed at www.regulations.gov (use the keyword/ID ``BSEE-2015-0002'').
---------------------------------------------------------------------------

    \8\ 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.
---------------------------------------------------------------------------

    The analysis covers 10 years (2015 through 2024) to ensure it 
encompasses the significant costs and benefits likely to result from 
this proposed rule. A 10-year period was used for this analysis because 
of the uncertainty associated with predicting industry's activities and 
the advancement of technical capabilities beyond 10 years. It is very 
difficult to predict, plan, or project costs associated with 
technological innovation due to unknown technological or business 
constraints that could drive a product into mainstream adoption or into 
obsolescence. The regulated community itself has difficulty conducting 
business modeling beyond a 10-year time frame. Over time, the costs 
associated with a particular new technology may drop because of various 
supply and demand factors, causing the technology to be more broadly 
adopted. In other cases, an existing technology may be replaced by a 
lower-cost alternative as business needs may drive technological 
innovation. Extrapolating costs and benefits beyond this 10-year time 
frame would produce more ambiguous results and therefore be 
disadvantageous in determining actual costs and benefits likely to 
result from this proposed rule. The BSEE concluded that this 10-year 
analysis period provides the best overall ability to forecast reliable 
costs and benefits likely to result from this proposed rule. 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.''
    The BSEE welcomes comments on this analysis, including potential 
sources of data or information on the costs and benefits of this 
proposed rule. The BSEE quantified and monetized the

[[Page 21539]]

costs, using 2013 data, of all the provisions in the proposed rule 
determined to result in a change compared to the baseline, 
including:xs112
--Additional information in the description of well-drilling design 
criteria;
--Additional information in the drilling prognosis;
--Prohibition of a liner as conductor casing;
--Additional capping stack testing requirements;
--Additional information in the APM for installed packers;
--Additional information in the APM for pulled and reinstalled packers;
--Rig movement reporting;
--Fitness requirements for MODUs and lift boats;
--Foundation requirements for MODUs and lift boats;
--Monitoring of well operations with a subsea BOP;
--Additional documentation and certification requirements for BOP 
systems and system components;
--Additional information in the APD, APM, or other submittal for BOP 
systems and system components;
--Submission of a Mechanical Integrity Assessment Report by a BSEE-
approved verification body;
--New surface BOP system requirements;
--New subsea BOP system requirements;
--New surface accumulator system requirements;
-- Chart recorders;
-- Notification and procedures requirements for testing of surface BOP 
systems;
-- Alternating BOP control station function testing;
-- ROV intervention function testing; autoshear, deadman, and EDS 
function testing on subsea BOPs;
-- Approval for well-control equipment not covered in Subpart G;
-- Breakdown and inspection of BOP system and components;
-- Additional recordkeeping for real-time monitoring; and
-- Industry familiarization with the new rule.

    The BSEE estimated the benefits derived from time savings 
associated with Sec.  250.737(d)(10) of the proposed rule and the 
benefits derived from the reduction in oil spills and fatalities using 
the incident-reducing potential of the proposed rule as a whole. The 
largest time savings benefits would result from proposed Sec.  250.737 
(d)(10), which would streamline the BOP function testing criteria and 
increase the intervals between this testing. Although we also consider 
benefits from potential reductions in oil spills and reduced 
fatalities, the time savings benefits of the proposed rule result in 
benefits greater than the costs of the rule to the extent that those 
costs could be quantified. In other words, based upon existing 
available data, the proposed rule is cost-beneficial when only the 
benefits resulting from time savings are considered.\9\
---------------------------------------------------------------------------

    \9\ Moreover, the analysis of Alternatives 1 and 2 did not 
consider potential benefits related to extended equipment life and 
reduced well control risks arising from fewer pressure tests and 
fewer trips out of the hole.
---------------------------------------------------------------------------

    The same is true of Alternative 2. A larger time savings benefit 
would result from changing the BOP pressure testing interval for 
workover and decommissioning from 7 days to 14 days plus increasing the 
BOP pressure testing interval for all operations (including drilling, 
completions, workovers, and decommissioning) from 14 days to 21 days. 
This alternative would result in additional time savings to industry by 
decreasing the number of required tests per year for operators. This 
time savings would result in greater net benefits to operators.
    We did not, however, include reduced trip time to perform BOP 
testing in the calculations of savings for Alternative 2.\10\ Drilling 
trip time depends on factors such as well depth, hole size, mud weight, 
the amount of open hole, hole conditions, surge and swab pressure, 
borehole deviation, bottom hole assembly configuration, hoisting 
capacity, type of rigs, and crew efficiency. BSEE is not aware of any 
analysis of offshore operations that provides reasonable estimates of 
average trip time that could be used for the purpose of this 
calculation. In addition, it is common practice in the GOM to perform 
BOP tests earlier than the required interval whenever operational 
opportunities become available (i.e., whenever there is no drill pipe 
across the BOPs due to the need to change drill bits). This practice 
would reduce the overall benefits from this alternative. BSEE requests 
comments and data on both of these issues to assist in the assessment 
of the overall benefits of this alternative.
---------------------------------------------------------------------------

    \10\ Trip time refers to the time needed to stop drilling or 
workover operations, remove or raise the drill/work string from the 
well, and then lower the string back to the bottom of the well to 
restart operations. A trip is often made to change a dull drill bit 
and/or to perform the pressure test or BOP test. During some deep 
drilling situations, the trip time may equal or exceed the on-bottom 
drilling time.
---------------------------------------------------------------------------

    The proposed rule also would reduce the probability of oil spills, 
and the provisions with the highest costs to industry (such as real-
time monitoring of well operations and alternating BOP control station 
function testing) will have the largest impact on reducing the risk of 
spills. If the proposed rule reduces the risk of incidents, benefits 
would result from the avoided costs associated with oil spills related 
to personal injuries, natural resource damages, lost hydrocarbons, 
spill containment and cleanup, and lost recreational use and lost 
profits from commercial fishing. The magnitude of these benefits, 
however, is dependent on the effectiveness of the proposed rule in 
reducing the number of incidents, which is uncertain.
    To estimate the potential benefits of the proposed rule associated 
with reducing the risk of 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 
between 1964 and 2010, BSEE identified 27 blowouts associated with oil 
spills greater than 10 barrels \11\ and used this data within the 
economic analysis (see the initial RIA for details).\12\ Blowouts that 
resulted in uncontrolled flow of gas, damage to a rig, and/or harm to 
personnel (but not oil spills over 10 barrels) are not reflected in 
this analysis.\13\ Accordingly, the benefits and the overall risk 
reduction associated with this proposed rule may be understated. The 
BSEE is specifically soliciting comments on any data and costs 
associated with any blowout that did not result in an oils spill 
greater than 10 barrels, and how to include that information within the 
economic analysis.
---------------------------------------------------------------------------

    \11\ See https://www.bsee.gov/Inspection-and-Enforcement/Accidents-and-Incidents/Spills/.
    \12\ BSEE based the analysis on the historical oil spill 
database for the period between 1964 and 2010, but recognizes that 
significant regulatory and technological improvements have taken 
place since 1964. If BSEE limited the analysis to the period 1988 
(when the Department's offshore regulatory program was 
comprehensively overhauled) through 2010, the potential benefits 
from this reduction of risk would be substantially greater, due to 
the impact of the Deepwater Horizon costs over such a shorter time 
period.
    \13\ Previous MMS studies indicate a total of 126 blowouts 
during drilling operations on the OCS between 1971 and 2006. These 
blowouts resulted in 26 fatalities, 63 injuries, damage to 
facilities and equipment, and the release of hydrocarbons.
---------------------------------------------------------------------------

    The actual reduction in the risk of oil spills to be achieved by 
the proposed rule cannot be determined. Although a sensitivity analysis 
was conducted for levels of risk reduction from 0 to 20 percent, our 
economic analysis used a 1 percent risk reduction because it

[[Page 21540]]

represents BSEE's best expert judgment of the lower bound of risk 
reduction that could result from the proposed rule.\14\ We multiplied 
the annual number of spilled barrels of oil (the total number of 
barrels spilled in the incidents divided by 46.945 years) by 1 percent 
to estimate the expected annual reduction in barrels of oil spilled 
associated with the proposed rule.
---------------------------------------------------------------------------

    \14\ 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,'' American Bureau of Shipping and ABSG 
Consulting, under BSEE contract M11PC00027 (June 2013); ``Deepwater 
Horizon Blowout Preventer Failure Analysis: Report to the U.S. 
Chemical Safety and Hazard Investigation Board,'' Engineering 
Services (2014). Given this accumulated knowledge of failure 
likelihoods, and analysis of how those likelihoods would be reduced 
by the proposed rule, BSEE has determined that 1 percent is a 
reasonable lower-bound of risk reduction that could occur as a 
result of the proposed rule.
---------------------------------------------------------------------------

    We then multiplied the annual reduction in spilled barrels of oil 
by the social and private cost of a spilled barrel of oil, which is 
estimated at $3,599 per barrel. This estimate was derived from the 
Bureau of Ocean Energy Management (BOEM) ``Economic Analysis 
Methodology for the Five Year OCS Oil and Gas Leasing Program for 2012-
2017'' (2012) (the BOEM Case Study),\15\ and includes costs associated 
with natural resource damages, the value of lost hydrocarbons, and 
spill cleanup and containment.\16\ We used a natural resource damage 
cost of $642 per barrel and a cleanup and containment cost of $2,857 
per barrel as estimated for the GOM in the BOEM Case Study. Consistent 
with the BOEM Case Study, we used a value of lost hydrocarbons per 
barrel of $100. The BSEE recognizes the uncertainty associated with 
projecting the price of oil during the 10-year period of analysis and 
thus includes a sensitivity analysis in the initial RIA for the price 
of oil.
---------------------------------------------------------------------------

    \15\ The BOEM Case Study presents seven separate cost categories 
to estimate the impact of a catastrophic spill, including natural 
resource damages, as well as impacts on recreation and commercial 
fishing. The BOEM Case Study is available at: https://www.boem.gov/uploadedFiles/BOEM/Oil_and_Gas_Energy_Program/Leasing/Five_Year_Program/2012-2017_Five_Year_Program/PFP%20EconMethodology.pdf.
    \16\ 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 that reflects data from the Deepwater Horizon 
incident.
---------------------------------------------------------------------------

    In addition to the time savings and risk reduction benefits, the 
proposed rule has other benefits. Due to difficulties in measuring and 
monetizing these benefits, BSEE does not offer a quantitative 
assessment of them. The BSEE has used a conservative approach 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 only 
considers 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 proposed rule under the 
assumption that the reduction in the risk of incidents is 1 percent. 
Although the analysis presents these benefit estimates based on our 
lower bound assumption of potential risk reduction, there is 
uncertainty around the level of risk reduction the proposed rule would 
actually achieve. Accordingly, it is reasonably possible that the 
actual benefits realized from the reductions in spill incidents will be 
different from those assessed in this analysis. Nonetheless, as 
discussed above, the proposed rule is cost-justified on the basis of 
time savings alone.

                                                                 Exhibit 1--Net Benefits
                                               [At a 1-percent risk reduction from the proposed rule] \1\
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                             Total benefits     Total benefits                         Net benefits       Net benefits
                           Year                             (alternative 1)    (alternative 2)      Total costs      (alternative 1)    (alternative 2)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                 2012 dollars/year
--------------------------------------------------------------------------------------------------------------------------------------------------------
 1. 2015.................................................       $153,988,977       $528,988,977       $164,862,782      ($10,873,805)       $364,126,195
 2. 2016.................................................        153,988,977        528,988,977         77,431,590         76,557,387        451,557,387
 3. 2017.................................................        153,988,977        528,988,977         77,431,590         76,557,387        451,557,387
 4. 2018.................................................        153,988,977        528,988,977         77,431,590         76,557,387        451,557,387
 5. 2019.................................................        153,988,977        528,988,977         77,431,590         76,557,387        451,557,387
 6. 2020.................................................        153,988,977        528,988,977         98,931,590         55,057,387        430,057,387
 7. 2021.................................................        153,988,977        528,988,977         77,431,590         76,557,387        451,557,387
 8. 2022.................................................        153,988,977        528,988,977         77,431,590         76,557,387        451,557,387
 9. 2023.................................................        153,988,977        528,988,977         77,431,590         76,557,387        451,557,387
10. 2024.................................................        153,988,977        528,988,977         77,431,590         76,557,387        451,557,387
                                                          ----------------------------------------------------------------------------------------------
Undiscounted 10-year total...............................      1,539,889,771      5,289,889,771        883,247,090        656,642,682      4,406,642,682
10-Year Total with 3% discounting........................      1,313,557,210      4,512,383,273        763,397,731        550,159,479      3,748,985,543
10-Year Total with 7% discounting........................      1,081,554,137      3,715,397,215        639,884,837        441,669,301      3,075,512,378
                                                          ----------------------------------------------------------------------------------------------
10-year Average..........................................        153,988,977        528,988,977         88,324,709         65,664,268        440,664,268
Annualized with 3% discounting...........................        153,988,977        528,988,977         89,493,503         64,495,474        439,495,474
Annualized with 7% discounting...........................        153,988,977        528,988,977         91,105,205         62,883,772        437,883,772
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Totals may not add because of rounding.

 4. Sensitivity Analysis
    This section presents sensitivity analysis of the potential 
benefits of the proposed rule that could result from varying the 
following factors:
    (a) The level of risk reduction of oil spills achieved by the 
proposed rule;
    (b) The level of risk reduction of fatalities achieved by the 
proposed rule; and
    (c) The price of a barrel of oil (i.e., the value of lost 
hydrocarbons).
    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

[[Page 21541]]

proposed rule is expected to have positive net benefits for the full 
range of risk reduction levels.
    In addition to the time savings and the prevention of oil spills, 
the proposed rule is anticipated to reduce the risk of fatalities to 
rig workers. The oil and gas extraction industry is characterized by a 
relatively small percentage of the national workforce, but with a 
fatality rate that is higher than the rate for most industries.

                                            Exhibit 2--Net Benefits Under Different Risk Reduction Levels \1\
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                              Benefits (7%       Benefits (3%       Net benefits     Net benefits (7%   Net benefits (3%
       Annual risk reduction (%)         Annual benefits      discounting)       discounting)      (undiscounted)      discounting)       discounting)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                          Total 10-Year
--------------------------------------------------------------------------------------------------------------------------------------------------------
0.....................................                 $0     $1,053,537,231     $1,279,530,426       $616,752,910       $413,652,394       $516,132,695
1.....................................          3,988,977      1,081,554,137      1,313,557,210        656,642,682        441,669,301        550,159,479
2.....................................          7,977,954      1,109,571,044      1,347,583,994        696,532,453        469,686,207        584,186,263
3.....................................         11,966,931      1,137,587,950      1,381,610,778        736,422,225        497,703,113        618,213,047
4.....................................         15,955,909      1,165,604,856      1,415,637,562        776,311,996        525,720,019        652,239,832
5.....................................         19,944,886      1,193,621,762      1,449,664,346        816,201,768        553,736,926        686,266,616
6.....................................         23,933,863      1,221,638,669      1,483,691,131        856,091,539        581,753,832        720,293,400
7.....................................         27,922,840      1,249,655,575      1,517,717,915        895,981,311        609,770,738        754,320,184
8.....................................         31,911,817      1,277,672,481      1,551,744,699        935,871,082        637,787,644        788,346,968
9.....................................         35,900,794      1,305,689,387      1,585,771,483        975,760,854        665,804,551        822,373,752
10....................................         39,889,771      1,333,706,294      1,619,798,267      1,015,650,625        693,821,457        856,400,537
11....................................         43,878,749      1,361,723,200      1,653,825,051      1,055,540,397        721,838,363        890,427,321
12....................................         47,867,726      1,389,740,106      1,687,851,836      1,095,430,168        749,855,269        924,454,105
13....................................         51,856,703      1,417,757,012      1,721,878,620      1,135,319,939        777,872,176        958,480,889
14....................................         55,845,680      1,445,773,919      1,755,905,404      1,175,209,711        805,889,082        992,507,673
15....................................         59,834,657      1,473,790,825      1,789,932,188      1,215,099,482        833,905,988      1,026,534,457
16....................................         63,823,634      1,501,807,731      1,823,958,972      1,254,989,254        861,922,894      1,060,561,242
17....................................         67,812,611      1,529,824,637      1,857,985,756      1,294,879,025        889,939,801      1,094,588,026
18....................................         71,801,589      1,557,841,544      1,892,012,541      1,334,768,797        917,956,707      1,128,614,810
19....................................         75,790,566      1,585,858,450      1,926,039,325      1,374,658,568        945,973,613      1,162,641,594
20....................................         79,779,543      1,613,875,356      1,960,066,109      1,414,548,340        973,990,519      1,196,668,378
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ For Alternative 1, the proposed rule.

    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). The benefits of occupational risk 
reduction are usually measured using the value of a statistical life 
(VSL). The BSEE used a VSL of $8.4 million to estimate the avoided 
costs associated with a reduction in the fatality rate \17\ (see 
initial RIA for details of VSL calculations).
---------------------------------------------------------------------------

    \17\ Between 1964 and 2010, there were 27 blowouts with oil 
spills greater than 10 barrels. Only two of these events resulted in 
fatalities: the 1984 blowout and the 2010 Deepwater Horizon incident 
that resulted in 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 (15/46.945). Using a VSL of $8,423,301, 
the average value of fatalities is $2,691,423 per year (0.320 x 
$8,423,301). Therefore, each 1 percent reduction in the risk of a 
fatality results in a risk reduction benefit of $26,914 (1 percent x 
$2,691,423). Note that this calculation likely understates the 
benefits associated with fatality risk reduction because blowouts 
that did not result in an oil spill greater than 10 barrels were not 
part of the database used for this analysis. Previous MMS studies 
indicate a total of 126 blowouts during drilling operations on the 
OCS between 1971 and 2006. These blowouts resulted in 26 fatalities, 
63 injuries, damage to facilities and equipment, and the release of 
hydrocarbons. Accounting for any additional fatalities would 
increase the fatality risk reduction benefits.

                                        Exhibit 3--Monetized Benefits From Averted Fatalities W/Net Benefits \1\
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                             Fatality risk     Net benefits of       Net benefits of proposed rule with fatality risk
                                                           reduction benefit    proposed rule           reduction  (at a 1-percent risk reduction)
                                                          -------------------  without fatality --------------------------------------------------------
                                                                                risk reduction
               Fatality risk reduction (%)                                     (at a 1-percent
                                                              Undiscounted     risk  reduction)     Undiscounted      3% Discounting     7% Discounting
                                                                             -------------------
                                                                                 Undiscounted
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                   Total 10-year
--------------------------------------------------------------------------------------------------------------------------------------------------------
0........................................................                 $0       $656,642,682       $656,642,682       $550,159,479       $441,669,301
1........................................................            269,142        656,642,682        656,911,824        550,389,063        441,858,335
2........................................................            538,285        656,642,682        657,180,967        550,618,647        442,047,369
3........................................................            807,427        656,642,682        657,450,109        550,848,231        442,236,403
4........................................................          1,076,569        656,642,682        657,719,251        551,077,814        442,425,438
5........................................................          1,345,712        656,642,682        657,988,393        551,307,398        442,614,472
6........................................................          1,614,854        656,642,682        658,257,536        551,536,982        442,803,506
7........................................................          1,883,996        656,642,682        658,526,678        551,766,566        442,992,541

[[Page 21542]]

 
8........................................................          2,153,139        656,642,682        658,795,820        551,996,150        443,181,575
9........................................................          2,422,281        656,642,682        659,064,963        552,225,734        443,370,609
10.......................................................          2,691,423        656,642,682        659,334,105        552,455,318        443,559,644
11.......................................................          2,960,565        656,642,682        659,603,247        552,684,901        443,748,678
12.......................................................          3,229,708        656,642,682        659,872,390        552,914,485        443,937,712
13.......................................................          3,498,850        656,642,682        660,141,532        553,144,069        444,126,746
14.......................................................          3,767,992        656,642,682        660,410,674        553,373,653        444,315,781
15.......................................................          4,037,135        656,642,682        660,679,817        553,603,237        444,504,815
16.......................................................          4,306,277        656,642,682        660,948,959        553,832,821        444,693,849
17.......................................................          4,575,419        656,642,682        661,218,101        554,062,405        444,882,884
18.......................................................          4,844,562        656,642,682        661,487,244        554,291,988        445,071,918
19.......................................................          5,113,704        656,642,682        661,756,386        554,521,572        445,260,952
20.......................................................          5,382,846        656,642,682        662,025,528        554,751,156        445,449,986
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ For Alternative 1, the proposed rule.

    As an additional sensitivity analysis, we estimated the net 
benefits of the proposed rule for different assumptions regarding the 
value of lost hydrocarbons. In the analysis presented above, BSEE used 
$100 per barrel for the value of lost hydrocarbons in the event of a 
spill. To reflect the fluctuations in the price of a barrel of oil that 
may occur during the 10-year analysis period, we also estimated the net 
benefits of the proposed rule for two alternative price scenarios: $50/
barrel and $130/barrel. Exhibit 4 presents the results, which indicate 
that the price of oil has a very limited impact on the net benefits of 
the proposed rule.

                             EXHIBIT 4--Net Benefits Under Three Oil Price Scenarios
                             [At a 1-percent risk reduction from the proposed rule]
----------------------------------------------------------------------------------------------------------------
                        Year                              $50/barrel          $100/barrel         $130/barrel
----------------------------------------------------------------------------------------------------------------
                                                                          (2012 dollars/year)
                                                     -----------------------------------------------------------
 1. 2015............................................       ($10,928,596)       ($10,873,805)       ($10,840,931)
 2. 2016............................................         76,502,597          76,557,387          76,590,262
 3. 2017............................................         76,502,597          76,557,387          76,590,262
 4. 2018............................................         76,502,597          76,557,387          76,590,262
 5. 2019............................................         76,502,597          76,557,387          76,590,262
 6. 2020............................................         55,002,597          55,057,387          55,090,262
 7. 2021............................................         76,502,597          76,557,387          76,590,262
 8. 2022............................................         76,502,597          76,557,387          76,590,262
 9. 2023............................................         76,502,597          76,557,387          76,590,262
10. 2024............................................         76,502,597          76,557,387          76,590,262
----------------------------------------------------------------------------------------------------------------
Undiscounted 10-year total..........................        656,094,777         656,642,682         656,971,425
10-Year Total with 3% discounting...................        549,692,105         550,159,479         550,439,903
10-Year Total with 7% discounting...................        441,284,475         441,669,301         441,900,196
----------------------------------------------------------------------------------------------------------------
10-year Average.....................................         65,609,478          65,664,268          65,697,142
Annualized with 3% discounting......................         64,440,684          64,495,474          64,528,349
Annualized with 7% discounting......................         62,828,982          62,883,772          62,916,646
----------------------------------------------------------------------------------------------------------------

    BSEE has concluded, after consideration of the impacts of the 
proposed rule, that the societal benefits would justify the societal 
costs.
    E.O. 13563 reaffirms the principles of E.O. 12866 while calling for 
improvements in the Nation's regulatory system to promote 
predictability, to reduce uncertainty, and to use the best, most 
innovative, and least burdensome tools for achieving regulatory ends. 
The E.O. directs agencies to consider regulatory approaches that reduce 
burdens and maintain flexibility and freedom of choice for the public 
where these approaches are relevant, feasible, and consistent with 
regulatory objectives. The E.O. 13563 emphasizes further that 
regulations must be based on the best available science and that the 
rulemaking process must allow for public participation and an open 
exchange of ideas. The BSEE engineers and technical staff have and will 
continue to work to ensure that this proposed rulemaking is based on 
sound engineering principles and considers options identified through 
research, coordination with standards-development organizations, and

[[Page 21543]]

interaction with the OCS industry. Thus, we have developed this rule in 
a manner consistent with these requirements.
    In addition, BSEE is considering whether to use probabilistic risk 
assessment methodology--including event trees, statistical information 
(e.g., failure rates of valves), probabilities, uncertainties, and 
assumptions--that potentially could help inform BSEE's final decision 
on the proposed regulation. Further details about a potential 
probabilistic risk assessment approach are provided in the initial RIA. 
The BSEE is interested in the public's views on the potential 
advantages and disadvantages to development of a probabilistic risk 
assessment model for this rulemaking. We specifically seek comments on 
the following issues:
    (a) What would be the potential advantages and disadvantages if 
BSEE were to move to risk-informed decisions in this proposed rule 
through the use of methods such as probabilistic risk assessments and 
event trees?
    (b) Given that there are a significant number of offshore drilling 
operations with different types of rig construction and drilling plans, 
if BSEE were to use event trees in risk reduction assessments, how much 
detail would such event trees need so that they would be representative 
of the affected operators and best inform stakeholders and decision 
makers? Commenters should provide examples of benefits and costs of any 
suggested level of detail and explain why that detail would be 
appropriate.
    (c) Describe any completed, ongoing or planned activities, not 
associated with BSEE, that would provide information beneficial to the 
potential development of a probabilistic risk assessment approach for 
this rulemaking, including any analyses identifying areas of 
significant risk or uncertainties. If you do so, provide timelines for 
the activity, if not already completed; indicate whether the activity 
will be peer-reviewed; and explain how it could be used in the 
potential development of a probabilistic risk assessment approach.
    (d) Describe any other planned or ongoing data collection efforts 
that could provide relevant information useful in the potential 
development of probabilistic risk assessment models for offshore oil 
and gas activities. If there are no such efforts at this time, how 
could such a data collection program be developed?
    (e) What challenges and concerns would there be to industry 
providing data to inform and help BSEE decide whether to engage in 
probabilistic risk assessment modeling for this proposed rule? What are 
ways that the challenges and concerns could be mitigated?
    The BSEE is also requesting comments on other ways to improve this 
economic analysis. The BSEE is specifically requesting comments on the 
following issues:
    (a) Which provisions of the proposed rule are most, or least, 
likely to reduce the risk of a well control incident?
    (b) For each proposed rule provision:
    (1) For what kinds of well control incidents (e.g., hydrocarbon 
leakage through annulus cement barrier, weather-related incident, 
collision) would the provision reduce risk?
    (2) By what mechanism would the provision reduce risk (e.g., 
reduction of the rate of failure of a particular technology)?
    (c) What risk reduction level (or range of risk reduction levels) 
would the individual provisions achieve?
    Please provide supporting data and studies to support your 
comments.

Regulatory Flexibility Act

    The DOI certifies that this proposed rule is likely to have a 
significant economic effect on a substantial number of small entities 
as defined under the Regulatory Flexibility Act, 5 U.S.C. 601 et seq. 
(RFA).
    The RFA, at 5 U.S.C. 603, requires agencies to prepare a regulatory 
flexibility analysis to determine whether a regulation would have a 
significant economic impact on a substantial number of small entities. 
Further, under the Small Business Regulatory Enforcement Fairness Act 
of 1996, 5 U.S.C. 801 (SBREFA), an agency is required to produce 
compliance guidance for small entities if the rule would have a 
significant economic impact. For the reasons explained in this section, 
BSEE believes that this proposed rule would 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 Initial Regulatory Flexibility Analysis assesses the impact of 
this proposed rule on small entities, as defined by the applicable 
Small Business Administration (SBA) size standards.
1. Description of the Reasons That Action by the Agency Is Being 
Considered
    The BSEE identified a need to amend the existing well-control 
regulations to improve the capability of the oil and gas industry to 
ensure that oil and gas operations on the OCS are safe and protect the 
environment. In particular, BSEE considers the proposed rule necessary 
to reduce the likelihood of all oil and gas blowouts, 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. Government and industry conducted multiple 
investigations to determine the cause of the Deepwater Horizon 
incident; many of these investigations identified BOP performance as a 
concern. The 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 
this concern. The investigations and the forum resulted in a set of 
recommendations to improve well-control operations, including BOP 
performance.
    The BSEE determined that the well-control regulations needed to be 
updated to incorporate some of these recommendations while others are 
being studied for consideration in future rulemakings. The proposed 
rule would create a new Subpart G in 30 CFR part 250 to consolidate the 
requirements for drilling, completion, workover, and decommissioning 
operations. Consolidating these requirements would improve the 
efficiency and consistency of the regulations and would allow for 
flexibility in future rulemakings. The proposed rule would also revise 
existing provisions throughout Subparts A, B, D, E, F, P, and Q of part 
250 to address concerns raised in the Deepwater Horizon investigations. 
Finally, the proposed rule would incorporate API Standard 53 to ensure 
better BOP performance and operability and more robust regulatory 
oversight.
2. Description and Estimated Number of Small Entities Regulated
    Small entities, as defined by the RFA, consist of small businesses, 
small organizations, and small governmental jurisdictions. We have not 
identified any small organizations or small government jurisdictions 
that the rule will impact, so this analysis focuses on impacts to small 
businesses (hereafter referred to as ``small entities''). A small 
entity is one that is independently owned and operated and which is not 
dominant in its field of operation.\18\ The definition of small 
business varies from industry to industry in order to properly reflect 
industry size differences.
---------------------------------------------------------------------------

    \18\ See 5 U.S.C. 601.

---------------------------------------------------------------------------

[[Page 21544]]

    The proposed rule would affect operators and holders of Federal oil 
and gas leases, as well as right-of-way holders, in the OCS. This 
includes about 130 businesses with active operations. 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 500 employees. Based on these criteria, approximately 90 (69 
percent) of the businesses operating on the OCS are considered small 
and the rest are considered large businesses. The 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 in a 
given industry. Therefore, BSEE expects that the proposed rule would 
affect a substantial number of small entities.
    The BSEE is using the estimated 130 businesses based on activity at 
the time this economic analysis was developed. The 130 businesses 
represent the best assessment of the total businesses operating in this 
arena at the time the economic analysis was developed. The BSEE 
recognizes that this number is a dynamic number and can fluctuate; 
however, BSEE determined that this number of businesses was appropriate 
for this rulemaking. The BSEE is requesting comments on the use of the 
active business numbers, and other ways to quantify the changing number 
of businesses.
3. Description and Estimate of Compliance Requirements
    The BSEE has estimated the incremental costs for small operators, 
lease holders, and right-of-way holders in the offshore oil and natural 
gas production industry. Costs already incurred as a result of current 
industry practice in accordance with existing regulations, industry 
permits, 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.\19\ As described in section 5 below, BSEE considered 
three alternatives. Alternative 2 results in a time-savings benefit to 
industry but no additional costs to industry, and thus the costs 
presented below are the same for Alternatives 1 and 2. We have 
estimated the costs of the following provisions of the rule:

    \19\ API 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 contractors and 
operators.
---------------------------------------------------------------------------

--Additional information in the description of well drilling design 
criteria;
--Additional information in the drilling prognosis;
--Prohibition of a liner as conductor casing;
--Additional capping stack testing requirements;
--Additional information in the APM for installed packers;
--Additional information in the APM for pulled and reinstalled packers;
--Rig movement reporting;
--Fitness requirements for MODUs and lift boats;
--Foundation requirements for MODUs and lift boats;
--Monitoring of well operations with a subsea BOP;
--Additional documentation and verification requirements for BOP 
systems and system components;
--Additional information in the APD, APM, or other submittal for BOP 
systems and system components;
--Submission by the operator of a Mechanical Integrity Assessment 
Report completed by a BSEE-approved verification organization;
--New surface BOP system requirements;
--New subsea BOP system requirements;
--New surface accumulator system requirements;
--Chart recorders;
--Notification and procedure requirements for testing of surface BOP 
systems;
--Alternating BOP control station function testing;
--ROV intervention function testing;
--Autoshear, deadman, and EDS function testing on subsea BOPs;
--Approval for well-control equipment not covered in Subpart G;
--Breakdown and inspection of BOP system and components;
--Additional recordkeeping for real-time monitoring; and
--Industry familiarization with the new rule.

    These requirements and their associated costs to the OCS industry 
and government are presented in the sections below.\20\
---------------------------------------------------------------------------

    \20\ Sums presented in the sections below may not equal the sums 
of the costs identified in this section because of rounding.
---------------------------------------------------------------------------

    (a) Additional information in the description of well drilling 
design criteria.
    Section 250.413(g) of the proposed rule would require information 
on the ECD to be included in the description of the well drilling 
design criteria. The ECD is an important parameter in avoiding 
fracturing the formation or compromising the casing shoe integrity, 
which could lead to erratic pressures and uncontrolled flows (e.g., 
formation kicks) emanating from a well reservoir during drilling. This 
information is necessary to better review the well drilling design and 
drilling program. The requirement to include information on the ECD in 
the well drilling design criteria would result in an average annual 
labor cost to industry of $218 per entity.\21\
---------------------------------------------------------------------------

    \21\ We assumed that industry staff (mid-level engineer) would 
spend one hour per well 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. To be conservative, however, we assumed that this 
requirement would result in a new cost for all wells drilled per 
year (320). We multiplied the number of industry staff hours per 
well by the average hourly compensation rate for a mid-level 
industry engineer ($88.38) and by the average number of wells 
drilled per year to obtain an average annual labor cost to industry 
of $28,282 (1 x $88.38 x 320). We then divided the average annual 
labor cost by the number of entities (130) to obtain an average 
annual labor cost per entity of $218 ($28,282 / 130).
---------------------------------------------------------------------------

    (b) Additional information in the drilling prognosis.
    Section 250.414 of the proposed rule would require the OCS industry 
to provide additional information in the drilling prognosis. New 
paragraph (j) would require 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. The requirement to include 
additional information in the drilling prognosis (submitted as part of 
the APD) would result in an average annual labor cost to industry of 
$54 per entity.\22\
---------------------------------------------------------------------------

    \22\ We assumed that industry staff (a mid-level engineer) would 
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 ($88.38) and the average number of wells 
drilled per year (320) to obtain the average annual labor cost to 
industry of $7,070 (0.25 x $88.38 x 320). We then divided the 
average annual labor cost by the number of entities (130) to obtain 
an average annual labor cost per entity of $54 ($7,070 / 130).
---------------------------------------------------------------------------

    (c) Prohibition of a liner as conductor casing.
    Section 250.421(f) would be revised to no longer allow a liner to 
be installed as conductor casing. This would ensure that the drive pipe 
would not be exposed to wellbore pressures during drilling in 
subsequent hole sections.

[[Page 21545]]

This provision would result in an average annual equipment and labor 
cost to industry of $6,115 per entity.\23\
---------------------------------------------------------------------------

    \23\ We estimated that approximately one percent of drilled 
wells currently have a liner as conductor casing (approximately one 
percent of 320 wells, or three wells), based on input provided in 
submittals to BSEE. To calculate the average annual equipment cost, 
we assumed that the average cost of the casing joints and wellhead 
per well would be $65,000. We multiplied the equipment cost per well 
by the number of affected wells to yield an average equipment cost 
of $195,000 ($65,000 x 3). We assumed that industry staff (rig crew) 
would spend one day to install the new equipment on a well. We then 
multiplied the number of industry staff days per well by the average 
labor cost for a rig crew per day ($200,000) and by the number of 
affected wells to obtain an estimated average annual labor cost to 
industry of $600,000 ($200,000 x 3) for this requirement. Summing 
the equipment and labor costs yields a total average annual cost to 
industry of $795,000 for this requirement. We divided the average 
annual equipment and labor cost by the number of entities (130) to 
obtain an average annual equipment and labor cost per entity of 
$6,115 ($795,000 / 130).
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    (d) Additional capping stack testing requirements.
    Proposed Sec.  250.462 would address source control and containment 
requirements. New paragraph (e)(1) would detail requirements for the 
testing of capping stacks. New requirements include the function 
testing of all critical components on a quarterly basis and the 
pressure testing of pressure holding critical components on a bi-annual 
basis. These new requirements would help ensure that operators are able 
to contain a subsea blowout. These new testing requirements would 
result in an average annual equipment and service cost to industry of 
$615 per entity.\24\
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    \24\ We assumed that the quarterly equipment and service costs 
of testing for capping stacks would be $5,000 per test. 
Additionally, we assumed that 4 capping stacks would be tested 
quarterly (or a total of 16 annual tests performed). We multiplied 
the costs per test by the number of annual tests in order to 
determine a total annual equipment and service cost to industry of 
$80,000 (16 x $5,000). We divided the annual equipment and service 
cost to industry by the number of entities (130) to obtain an 
average annual equipment and service cost per entity of $615 
($80,000 / 130).
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    (e) Additional information in the APM for installed packers.
    Proposed paragraphs (e) and (f) in Sec.  250.518 would 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 
requirements would codify existing BSEE policy to ensure consistent 
permitting. It is expected that operators already comply with the 
design specifications included in this section because this is the only 
established industry standard. Thus, the depth setting calculation is 
the only requirement that would impose a new cost beyond the current 
baseline. The required calculations would be submitted for every well 
that is completed where tubing is installed. The requirement to include 
additional information in the APM would result in an average annual 
labor cost to industry of $44 per entity.\25\
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    \25\ We assumed that industry staff (a mid-level engineer) would 
spend 0.25 hours to include the additional information in the APM 
for a well. We assumed that APMs would be submitted for an average 
of 260 wells with installed packers per year. We multiplied the 
number of industry staff hours per well by the average hourly 
compensation rate for a mid-level industry engineer ($88.38) and by 
the estimated number of wells with installed packers for which an 
APM would be submitted per year to estimate an average annual labor 
cost to industry of $5,745 (0.25 x $88.38 x 260). We divided the 
average annual labor cost by the number of entities (130) to obtain 
an average annual labor cost per entity of $44 ($5,745 / 130).
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    (f) Additional information in the APM for pulled and reinstalled 
packers.
    In Sec.  250.619, new paragraphs (e) and (f) would clarify 
requirements for pulled and reinstalled packers and bridge plugs and 
would require additional descriptions and calculations in the APM 
regarding production packer setting depth. These new requirements would 
codify existing BSEE policy to ensure consistent permitting. It is 
expected that operators already comply with the design specifications 
included in this section because this is the only established industry 
standard. The depth setting calculation is the only requirement that 
would impose a new cost beyond the current baseline. The required 
calculations would 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 would result in an average annual 
labor cost increase to industry of $172 per entity.\26\
---------------------------------------------------------------------------

    \26\ We assumed that industry staff (a mid-level engineer) would 
spend 0.25 hours to include the additional information in the APM 
for a well. We also assumed that APMs would be submitted for an 
average of 1,010 wells with pulled and reinstalled packers per year. 
We multiplied the number of industry staff hours per well by the 
average hourly compensation rate for a mid-level industry engineer 
($88.38) and the estimated number of wells with pulled and 
reinstalled packers for which an APM would be submitted per year to 
obtain an average annual labor cost to industry of $22,316 (0.25 x 
$88.38 x 1,010). We divided the average annual labor cost by the 
number of entities (130) to obtain an average annual labor cost per 
entity of $172 ($22,316 / 130).
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    (g) Rig movement reporting.
    Proposed Sec.  250.712 would list the requirements for reporting 
movement of rig units to the BSEE District Manager. Paragraph (a) would 
extend the rig movement reporting requirements to all rig units 
conducting operations covered under this subpart, including MODUs, 
platform rigs, snubbing units, wire-line units used for non-routine 
operations, and coiled tubing units. Paragraphs (c) and (e) are new and 
would require notification if a MODU or platform rig is to be warm or 
cold stacked or if a drilling rig would enter or leave the OCS. 
Paragraph (f) would be revised to clarify that, if the anticipated date 
for initially moving on or off location were to change by more than 24 
hours, an updated Rig Movement Notification Report would be required.
    Currently, rig movement reports are only required for drilling 
operations, but the proposed rule would require operators to submit rig 
movement reports for other operations as well, including cases when 
rigs are stacked or would enter or leave the OCS. These changes would 
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 would result in an 
average annual labor cost to industry of $19 per entity.\27\
---------------------------------------------------------------------------

    \27\ We assumed that industry staff (administrative) would spend 
five minutes (0.08 hours) to submit a movement report and that 
industry would submit an average of 1,000 movement reports per year. 
We multiplied the number of industry staff hours per report by the 
average hourly compensation rate for an administrative staff 
($29.82) and the average number of reports per year to obtain an 
average annual labor cost to industry of $2,485 (0.0833 x $29.82 x 
1,000). We divided the average annual labor cost by the number of 
entities (130) to obtain an average annual labor cost per entity of 
$19 ($2,485 / 130).
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    (h) Fitness requirements for MODUs and lift boats.
    Proposed Sec.  250.713(a) would add a requirement that operators 
provide fitness information for a MODU or lift boat for workovers, 
completions, and decommissioning. Operators must provide information 
and data to demonstrate the drilling unit's capability to perform at 
the proposed drilling location. This information must include the most 
extreme environmental and operational conditions that the unit 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 the APD is 
submitted, the BSEE District Manager may approve the APD, but would 
require operators to collect and report this information during 
operations. Under this circumstance, the District Manager would have 
the right to revoke the approval of the APD, if information collected 
during operations shows that the drilling unit is not capable of 
performing at the proposed location. This requirement would result

[[Page 21546]]

in an average annual labor cost to industry of $340 per entity.\28\
---------------------------------------------------------------------------

    \28\ We assumed that industry staff (a mid-level engineer) would 
spend 0.5 hours per APM to provide the additional information and 
that an average of 1,000 APMs would be affected per year. We 
multiplied the number of industry staff hours per APM by the average 
hourly compensation rate for a mid-level industry engineer ($88.38) 
and by the estimated number of APMs affected per year to obtain an 
average annual labor cost to industry of $44,190 (0.5 x $88.38 x 
1,000). We divided the average annual labor cost by the number of 
entities (130) to obtain an average annual labor cost per entity of 
$340 ($44,190 / 130).
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    (i) Foundation requirements for MODUs and lift boats.
    Proposed Sec.  250.713(b) would introduce a requirement for 
foundation requirements for workovers, completions, and 
decommissioning. Operators must provide information to show that site-
specific soil and oceanographic conditions would be capable of 
supporting the proposed rig unit. 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 
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 would be capable of 
supporting the rig unit or equipment installed on a subsea wellhead. 
For moored rigs, operators must submit a plan of the rigs anchor 
pattern approved in the EP, DPP, or DOCD in the APD or APM. This 
requirement would result in an average annual labor cost to industry of 
$340 per entity.\29\
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    \29\ We assumed that industry staff (a mid-level engineer) would 
spend 0.5 hours per APM to provide the additional information and 
that an average of 1,000 APMs would be affected per year. We 
multiplied the number of industry staff hours per APM by the average 
hourly compensation rate for a mid-level industry engineer ($88.38) 
and by the estimated number of APMs affected per year to obtain an 
average annual labor cost to industry of $44,190 (0.5 x $88.38 x 
1,000). We divided the average annual labor cost by the number of 
entities (130) to obtain an average annual labor cost per entity of 
$340 ($44,190 / 130).
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    (j) Real-time monitoring of well operations.
    Proposed Sec.  250.724 is a new section that lists requirements 
for:

--Monitoring well operations on rigs that have a subsea BOP, surface 
BOP on a floating facility, and rigs operating in HPHT reservoirs; and
--Storing data at a designated onshore location, as listed in the APD 
or APM.
    In order to comply with this section, the OCS industry would incur 
annual equipment and labor costs associated with gathering, 
transmitting, and storing data. The costs associated with these new 
data collection and storage requirements would include an average 
annual equipment and labor cost of $311,538 per entity. The BSEE 
requests feedback related to the costs of compliance with monitoring of 
well operations with a subsea BOP.\30\

    \30\ We assumed that the average costs per day and the average 
operational days per year would be the same for rigs with subsea 
BOPs and rigs operating in HPHT reservoirs. Additionally, we assumed 
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 would be $5,000, including equipment 
and labor. We estimated that half of the rigs with subsea BOPs 
already conduct this monitoring. Thus, only half of rigs with subsea 
BOPs (20 rigs) would incur a new cost to comply with these 
requirements. Similarly, we assumed that 10 of the rigs operating in 
HPHT reservoirs would incur a new cost to comply with these 
requirements. We multiplied the time that the rig is operational per 
year by the average cost per day to perform monitoring and by the 
number of affected rigs to obtain an average annual equipment and 
labor cost to industry of $40.5 million (270 x $5,000 x 30). We 
divided the average annual equipment and labor cost by the number of 
entities (130) to obtain average an average annual equipment and 
labor cost per entity of $311,538 ($40,500,000 / 130).
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    (k) Additional documentation and verification requirements for BOP 
systems and system components.
    Proposed Sec.  250.730 would list general requirements for BOP 
systems and system components and additions to the section would 
describe new documentation and verification requirements. Proposed 
Sec.  250.731(c) would require verification by a BSEE-approved 
verification organization of specified aspects of equipment design, 
equipment tests, shear tests, and pressure integrity tests; and all 
certification documentation must be made available to BSEE. Proposed 
Sec.  250.732(c) would require a comprehensive review by a BSEE-
approved verification organization of BOP and related equipment being 
proposed for use in HPHT service. Proposed Sec.  250.730(d) would 
require that quality management systems for BOP stacks be certified by 
an entity that meets the requirements of ISO 17011.
    Additionally, operators may submit a request for approval of 
equipment manufactured under quality assurance programs other than API 
Spec. Q1. The BSEE may approve such a request, provided the operator 
submits relevant information about the alternative program. Costs 
associated with these new documentation and certification requirements 
would include an average annual equipment and labor cost of $13,706 per 
entity. The BSEE requests feedback related to the costs of compliance 
with these documentation and certification requirements for BOP systems 
and system components.\31\
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    \31\ For proposed Sec.  250.731(c), we assumed that the one-time 
equipment and service costs to industry would be $40,000. We 
estimated that 320 wells would incur a new cost to comply with these 
requirements. We multiplied the one-time cost of equipment and 
service by the number of affected wells to obtain the total one-time 
equipment and service cost to industry of $12,800,000 ($40,000 x 
320), resulting in an average annual cost of $1,280,000 to industry. 
For Sec.  250.732(c), we assumed that the annual costs would be 
$50,000, including equipment and service. We estimated that 10 wells 
would 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 ($50,000 x 10). For Sec.  250.730(d), 
we assumed that a mid-level industry engineer would spend 2 hours to 
submit a request. We multiplied the compensation rate for a mid-
level industry engineer ($88.38) by the number of hours to complete 
the submission and then multiplied this annual cost by the total 
number of wells (10) to determine the annual cost to industry of 
$1,768 (2 $88.38 x 10). The average annual cost to industry 
associated with these requirements is $1,781,768 ($1,280,000 + 
$500,000 + $1,768). We divided this average annual equipment and 
labor cost by the number of entities (130) to obtain average an 
average annual equipment and labor cost per entity of $13,706 
($1,781,768 / 130).
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    (l) Additional information in the APD, APM, or other submittals for 
BOP systems and system components.
    Proposed Sec.  250.731 would list the descriptions of BOP systems 
and system components that must be included in the applicable APD, APM, 
or other submittal for a well. Paragraph (a) would require 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. Paragraph (b) would add schematic drawing 
requirements, including labeling for the control system alarms and set 
points, control stations, and riser cross section. New paragraph (e) 
would require a listing of the functions with sequences and timing of 
autoshear, deadman, and EDS for subsea BOPs. For subsea BOPs, surface 
BOPs on a floating facility, and BOPs operating under HPHT conditions, 
new paragraph (f) would require submission of a certification that a 
Mechanical Integrity Assessment Report has been submitted within the 
past 12 months. New paragraph (c) would include a change in required 
certifications. The paragraph would require submission of 
certifications from a BSEE approved verification organization (rather 
than a ``qualified third-party'') that:

--Test data would demonstrate that the shear ram(s) would shear the 
drill

[[Page 21547]]

pipe at the water depth (per proposed Sec.  250.732(b)),
--The BOP would be designed, tested, and maintained to perform at the 
most extreme anticipated conditions; and
--The accumulator systems would have sufficient fluid to function the 
BOP system without assistance from the charging system.

    These proposed requirements would be necessary to enhance BSEE's 
review of the BOP system and its emergency systems, which were the 
topic of many of the recommendations of the Deepwater Horizon 
investigation reports. These requirements would be necessary to help 
BSEE verify that the accumulator system would have sufficient fluid to 
function the BOP system without assistance from the charging system. 
The proposed requirements to provide additional documentation about the 
BOP system and system components in the APD, APM, or other submittal 
would result in an average annual labor cost to industry of $218 per 
entity.\32\ The BSEE was unable to locate any applicable data or 
comparative cost estimates, and therefore was unable to determine a 
definitive cost estimate for the annual costs to industry associated 
with the change in the required independent third-party verifications 
referenced in new paragraph (a). The BSEE requests feedback from the 
public and industry on costs associated with the change in the 
verification requirements.
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    \32\ We assumed that industry staff (a mid-level engineer) would 
spend one hour to include additional information in the APD, APM, or 
other submittal 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 ($88.38) and by the average number of 
wells drilled per year (320) to obtain an average annual labor cost 
to industry of $28,282 (1 x $88.38 x 320). We divided the average 
annual labor cost by the number of entities (130) to obtain an 
average annual labor cost per entity of $218 ($28,282 / 130).
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    (m) Submission of a Mechanical Integrity Assessment Report by a 
BSEE-approved verification organization.
    Proposed Sec.  250.732(d) would include new requirements on the 
submission of a Mechanical Integrity Assessment Report on the BOP stack 
and systems. New paragraph (d) would outline the requirements for this 
report, which must be completed by a BSEE-approved verification 
organization and submitted by the operator for operations that would 
require the use of a subsea BOP, a surface BOP on a floating facility, 
or a BOP that is being used in HPHT operations. Proposed new Sec.  
250.731(f) would require certification in the applicable permit stating 
that this report has been submitted within the past 12 months. The 
third-party reporting would enhance the BSEE review and permitting 
process and would ensure that BSEE is aware of repairs or other changes 
to the operating BOPs. These reporting requirements would result in new 
costs to industry consisting of capital and labor costs for creating 
reports and submitting them to BSEE. The analysis estimated an average 
annual cost to industry of $37,032 per entity.\33\
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    \33\ For capital costs, we assumed an annual cost of $15,000 for 
each well which results in an annual capital cost of $4.8 million 
($15,000 x 320). For labor costs, we assumed that industry staff (a 
mid-level engineer) would spend a half hour to prepare a report for 
each well. We multiplied the number of industry staff hours per well 
by the average hourly compensation rate for a mid-level industry 
engineer ($88.38) and by the average number of wells drilled per 
year (320) to obtain an average annual labor cost to industry of 
$14,141 (0.5 x $88.38 x 320). The average annual labor and capital 
cost to industry. associated with these requirements is $4,814,141 
($4,800,000 + $14,141). We divided the average annual labor and 
capital cost to industry by the number of entities (130) to obtain 
an average annual labor and capital cost per entity of $37,032 
($4,814,141 / 130).
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    (n) New surface BOP requirements.
    Proposed Sec.  250.733 would include new requirements for surface 
BOP stacks. New paragraph (e) would require that hydraulically operated 
locks are installed with surface BOPs. The BSEE was unable to locate 
any applicable data or comparative cost estimates and therefore was 
unable to determine a definitive cost estimate for the labor and 
equipment costs to industry associated with the installation of 
hydraulically operated locks. The BSEE requests feedback related to the 
costs of compliance with this new surface BOP stack requirement.
    (o) New subsea BOP system requirements.
    Proposed Sec.  250.734 would include new requirements for subsea 
BOP systems, based on recommendations from the Deepwater Horizon 
investigations. Paragraph (a) would require that BOPs be equipped with 
two shear rams and would outline the requirements for the shear rams. 
These additions would assist in emergency well-control planning. The 
BSEE recognizes that the equipment and labor costs associated with 
these new subsea BOP system requirements would be case-specific. For 
example, the costs would depend on the age of the rig and BOP system, 
the BOP system type, and the size of the rig, among other factors.
    The costs associated with the shear ram requirements in paragraph 
(a) would include an average one-time compliance cost to industry of 
$384,615 per entity.\34\ The BSEE welcomes feedback related to the 
costs of compliance with these new technology requirements.
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    \34\ API Standard 53 includes the requirements under new 
paragraph (a) for all rigs with the exception of moored rigs. We 
estimated that 5 moored rigs would be affected and that the one-time 
capital compliance cost associated with these shear ram requirements 
would 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 ($10,000,000 x 5). We divided the average one-time 
equipment and labor cost by the number of entities (130) to obtain 
an average one-time cost per entity of $384,615 ($50,000,000 / 130).
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    (p) New surface accumulator system requirements.
    Proposed Sec.  250.735(a) would list new requirements for the 
surface accumulator system of a BOP. The surface accumulator system 
must operate all BOP functions against MASP with 200 psi above pre-
charge without use of the charging system. This revision would ensure 
that the BOP system would be capable of operating all critical 
functions. The requirement that the surface accumulator system would 
operate all functions for all BOP systems would result in a one-time 
equipment and labor cost to industry of $21,713 per entity.\35\
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    \35\ We assumed that the average cost of the additional 
equipment needed to meet the requirements would be $25,000 per rig. 
It is unknown how many rigs already comply; thus, we made a 
conservative assumption that all rigs would be affected (90 rigs). 
We multiplied the equipment cost per rig by the number of affected 
rigs to obtain an estimated one-time equipment cost of $2.25 million 
($25,000 x 90). For the one-time labor cost to industry, it was 
estimated that one to three days of industry time would be required 
per rig to install the new equipment. To be conservative, we assumed 
that industry staff (a mid-level engineer) would spend 72 hours to 
install the new equipment on a rig. We multiplied the number of 
industry staff hours per rig by the average hourly compensation rate 
for a mid-level industry engineer ($88.38) and by the number of 
affected rigs to obtain an estimated one-time labor cost to industry 
of $572,702 (72 x $88.38 x 90). Summing the equipment and labor 
costs resulted in a total one-time cost to industry of $2,822,708. 
We divided the one-time equipment and labor cost by the number of 
entities (130) to obtain a one-time equipment and labor cost per 
entity of $21,713 ($2,822,708 / 130).
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    (q) Chart recorders.
    Proposed Sec.  250.737(c) would address BOP testing and introduce a 
requirement that each test must hold the required pressure for five 
minutes while using a four-hour chart. This would allow the chart to 
detect a leak during the test. This testing requirement would result in 
a one-time equipment and labor cost to industry of $1,388 per 
entity.\36\
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    \36\ We assumed that each rig would require a chart recorder for 
an average cost of $2,000 per rig. We multiplied the average 
equipment cost per rig by the total number of rigs (90) to obtain an 
estimated one-time equipment cost to industry of $180,000 ($2,000 x 
90). We assumed that industry staff (rig crew) would spend five 
minutes (0.08 hours) per rig to install the equipment. We multiplied 
the number of industry staff hours per rig by the average hourly 
compensation rate for a rig crew staff ($56.80) and by the total 
number of rigs to obtain an estimated one-time labor cost to 
industry of $426 (0.0833 x $56.80 x 90). Summing the equipment and 
labor costs resulted in a total one-time cost to industry of 
$180,426. We divided the one-time equipment and labor cost by the 
number of entities (130) to obtain a one-time equipment and labor 
cost per entity of $1,388 ($180,426 / 130).

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[[Page 21548]]

    (r) Notification and procedure requirements for testing of surface 
BOP systems.
    Proposed Sec.  250.737(d)(2) would expand notification and 
procedure requirements regarding the use of water to test a surface BOP 
system. This notification and procedure requirement would result in an 
average annual labor cost to industry of $41 per entity.\37\
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    \37\ We assumed that a mid-level industry engineer would spend 1 
additional hour on a submittal as a result of these expanded 
requirements. We multiplied the compensation rate for a mid-level 
industry engineer ($88.38) by the number of hours to complete the 
submission and then multiplied this annual cost by the total number 
of submittals (60) to determine the annual cost to industry of 
$5,303 (1 x $88.38 x 60). We divided the average annual labor cost 
by the number of entities (130) to obtain an average annual labor 
cost per entity of $41 ($5,303 / 130).
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    (s) Alternating BOP control station function testing.
    Proposed Sec.  250.737(d)(5) would expand the requirements for 
function testing BOP control stations. It would require that the 
operator designate the BOP control stations as primary and secondary 
and alternate function testing of each station weekly. This testing 
requirement would result in an average operations cost to industry of 
$192,308 per entity.\38\ The BSEE requests feedback related to the 
costs of compliance with alternating BOP control station function 
testing.
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    \38\ We assumed that testing would require 0.5 days per rig per 
year (two hours every two weeks for three months). Because subsea 
and surface BOPs 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 average daily rig operating cost 
for subsea BOP rigs ($1 million) and by the number of subsea BOP 
rigs (40) for an average annual cost of $20 million for subsea BOP 
rigs (0.5 x $1 million x 40). For surface BOP rigs, we multiplied 
the time required to conduct the testing per rig by the average 
daily rig operating cost for surface BOP rigs ($200,000) and by the 
number of surface BOP rigs (50) for an average annual cost of $5 
million for surface BOP rigs (0.5 x $200,000 x 50). Summing the 
average annual costs for subsea BOP rigs and surface BOP rigs 
resulted in an average annual operations cost to industry associated 
with this provision of $25 million. We divided the average annual 
operations cost to industry by the number of entities (130) to 
obtain an average annual operations cost per entity of $192,308 
($25,000,000 / 130).
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    (t) ROV intervention function testing.
    Proposed Sec.  250.737(d)(12) would include requirements for 
testing ROV intervention functions to include testing and verifying the 
closure of all ROV intervention functions on a subsea BOP. The operator 
would have to test and verify closure of the selected ram. This testing 
requirement would result in an average annual operations cost to 
industry of $3,205 per entity.\39\
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    \39\ We assumed that it would take five minutes per well to 
conduct the testing and that 120 wells would be affected (40 subsea 
BOP rigs with three wells per rig). We multiplied the time diverted 
for testing in a day 0.003472 (5 min / 60 min / 24 hours) by the 
daily operating cost per rig ($1,000,000) and by the estimated 
number of wells affected per year to obtain an average annual 
operations cost to industry of $416,667 (0.03 x 120 x $1,000,000). 
We divided the average annual operations cost by the number of 
entities (130) to obtain an average annual operations cost per 
entity of $3,205 ($416,667 / 130).
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    (u) Autoshear, deadman, and EDS system function testing on subsea 
BOPs.
    Proposed Sec.  250.737(d)(13) would expand the requirements for 
function testing of autoshear, deadman, and EDSs on subsea BOPs. It 
would require that the test procedures submitted for BSEE District 
Manager approval include a schematic of the circuitry of the system, 
the approved schematics of the BOP control system, and a description of 
how the ROV would be used during the operation. It would also outline 
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 (per proposed Sec.  
250.737(d)(13)). It would require that the blind-shear rams be tested 
to verify closure. The operator must document the plan to verify 
closure of the casing shear ram, if installed, as well as all test 
results. These documentation and testing requirements would result in 
an average one-time equipment cost to industry of $769 per entity and 
an average annual operations cost of $38,462 per entity.\40\
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    \40\ We assumed that the average cost of the sensing device 
would 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 ($2,500 x 40). We divided the 
equipment cost by the number of entities (130) to obtain a one-time 
equipment cost per entity of $769 ($100,000 / 130). We assumed that 
it would take one hour per well to perform the testing and 
documentation tasks required by this provision, and that each subsea 
BOP rig would be affected (40 subsea rigs). We multiplied the time 
diverted for testing in a day 0.125 (1 hour / 24 hours) 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 (0.125 x 40 x $1,000,000). We divided the 
average annual operations cost by the number of entities (130) to 
obtain an average annual operations cost per entity of $38,462 
($5,000,000 / 130).
---------------------------------------------------------------------------

    (v) Approval for well-control equipment not covered in Subpart G.
    Proposed Sec.  250.738 would describe the required actions for 
specified situations involving BOP equipment or systems. Paragraphs 
(b), (i), and (o) would include requirements for reports from 
verification organizations. Reports previously required to be prepared 
by a ``qualified third-party'' under these sections would be required 
to be prepared by a ``BSEE-approved verification organization.'' 
Proposed Sec.  250.738(m) would include a similar change and introduce 
a requirement that an operator request approval from the BSEE District 
Manager to use well-control equipment not covered in Subpart G. The 
operator must submit a report from a BSEE-approved verification 
organization, as well as any other information required by the District 
Manager. This approval request requirement would result in an average 
annual labor cost to industry of approximately $1 per entity.\41\ The 
BSEE was unable to locate any applicable data or comparative cost 
estimates and therefore was unable to determine a definitive cost 
estimate for the annual costs to industry associated with the third-
party verification. The BSEE welcomes feedback from the public or 
industry on costs associated with the third-party verification 
requirements.
---------------------------------------------------------------------------

    \41\ We assumed that industry staff (a mid-level engineer) would 
spend 0.5 hours to submit an equipment approval request and report. 
We also assumed that industry would submit a request and report for 
an average of two deepwater rigs per year. We multiplied the number 
of industry staff hours per submission by the average hourly 
compensation rate for a mid-level industry engineer ($88.38) and the 
average number of submissions per year to obtain an average annual 
labor cost to industry of $88 (0.5 x $88.38 x 2). We divided the 
average annual labor cost by the number of entities (130) to obtain 
an average annual labor cost per entity of $1 ($88 / 130).
---------------------------------------------------------------------------

    (w) Breakdown and inspection of the BOP system and components.
    Proposed Sec.  250.739(b) would introduce a requirement for a 
complete breakdown and inspection of the BOP and every associated 
component every 5 years. During this complete breakdown and inspection, 
a BSEE-approved verification organization must document the inspection 
and any problems encountered. This BSEE-approved verification 
organization's report must be available to BSEE upon request. This 
additional requirement would be necessary to ensure that the components 
on the BOP stack are 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 
would result in an average cost to industry to obtain third-party 
reports of $165,385 per entity during the year of inspection, which 
would occur

[[Page 21549]]

once every 5 years or twice during the 10-year analysis period.\42\ We 
assumed that costs would be incurred in year 1 and year 6 of the 10-
year analysis period.
---------------------------------------------------------------------------

    \42\ For subsea BOP rigs, we assumed that equipment and labor 
cost would be $350,000 per rig. We multiplied the total number of 
subsea BOP rigs (40) by the equipment and labor cost to obtain an 
inspection-year cost of $14 million ($350,000 x 40), which occurs 
every 5 years for subsea BOP rigs. For surface BOP rigs, we assumed 
that equipment and labor cost would be $150,000 per rig. We 
multiplied the total number of surface BOP rigs (50) by the 
equipment and labor cost to obtain an inspection-year cost of $7.5 
million ($150,000 x 50), which occurs every 5 years for surface BOP 
rigs. The sum of subsea and surface BOP costs are $21.5 million 
during the year of inspection. We divided this total cost by the 
number of entities (130) to obtain an average cost of inspection per 
entity of $165,385 ($21,500,000 / 130).
---------------------------------------------------------------------------

    (x) Additional recordkeeping for real-time monitoring.
    Proposed Sec. Sec.  250.740(a) and Sec.  250.741(b) would introduce 
requirements for additional recordkeeping of real-time monitoring data 
for well operations. These additional records would require an average 
additional annual labor cost to industry of $14 per entity.\43\
---------------------------------------------------------------------------

    \43\ We assumed that industry staff (administrative staff) would 
spend 0.5 hours to submit a report. We multiplied the number of 
industry staff hours per submission by the average hourly 
compensation rate for administrative staff ($29.82) and then 
multiplied this annual cost by the number of affected wells (120, 
based on the assumption of three wells per subsea BOP rig) to obtain 
an average annual labor cost to industry of $1,789 (0.5 x $29.82 x 
120). We divided the average annual labor cost to industry by the 
number of entities (130) to obtain an average annual labor cost per 
entity of $14 ($1,789 / 130).
---------------------------------------------------------------------------

    (y) Industry familiarization with new regulations.
    When the new regulation takes effect, operators would need to read 
and interpret the rule. Through this review, operators would 
familiarize themselves with the structure of the new rule and identify 
any new provisions relevant to their operations. Operators would 
evaluate whether any new action must be taken to achieve compliance 
with the rule. Reviewing the new regulations would require staff time, 
representing an average one-time labor cost on industry of $216 per 
entity.\44\
---------------------------------------------------------------------------

    \44\ We assumed that industry staff (a professional engineer, 
supervisory) would spend two hours to review the new regulation. The 
average hourly wage rate for a professional engineer (supervisory) 
is $76.00, based on BSEE's Supporting Statement A (BSEE Production 
Safety Systems). We multiplied this wage rate by the private sector 
loaded wage factor of 1.42 to account for employee benefits, 
resulting in a loaded average hourly compensation rate of $107.92. 
We assumed that an industry staff would 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 $28,059 (2 x $107.92 x 130). We divided the one-time 
labor cost by the number of entities (130) to obtain an average one-
time labor cost of $216 ($28,059 / 130).
---------------------------------------------------------------------------

    (z) Total Cost Burden for Small Entities.
    The BSEE's calculations indicate that the total cost burden of this 
proposed rule would be $6,783,880 per affected small entity over 10 
years, which yields an average annual cost of $678,388, as presented in 
Exhibit 4. Four provisions comprise approximately 85 percent of the 
cost to small entities:

--Monitoring of well operations with a subsea BOP;
--Alternating BOP control station function testing;
--Autoshear, deadman, and EDS system function testing on subsea BOPs; 
and
--New subsea BOP system requirements.

    Exhibit 5 displays estimates of costs to small entities as a 
percentage of revenues.\45\ In 8 of the 10 years in the analysis 
period, the proposed rule represents a cost of $595,628 per entity. In 
the first year, costs would be higher at $1,268,175 per entity as a 
result of the one-time equipment and inspection costs. In year 6, small 
entities would incur the costs from BOP major inspections, which would 
be performed every 5 years.
---------------------------------------------------------------------------

    \45\ The source for the estimated small business revenue is the 
RIA for the BSEE Final Rulemaking ``Increased Safety Measures for 
Energy Development on the Outer Continental Shelf'' (77 FR 50856; 
August 22, 2012). The data in the source document is from the Office 
of Natural Resources Revenue. The RIA can be viewed here: https://www.regulations.gov/#!documentDetail;D=BSEE-2012-0002-0047. The data 
source reports the total 2009 small company revenue to be 
$4,113,000,000. We calculated the average revenue per small business 
by dividing the total small business revenue by the number of small 
businesses subject to the rule ($4,113,000,000/90 operators) to 
obtain an average of $45,700,000 per operator.
---------------------------------------------------------------------------

    The costs of the rule as a proportion of small entity revenue range 
from 1.30 percent in most years to 2.78 percent in the first year. The 
BSEE considers that a rule has a ``significant economic impact'' when 
the total annual cost associated with the rule is equal to or exceeds 1 
percent of annual revenue. Thus, the rule is expected to have a 
significant economic impact on the average participating small 
operators, lease holders, and pipeline right-of-way holders. Thus, BSEE 
concluded that this proposed rule will have a significant economic 
impact on a substantial number of small entities.

                        Exhibit 4--Per Entity Cost of the Proposed Rule by Provision \1\
----------------------------------------------------------------------------------------------------------------
                                                           Total 10 year      Average annual
                                                          cost per entity    cost per entity    Percent of total
                                                           (undiscounted)     (undiscounted)          cost
----------------------------------------------------------------------------------------------------------------
(a) Additional information in the description of well               $2,176               $218               0.03
 drilling design criteria..............................
(b) Additional information in the drilling prognosis...                544                $54               0.01
(c) Prohibition of a liner as conductor casing.........             61,154              6,115               0.90
(d) Additional capping stack testing requirements......              6,154                615               0.09
(e) Additional information in the APM for installed                    442                 44               0.01
 packers...............................................
(f) Additional information in the APM for pulled and                 1,717                172               0.03
 reinstalled packers...................................
(g) Rig movement reporting.............................                191                 19               0.00
(h) and (i) Information on MODUs, including lift boats.              6,799                680               0.10
(j) Real-time monitoring of well operations............          3,115,385            311,538              45.92
(k) Additional documentation and certification                     137,059             13,706               2.02
 requirements for BOP systems and system components....
(l) Additional information in the APD, APM, or other                 2,176                218               0.03
 submittal for BOP systems and system components.......
(m) Submission of a Mechanical Integrity Assessment                370,319             37,032               5.46
 Report by a BSEE-approved verification organization...
(n) New surface BOP requirements.......................           Data not available; requesting comments
(o) New subsea BOP system requirements \2\.............            384,615             38,462               5.67
(p) New surface accumulator system requirements........             21,713              2,171               0.32
(q) Chart recorders....................................              1,388                139               0.02
(r) Use water to test surface BOP system...............                408                 41               0.01

[[Page 21550]]

 
(s)Alternating BOP control station function testing....          1,923,077            192,308              28.35
(t) ROV intervention function testing..................             32,051              3,205               0.47
(u) Autoshear, deadman, and EDS system function testing            385,385             38,538               5.68
 on subsea BOPs........................................
(v) Approval for well-control equipment not covered in                   7                  1               0.00
 Subpart G.............................................
(w) Breakdown and inspection of BOP system and                     330,769             33,077               4.88
 components............................................
(x) Record-keeping for real-time monitoring............                138                 14               0.00
(y) Industry familiarization with the new rule.........                216                 22               0.00
                                                        --------------------------------------------------------
    Total..............................................          6,783,880            678,388             100.00
----------------------------------------------------------------------------------------------------------------
\1\ Totals may not add because of rounding.
\2\ This is a lower-bound estimate of the costs of this provision; BSEE seeks comment on costs that we were
  unable to estimate (see section 4 above for details).


                                  Exhibit 5--Annual Cost and Revenue Per Entity
----------------------------------------------------------------------------------------------------------------
                                                          2016-2019 (each                       2021-2024 (each
                Year                         2015          year the same)          2020          year the same)
----------------------------------------------------------------------------------------------------------------
Annual Industry Cost Stream for            $164,728,509        $77,297,317        $98,797,317        $77,297,317
 Proposed Rule a....................
Total Entities b....................                130                130                130                130
Average Annual Cost per Entity c = a          1,268,175            595,628            761,012            595,628
 / b................................
Average Annual Revenue for Small             45,700,000         45,700,000         45,700,000         45,700,000
 Entities \1\ d.....................
Cost from Proposed Rule as a                      2.78%              1.30%              1.67%              1.30%
 Percentage of Annual Revenue e = c /
  d.................................
----------------------------------------------------------------------------------------------------------------
\1\ The source for this estimate is the RIA for the BSEE Final Rulemaking ``Increased Safety Measures for Energy
  Development on the Outer Continental Shelf'' (77 CFR 50856; August 22, 2012). The data in the source document
  is from the Office of Natural Resource Revenue. The RIA can be viewed here: https://www.regulations.gov/#!documentDetail;D=BSEE-2012-0002-0047. The data source reports the total 2009 small company revenue to be
  $4,113,000,000. We calculated the average revenue per small business by dividing the total small business
  revenue by the number of small businesses subject to the rule ($4,113,000,000/90) to obtain an average of
  $45,700,000 per operator.

4. Identification of All Relevant Federal Rules That May Duplicate, 
Overlap, or Conflict With the Proposed Rule
    The proposed rule does not conflict with any relevant federal rules 
or duplicate or overlap with any Federal rules in any way that would 
unnecessarily add cumulative regulatory burdens on small entities 
without any gain in regulatory benefits. However, BSEE requests 
comments identifying any federal rules that may duplicate, overlap, or 
conflict with the proposed rule.
 5. Description of Significant Alternatives to the Proposed Rule
    BSEE has considered three alternatives:
    BSEE has considered three regulatory alternatives:
    (1) Promulgate the requirements contained within the proposed rule, 
including increasing the BOP testing frequency for workover and 
decommissioning operations from current 7 day to proposed 14 day 
testing frequency. The following chart identifies the BOP testing 
changes related to Alternative 1:

                          BOP Pressure Testing
------------------------------------------------------------------------
                                     Current testing    Proposed testing
             Operation                  frequency          frequency
------------------------------------------------------------------------
Drilling/Completions..............            14 days            14 days
Workover/Decommissioning..........             7 days            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 (e.g., 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; or

                                              BOP Pressure Testing
----------------------------------------------------------------------------------------------------------------
                                                                             Proposed testing
                       Operation                          Current testing       frequency        Alternative 2
                                                             frequency       (Alternative 1)   testing frequency
----------------------------------------------------------------------------------------------------------------
Drilling/Completions...................................            14 days            14 days            21 days
Workover/Decommissioning...............................             7 days            14 days           21 days*
----------------------------------------------------------------------------------------------------------------
* includes change from current 7 days to proposed 14 days


[[Page 21551]]

    (3) Take no regulatory action and continue to rely on existing BOP 
regulations in combination with permit conditions, Deep Water 
Operations Plans (DWOPs), operator prudence, and industry standards.
    Alternative 2 results in a time-savings benefit to industry but no 
additional costs to industry, and thus the costs are the same for 
Alternatives 1 and 2. By taking no regulatory action in 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 event with consequences 
similar to those of the Deepwater Horizon incident.\46\
---------------------------------------------------------------------------

    \46\ See sources listed in n. 6.
---------------------------------------------------------------------------

    Alternative 2 was not selected because BSEE is lacking critical 
data on testing frequency and equipment reliability. This issue may be 
considered in the final rulemaking if BSEE receives sufficient data to 
support Alternative 2.
    The BSEE has elected to move forward with Alternative 1, the 
proposed rule, which would address recommendations provided by 
government, industry, academia, and other stakeholders as well as 
incorporate API Standard 53. In addition to addressing concerns and 
aligning with industry standards, BSEE is functioning in a prudent 
capacity with this proposed rule by advancing several of the more 
critical capabilities beyond current industry standards. The proposed 
rule would also improve efficiency and consistency of the regulations 
and allow for flexibility in future rulemakings.
    The operating risk for small companies to incur safety or 
environmental accidents is not necessarily lower than it is for larger 
companies. Offshore operations are highly technical and can be 
hazardous. Adverse consequences in the event of incidents are similar 
regardless of the operator's size. The proposed rule would reduce risk 
for entities of all sizes. Nonetheless, BSEE is requesting comment on 
the time it would take to comply with the proposed rule and the costs 
of these proposed policies on small entities, with the goal of ensuring 
thorough consideration and discussion at the final rule stage. The BSEE 
specifically requests comments on the burden estimates discussed above 
as well as information on regulatory alternatives that would reduce the 
burden on small entities (e.g., different compliance requirements for 
small entities, alternative testing requirements and periods, and 
exemption from regulatory requirements).

Small Business Regulatory Enforcement Fairness Act

    The proposed rule is a major rule under the Small Business 
Regulatory Enforcement Fairness Act, 5 U.S.C. 801 et seq. This proposed 
rule:
    (1) Would have an annual effect on the economy of $100 million or 
more.
    (2) Would cause a major increase in costs or prices for consumers, 
individual industries, Federal, State, or local government agencies, or 
geographic regions.
    (3) Would not have significant adverse effects on competition, 
employment, investment, productivity, innovation, or the ability of 
U.S.-based enterprises to compete with foreign-based enterprises.
    The requirements would 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 RFA 
discussion.

Unfunded Mandates Reform Act of 1995

    This proposed rule would not impose an unfunded mandate on State, 
local, or tribal governments or the private sector of more than $100 
million per year. The proposed rule would not have a significant or 
unique effect on State, local, or tribal governments or the private 
sector. A statement containing the information required by the Unfunded 
Mandates Reform Act, 2 U.S.C. 1501 et seq., is not required.

Takings Implication Assessment (E.O. 12630)

    Under the criteria in E.O. 12630, this proposed rule does not have 
significant takings implications. The proposed rule is not a 
governmental action capable of interference with constitutionally 
protected property rights. A Takings Implication Assessment is not 
required.

Federalism (E.O. 13132)

    Under the criteria in E.O. 13132, this proposed rule does not have 
federalism implications. This proposed rule would not substantially and 
directly affect the relationship between the Federal and State 
governments. To the extent that State and local governments have a role 
in OCS activities, this proposed rule would not affect that role. A 
federalism assessment is not required.

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)

    Under the criteria in E.O. 13175, we have evaluated this proposed 
rule and determined that it has no substantial direct effects on 
federally recognized Indian tribes. The BSEE is committed to regular 
and meaningful consultation and collaboration with tribes on policy 
decisions that have tribal implications. The BSEE will consult with any 
tribe that requests consultation about this proposed rule.

Paperwork Reduction Act (PRA) of 1995

    This proposed rule contains collections of information that will be 
submitted to OMB for review and approval under the PRA, 44 U.S.C. 3501 
et seq. As part of its continuing effort to reduce paperwork and 
burdens on respondents, BSEE invites the public and other Federal 
agencies to comment on any aspect of the reporting and recordkeeping 
burden. If you wish to comment on the information collection (IC) 
aspects of this proposed rule, you may send your comments directly to 
OMB and send a copy of your comments to the Regulations and Standards 
Branch (see the ADDRESSES section of this proposed rule). Please 
reference 30 CFR part 250, subpart G, Blowout Preventer Systems and 
Well Control, 1014-NEW, in your comments. To see a copy of the 
information collection request submitted to OMB, go to https://www.reginfo.gov (select Information Collection Review, Currently Under 
Review); or you may obtain a copy of the supporting statement for the 
new collection of information by contacting the Bureau's Information 
Collection Clearance Officer at (703) 787-1607.
    The PRA provides that an agency may not conduct or sponsor, and a 
person is not required to respond to, a collection of information 
unless it displays a currently valid OMB control number. The OMB is 
required to make a decision concerning the collection of information 
contained in these proposed regulations 30-60 days after publication of 
this document in the Federal Register. Therefore, a comment to OMB is 
best assured of being fully considered if OMB receives it by May 18, 
2015. This does not affect the deadline for the public to comment to 
BSEE on the proposed regulations.

[[Page 21552]]

    The title of the collection of information for this rule is 30 CFR 
250, Subpart G, Blowout Preventer Systems and Well Control (Proposed 
Rulemaking). The proposed regulations concern BOP system requirements, 
maintaining well control among others, and the information is used in 
BSEE's efforts to regulate oil and gas operations on the OCS to protect 
life and the environment, conserve natural resources, and prevent 
waste.
    Potential respondents comprise Federal OCS oil, gas, and sulphur 
operators and lessees. Responses to this collection of information are 
mandatory, or are required to obtain or retain a benefit; they are also 
submitted on occasion, daily and weekly (during drilling operations), 
monthly, quarterly, biennially, and as a result of situations 
encountered depending upon the requirement. The IC does not include 
questions of a sensitive nature. The BSEE will protect proprietary 
information according to the Freedom of Information Act (5 U.S.C. 552) 
and DOI implementing regulations (43 CFR 2), 30 CFR part 252, OCS Oil 
and Gas Information Program, and 30 CFR 250.197, Data and information 
to be made available to the public or for limited inspection.
    This proposed rule affects Subpart A (1014-0022, expiration 8/31/
2017); Subpart B (1014-0024, expiration 12/31/2015); 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).
    This rule would also codify NTL 2013-G01, Global Positioning 
Systems (GPS) for Mobile Offshore Drilling Units (MODUs) (1014-0013, 
expiration 1/31/2016).
    This rule proposes to create new 30 CFR part 250, subpart G, Well 
Operations and Equipment, which will combine common requirements from 
the various other subparts mentioned, as well as add new requirements. 
The following explanations apply to this section: in the burden table, 
the OMB currently approved hour and/non-hour cost burdens for 
requirements will be identified with an asterisk (*); italics show 
revision(s) of existing requirements; and brackets indicate new 
requirements.
    A vast majority of this proposed rule contains IC burdens OMB has 
already approved (174,686 burden hours* and $102,500 non-hour cost 
burdens*). We are revising some existing requirements (+ 5,052 burden 
hours); and adding [new] regulatory requirements (+ [11,701 burden 
hours]) for a total of 191,439 burden hours.
    The following is a brief explanation of how the proposed regulatory 
changes affect the various subpart and form burdens:
     Subpart A--transferred the currently approved burden hours 
from Subpart D for BOPs pertaining to alternative procedures and 
departures (12,300 hours*).
     Subpart B--revised the requirement by adding information 
to be submitted with DWOPs pertaining to free standing hybrid risers 
(FSHR) (9,000 hours*; + 48 hours).
     APD--added NEW burden hours pertaining to requirements 
including, but not limited to, ECD information, current monitoring, 
changes to casing, etc. (47,800 hours* + [1,122 hours]). Because the 
responses remained unchanged, we did not list the non-hour costs 
burdens associated with APDs since the dollar amount will not change.
     APM--added NEW burden hours pertaining to requirements 
including, but not limited to, descriptions/calculations of production 
packer setting depth, annulus monitoring plan information, etc. (11,321 
hours* + [1,929 hours]). Because the responses remained unchanged, we 
did not list the non-hour costs burdens associated with APMs since the 
dollar amount will not change.
     Subpart D--
    (1) relocated common well operation and equipment requirements 
(10,811 hours*).
    (2) revised requirements for additional information relating to 
safe drilling margins, well head descriptions, casing or line 
centralization during cementing, submitting any changes to approved 
plans, permits, or submittal (+ 4,859 hours).
    (3) added NEW burden hours pertaining to requirements relating to, 
but not limited to, cementing, source control and containment 
capabilities, etc., (+ [1,923 hours]).
     Subpart G--
    (1) relocated burden hours from OMB currently approved requirements 
in D, E, F, P, and Q, that pertain to rig requirements, well 
operations, BOP system requirements, etc., as well as the hour and non-
hour cost burden from GPS for MODUs (NTL 2013-G01) (83,454 hours* and 
$102,500 non-hour cost burden*).
    (2) revised requirements that were relocated from other subparts in 
30 CFR 250 for additional information that may be needed for properly 
functioning acoustic systems, EDS, rating pressure, etc., and 
requirements needing approval by the District Manager (+ [145 hours]).
    (3) added NEW requirements pertaining to, but not limited to, warm 
or cold stacking for MODUs, dropped objects plan, real-time monitoring, 
pressure tests, etc., (+ [6,727 hours]).
     Subparts P and Q have only cross references to new Subpart 
G or current Subpart D and have no new associated burdens.
    Once this rule becomes effective, BSEE will use the approved OMB 
control number for the Subpart G information collection. The affected 
remaining subparts discussed in this rule will have their information 
collection burdens adjusted accordingly through the renewal process.

                                                  Burden Table
      [Current regulations are regular font with an asterisk (*); Italic font show revision(s) of existing
                          requirements; and bracketed text indicates new requirements]
----------------------------------------------------------------------------------------------------------------
                                      Reporting and
                                      recordkeeping
30 CFR 250 Current Revision NEW   requirement+  (BSEE-      Hour burden     Average number of    Annual burden
                                  Approved Verification                      annual responses   hours  (rounded)
                                  Organization = BAVO)
----------------------------------------------------------------------------------------------------------------
                                                    Subpart A
----------------------------------------------------------------------------------------------------------------
[107]..........................  NEW: Produce and         Burden covered under various 30 CFR  0
                                  submit documents         250 regulations (depending on the
                                  ordered by BSEE to          operational requirement(s)).
                                  ensure compliance
                                  with this part.
----------------------------------------------------------------------------------------------------------------

[[Page 21553]]

 
141; 198; [701; 720(a)(2);       Request approval to     20...............  496 requests.....  9,920 *
 730(d)(1)]; 1612.                use new or
                                  alternative
                                  procedures, along
                                  with supporting
                                  documentation if
                                  applicable, including
                                  BAST not specifically
                                  covered elsewhere in
                                  regulatory
                                  requirements.
----------------------------------------------------------------------------------------------------------------
142; 198; 702..................  Request approval of     2.5..............  952 requests.....  2,380 *
                                  departure from
                                  operating
                                  requirements not
                                  specifically covered
                                  elsewhere in
                                  regulatory
                                  requirements, along
                                  with supporting
                                  documentation if
                                  applicable.
----------------------------------------------------------------------------------------------------------------
    Subtotal (A)...............  ......................  .................  1,448 responses..  12,300 hours *
----------------------------------------------------------------------------------------------------------------
                                                    Subpart B
----------------------------------------------------------------------------------------------------------------
287; 291; 292(p)...............  Submit DWOP and         750..............  12 plans.........  9,000 *
                                  accompanying/          4................                     48
                                  supporting
                                  information. [Provide
                                  detailed information/
                                  descriptions
                                  pertaining to
                                  pipeline free
                                  standing hybrid riser
                                  (FSHR)]. Submit
                                  documentation for
                                  pipeline FSHR
                                  certification and
                                  have verified by CVA.
----------------------------------------------------------------------------------------------------------------
                                                                            12 responses       9,000 hours *
                                                                                               48 hours
    Subtotal (B)...............  ......................  .................  .................  9,048 hours
----------------------------------------------------------------------------------------------------------------
                                     Applications for Permit to Drill (APD)
----------------------------------------------------------------------------------------------------------------
410-418; [420(a)(7)];            Apply for permit to     114.98...........  408 applications.  46,912 *
 423(c)(1); [428(b), (k)]; plus   drill APD (Form BSEE-  2.75.............  .................  1,122
 various references in Subparts   0123) that includes
 A, D, E, F, [G (701; 702;        any/all supporting
 713(a), (b), (e), (g); 720(b);   documentation/
 721(g)(4); 724(b); 731;          evidence (including,
 733(b);734(b), (c); 737(a)(3),   but not limited to,
 (b)(2), (b)(3), (d)(2),          test results,
 (d)(3), (d)(4), (d)(12),         calculations,
 (d)(13); 738(m), (n)]; H; and    pressure integrity,
 P.                               kill weight fluids,
                                  verifications,
                                  certifications,
                                  procedures, criteria,
                                  qualifications,
                                  diverter
                                  descriptions; [ECD
                                  information]; rig
                                  anchor pattern plats;
                                  contingency plan
                                  (move off info/
                                  [current
                                  monitoring]);
                                  description of your
                                  BOP and its
                                  components and
                                  schematic drawings;
                                  [descriptive
                                  schematic (pressure
                                  ratings, dimensions,
                                  valves, load
                                  shoulders, height
                                  above water line
                                  etc.); location of
                                  ruptured disks;
                                  description of
                                  mudline level to
                                  displace cement; how
                                  the operator will
                                  visually monitor
                                  returns; PE
                                  certification showing
                                  approval of changes
                                  to casing setting
                                  depths; description
                                  of source control and
                                  containment
                                  capabilities; EDS;
                                  annulus monitoring
                                  plan information; any
                                  additional
                                  information required
                                  by District Manager];
                                  etc.) and requests
                                  for various approvals
                                  required in Subpart D
                                  (including Sec.  Sec.
                                    250.418(g); 427,
                                  428, 432, 460,
                                  490(c)) and submitted
                                  via the form; upon
                                  request, make
                                  available to BSEE.
----------------------------------------------------------------------------------------------------------------
[420(b)(4)]; 428; 465(a)(1);     Obtain approval to      1.34.............  662 submittals...  888 *
 [721(g)(4); 731; 733(f);         revise your drilling
 734(b), (c)].                    plan [changes to the
                                  casing], or change
                                  major drilling
                                  equipment by
                                  submitting a revised
                                  Form BSEE-0123,
                                  Application for
                                  Permit to Drill;
                                  [include BAVO
                                  certification; any
                                  other information
                                  required by the
                                  District Manager (on
                                  a case-by-case
                                  basis)].
----------------------------------------------------------------------------------------------------------------

[[Page 21554]]

 
    Subtotal (APD).............  ......................  .................  .................  47,800 hours*
                                                                                               [1,122 hours]
                                                                            1,070 responses    48,922 hours
----------------------------------------------------------------------------------------------------------------
                                     Application for Permit to Modify (APM)
----------------------------------------------------------------------------------------------------------------
460; 465; plus various ref in    Provide revised plans   3.377............  2,893              9,770 *
 A, D, E 518(f); F, 619(f); [G,   and the additional     [40 min].........   applications      [1,929]
 701; 702; 713(a), (b), (e),      supporting
 (g); 720(b); 721(g)(4);          information required
 724(b); 731; 733(b), (f),        by the cited
 734(b)(1); 737(d)(2), (d)(3),    regulations [test
 (d)(4), (d)(12), (d)(13);        results;
 738(m), (n)],; H; P; and Q       calculations;
 1704(g).                         verifications;
                                  certifications,
                                  procedures;
                                  [descriptions/
                                  calculations of
                                  production packer
                                  setting depth]; rig
                                  anchor pattern plats;
                                  contingency plan
                                  (move off info/
                                  [current
                                  monitoring]);
                                  description of your
                                  BOP, its components
                                  and schematic
                                  drawings; [annulus
                                  monitoring plan
                                  information];
                                  criteria;
                                  qualifications; etc.]
                                  when you submit an
                                  Application for
                                  Permit to Modify
                                  (APM) (Form BSEE-
                                  0124) to BSEE for
                                  approval.
----------------------------------------------------------------------------------------------------------------
Subparts D, E, F, H, P, Q......  Submit Revised APM      1................  1,551              1,551*
                                  plans (BSEE-0124).                         applications.
                                  (This burden
                                  represents only the
                                  filling out of the
                                  form).
----------------------------------------------------------------------------------------------------------------
    Subtotal (APM).............  ......................  .................  .................  11,321 hours *
                                                                                               [1,929 hours]
                                                                            4,444 responses    13,250 hours
----------------------------------------------------------------------------------------------------------------
                                                    Subpart D
----------------------------------------------------------------------------------------------------------------
420(b)(3); 465(a) (b)(3); plus   Submit form BSEE-0125   2................  239 submittals     478 *
 various ref in A, D, E, F, [G,   (End-of-Operations     1................                     239
 721(g)(8); 744]; P; Q            Report (EOR)) and all
 (1704([h]));.                    additional supporting
                                  information as
                                  required by the cited
                                  regulations; and any
                                  additional
                                  information required
                                  by the District
                                  Manager.
----------------------------------------------------------------------------------------------------------------
421(b).........................  Alaska only: Discuss    1................  1 discussion.....  1 *
                                  the cement fill level
                                  with the District
                                  Manager.
423(c)(2)......................  Document all your test  0.5..............  300 results......  150 *
                                  results and make them
                                  available to BSEE
                                  upon request.
428(c)(3); [428(k); 743(a),      In the GOM OCS Region,  1................  4,160 submittals.  4,160*
 (c); 746(e)]; plus various       submit drilling
 references in Subparts A, D,     activity reports
 [G].                             weekly (District
                                  Manager may require
                                  more frequent
                                  submittals on a case-
                                  by-case basis) on
                                  Forms BSEE-0133 (Well
                                  Activity Report
                                  (WAR)) and BSEE-0133S
                                  (Bore Hole Data) with
                                  supporting
                                  documentation.
428(c)(3); [428(k); 743(b),      In the Pacific and      1................  14 wells x 365     1,022 *
 (c)] plus various references     Alaska Regions during                      days x 20% year
 in Subparts A, D, [G].           drilling operations,                       = 1,022.
                                  submit daily drilling
                                  reports on Forms BSEE-
                                  0133 (Well Activity
                                  Report (WAR)) and
                                  BSEE-0133S (Bore Hole
                                  Data) with supporting
                                  documentation.
428(d).........................  Submit all remedial     5................  1,000 submittals.  5,000 *
                                  actions for review
                                  and approval by
                                  District Manager
                                  (before taking
                                  action); and any
                                  other requirements of
                                  the District Manager.
428(d).........................  Submit descriptions of  5................  564 submittals...  2,820
                                  completed immediate
                                  actions to District
                                  Manager (if taken to
                                  ensure safety of crew/
                                  prevent well-control
                                  event); and any other
                                  requirements of the
                                  District Manager.
428(d).........................  Submit PE               4................  450 submittals...  1,800
                                  certification of any
                                  proposed changes to
                                  your well program;
                                  and any other
                                  requirements of the
                                  District Manager.
[428(k)].......................  NEW: Maintain daily     [0.5]............  [75 reports].....  [38]
                                  drilling report
                                  (cementing
                                  requirements).

[[Page 21555]]

 
[428(k)].......................  NEW: If cement returns  [1]..............  [10 requests]....  [10]
                                  are not observed,
                                  contact the District
                                  Manager to obtain
                                  approval before
                                  continuing with
                                  operations.
[462(c)].......................  NEW: Submit a           [8]..............  [150 submittals].  [1,200]
                                  description of source
                                  control and
                                  containment
                                  capabilities to the
                                  Regional Supervisor
                                  for approval.
[462(d)].......................  NEW: Request re-        [1]..............  [600 requests]...  [600]
                                  evaluation of your
                                  source containment
                                  capabilities from the
                                  District Manager and
                                  Regional Supervisor..
[462(e)(1)]....................  NEW: Notify BSEE at     [0.5]............  [150               [75]
                                  least 21 days prior                        notifications].
                                  to pressure testing;
                                  needs to be witnessed
                                  by BSEE and a BAVO.
----------------------------------------------------------------------------------------------------------------
                                                                            6,722 responses..  10,811 hours*.
                                                                            1,014 responses..  4,859 hours
                                                                            [985 responses]..  [1,923 hours]
    Subtotal (D)...............  ......................  .................  8,721 responses..  17,593 hours
----------------------------------------------------------------------------------------------------------------
                                                    Subpart E
----------------------------------------------------------------------------------------------------------------
518(f).........................  Include in your APM        Burden covered under 1014-0026     0
                                  descriptions and
                                  calculations of
                                  production packer
                                  setting depth(s).
----------------------------------------------------------------------------------------------------------------
                                                    Subpart F
----------------------------------------------------------------------------------------------------------------
619(f).........................  Include in your APM        Burden covered under 1014-0026     0
                                  descriptions and
                                  calculations of
                                  production packer
                                  setting depth(s).
----------------------------------------------------------------------------------------------------------------
                                                    Subpart G
----------------------------------------------------------------------------------------------------------------
                                              General Requirements
----------------------------------------------------------------------------------------------------------------
[701; 720(a); 730(d)(1)]         Request alternative         Burden cover under 1014-0022      0
 [(250.141)].                     procedures or
                                  equipment from
                                  District Manager;
                                  along with any
                                  supporting
                                  documentation/
                                  information required.
[702] [(250.142)]..............  Request departures          Burden cover under 1014-0022      0
                                  from District
                                  Manager; include
                                  justification; and
                                  submit supporting
                                  documentation if
                                  applicable.
----------------------------------------------------------------------------------------------------------------
                                                Rig Requirements
----------------------------------------------------------------------------------------------------------------
[710(a)].......................  Instruct crew members   0.75.............  7,512 meetings...  5,634 *
                                  in safety
                                  requirements of
                                  operations--record
                                  dates and times of
                                  meetings, include
                                  potential hazards;
                                  make available to
                                  BSEE.
[710(b); 738(p)]...............  Prepare a well-control  0.5..............  308 plans........  154 *
                                  drill plan for each
                                  well, including but
                                  not limited to
                                  procedures, [EDS],
                                  crew assignments,
                                  established times to
                                  complete assignments,
                                  etc. Keep/post a copy
                                  of the plan on the
                                  rig at all times;
                                  post on rig floor/
                                  bulletin board.
[711(b), (c)]..................  Record in the daily     1................  8,320 drills.....  8,320 *
                                  report: time, date,
                                  and type of drill
                                  conducted; time to
                                  close diverter or
                                  BOP; total time for
                                  entire drill. The
                                  BSEE may require you
                                  to conduct a well-
                                  control drill during
                                  an inspection.
[712(a), (b), (f)].............  Notify BSEE of all rig  0.1..............  20 notices.......  2 *
                                  movements on or off
                                  locations.
                                 Rig movements reported  0.2..............  151 submittals...  30 *
                                  on Rig Movement
                                  Notification Report
                                  (Form BSEE-0144).
                                  Including MODUs,
                                  platform rigs;
                                  snubbing units, lift
                                  boats, wire-line
                                  units, and coiled
                                  tubing units 72 hours
                                  prior to movement; if
                                  the initial date
                                  changes by more than
                                  24 hours, submit
                                  updated BSEE-0144.

[[Page 21556]]

 
[712(c), (e)]..................  NEW: Notify District    [0.5]............  [25                [13]
                                  Manager if MODU or                         notifications].
                                  platform rig is to be
                                  warm or cold stacked
                                  on Form BSEE-0144;
                                  notify District
                                  Manager where the rig
                                  is coming from when
                                  entering OCS waters.
[712(d)].......................  NEW: Prior to resuming  [2]..............  [10 responses]...  [20]
                                  operations, report to
                                  District Manager any
                                  construction repairs
                                  or modifications that
                                  were made to the MODU
                                  or rig.
                                                        --------------------------------------
[713]..........................  Submit MODU or lift      Burden covered under 1014-0025 for   0
                                  boat information if          APD; and 1014-0026 for APM
                                  being used for well
                                  operations with your
                                  APD/APM.
                                                        --------------------------------------
[713(a), (b)]..................  Collect and report      5................  30 reports.......  150 *
                                  additional
                                  information on a case-
                                  by-case basis if
                                  sufficient
                                  information is not
                                  available.
                                                        --------------------------------------
[713(b)].......................  Reference to               Burden covered under 1010-0151     0
                                  Exploration Plan,
                                  Development and
                                  Production Plan, and
                                  Development
                                  Operations
                                  Coordination Document
                                  (30 CFR 550, Subpart
                                  B).
[713(c)(1)]....................  Submit 3rd party           Burden covered under 1014-0011     0
                                  review of drilling
                                  unit according to 30
                                  CFR 250, Subpart I.
                                                        --------------------------------------
[713(c)(2); (417(c)(2))].......  Have a Contingency         Burden covered under 1014-0025     0
                                  Plan that addresses
                                  design and operating
                                  limitations of MODU
                                  or lift boat.
                                                        --------------------------------------
[713(d) (417(d))]..............  Submit current             Burden covered under 1014-0025     0
                                  certificate of
                                  inspection/compliance
                                  from USCG and
                                  classification;
                                  submit documentation
                                  of operational
                                  limitations by a
                                  classification societ.
----------------------------------------------------------------------------------------------------------------
[714]..........................  NEW: Develop and        [40].............  [40 plans].......  [1,600]
                                  implement dropped
                                  objects plan with
                                  supporting
                                  documentation/
                                  information; any
                                  additional
                                  information required
                                  by the District
                                  Manager; make
                                  available to BSEE
                                  upon request.
----------------------------------------------------------------------------------------------------------------
[715] NTL......................  GPS for MODUs.........  0.25.............  1 rig............
                                --------------------------------------------------------------------------------
                                 1--Notify BSEE with     .................  1 notification     1 *
                                  tracking/locator data
                                  access and supporting
                                  information; notify
                                  BSEE Hurricane
                                  Response Team as soon
                                  as operator is aware
                                  a rig has moved off
                                  location.
                                --------------------------------------------------------------------------------
                                 2-Install and protect       20 devices per year for replacement and/or new x
                                  tracking/locator                          $325.00 = $6,500 *
                                  devices--(these are
                                  replacement GPS
                                  devices or new rigs).
                                --------------------------------------------------------------------------------
                                 3--Pay monthly          40 rigs x $50/month = ($600/year per 1 rig) = $24,000 *
                                  tracking fee for GPS
                                  devices already
                                  placed on MODUs/rig..
                                --------------------------------------------------------------------------------
                                 4--Rent GPS devices               40 rigs @$1,800 per year = $72,000 *
                                  and pay monthly
                                  tracking fee per rig.
----------------------------------------------------------------------------------------------------------------
                                                                            16,313 responses.  14,141 hours *
                                                                            [105 responses]..  [1,783 hours]
                                                                            16,418 responses.  15,924 hours
                                                                           -------------------------------------
    Subtotal (G--Rig Req.).....  ......................  .................    $102,500 Non-hour cost burdens *
----------------------------------------------------------------------------------------------------------------

[[Page 21557]]

 
                                                 Well Operations
----------------------------------------------------------------------------------------------------------------
[720(a)].......................  NEW: Notify and obtain  [5]..............  [150               [750]
                                  approval from the                          notifications].
                                  District Manager when
                                  interrupting
                                  operations before
                                  getting off the well.
                                                        --------------------------------------
[720(a)(2)]....................  Request approval to        Burden covered under 1014-0022     0
                                  use alternate
                                  procedures/barriers.
                                                        --------------------------------------
[720(b)].......................  Submit with your APD     Burden covered under 1014-0025 for   0
                                  or APM reasons for           APD; and 1014-0026 for APM
                                  displacing kill-
                                  weight fluid with
                                  detailed step-by-step
                                  written procedures
                                  how to displace the
                                  fluids, shear pipe
                                  procedures, etc.
                                                        --------------------------------------
[721(d), (f), (g)].............  Submit to the District  0.5..............  88 requests......  44 *
                                  Manager for approval
                                  plans to re-cement,
                                  repair, or run
                                  additional casing/
                                  liner for proper
                                  seal, along with PE
                                  certification of
                                  proposed plans. The
                                  District Manager may
                                  require you to
                                  perform additional
                                  pressure tests.
----------------------------------------------------------------------------------------------
[721(g)(4)]....................  Submit test procedures   Burden covered under 1014-0025 for   0
                                  and criteria for a          APD; and 1014-0026 for APM.
                                  successful test with
                                  APD/APM; if changes
                                  made to procedures,
                                  submit changes with
                                  revised APD or APM.
----------------------------------------------------------------------------------------------
[721(g)(5)]....................  Document all your test  0.75.............  1,340 results....  1,005 *
                                  results and make them
                                  available to BSEE
                                  upon request.
[721(g)(6)]....................  Contact the             1................  14 notifications.  14 *
                                  appropriate BSEE
                                  District Manager
                                  immediately if you
                                  have any indication
                                  of a failed negative
                                  pressure test; submit
                                  a description of the
                                  corrective action
                                  taken; and receive
                                  approval from the
                                  appropriate BSEE
                                  District Manager for
                                  the retest.
                                                        --------------------------------------
[721(g)(8); 744(a)]............  Submit Form BSEE-0125,     Burden covered under 1014-0018     0
                                  EOR.
                                                        --------------------------------------
[722]..........................  Caliper, pressure       3................  247 reports......  741 *
                                  test, or evaluate
                                  casing; submit
                                  evaluation results
                                  report including
                                  calculations; obtain
                                  approval before
                                  repairing or
                                  installing additional
                                  casing [(including PE
                                  Certification.)]; or
                                  resuming operations
                                  (every 30 days during
                                  prolonged drilling).
[722(b)(3)]....................  [ Perform a pressure    [1]..............  [300 results]....  [300]
                                  test after repairs
                                  made/casing installed
                                  and report results.
[723(d)].......................  Request exceptions      1.5..............  845 requests.....  1,268 *
                                  prior to moving
                                  rig(s) or related
                                  equipment.
[724]..........................  NEW: Immediately        [12].............  [50 submittals]..  [600]
                                  transmit real-time
                                  monitoring data
                                  onshore during
                                  operations or in HPHT
                                  reservoirs; store and
                                  monitor by qualified
                                  personnel.
                                                        --------------------------------------
[724(b)].......................  NEW: List designated     Burden covered under 1014-0025 for   0
                                  location where real-         APD; and 1014-0026 for APM
                                  time data will be
                                  stored and monitored
                                  in your APD or APM;
                                  make location and
                                  data accessible to
                                  BSEE upon request.
----------------------------------------------------------------------------------------------------------------
                                                                            2,534 responses..  3,072 hours *
                                                                            [500 responses]..  [1,650 hours]
    Subtotal (G--Well Op.).....                                             3,034 responses..  4,722 hours
----------------------------------------------------------------------------------------------------------------

[[Page 21558]]

 
                                             BOP System Requirements
----------------------------------------------------------------------------------------------------------------
[730; 731; 732]................  Submit BOP               Burden covered under 1014-0025 for   0
                                  descriptions with            APD; and 1014-0026 for APM
                                  your applicable APD
                                  or APM; third-party
                                  verification and
                                  supporting
                                  information/
                                  documentation.
                                                        --------------------------------------
[730(a)(4)]....................  NEW: Maintain current   [24].............  [10 requests]....  [240]
                                  set of approved
                                  schematic drawings on
                                  the rig and an
                                  onshore location;
                                  obtain District
                                  Manager approval to
                                  resume operations if
                                  any modifications or
                                  changes are made.
[730(c)(1)]....................  NEW: Provide written    [2]..............  [30 reports].....  [60]
                                  report to
                                  manufacturer within
                                  30 days of
                                  identifying equipment
                                  failure.
[730(c)(2)]....................  NEW: Initiate           [5]..............  [30 reports].....  [150]
                                  investigation and
                                  analysis within 60
                                  days to determine
                                  cause of equipment
                                  failure; provide the
                                  manufacturer a copy
                                  of analysis report.
[730(c)(3)]....................  NEW: Report the design  [5]..............  [2 reports]......  [10]
                                  change/modified
                                  procedures in writing
                                  to BSEE, OORP; within
                                  30 days of
                                  manufacturer's
                                  notification.
[730(d)(2)]....................  NEW: Request for        [5]..............  [1 response].....  [5]
                                  alternate to API
                                  Spec. Q1 to BSEE,
                                  OORP.
                                                        --------------------------------------
[731]..........................  Resubmit BOP system      Burden covered under 1014-0025 for   0
                                  component                   APD; and 1014-0026 for APM.
                                  documentation in your
                                  APD or APM when
                                  information changes
                                  or moved off location
                                  from well.
                                                        --------------------------------------
[732(a)].......................  NEW: Submit all         [5]..............  [5 submittals]...  [25]
                                  relevant information
                                  to nominate a
                                  verification
                                  organization for BSEE
                                  approval.
[732(b)].......................  NEW: Submit BAVO        [10].............  [150               [1,500]
                                  verification and all                       Verifications].
                                  supporting
                                  documentation related
                                  to this section (such
                                  as, but not limited
                                  to sharing testing,
                                  pressure integrity
                                  testing,
                                  calculations, etc.).
[732(c)].......................  NEW: Submit             [10].............  [10 wells].......  [100]
                                  verifications showing
                                  the BAVO conducted a
                                  comprehensive review
                                  of the BOP and
                                  related equipment for
                                  HPHT wells as listed
                                  in this section;
                                  submit verifications
                                  to the District
                                  Manager and Regional
                                  Supervisor before
                                  beginning operations
                                  in an HPHT
                                  environment.
[732(d), (e)]..................  NEW: Submit Mechanical  [10].............  [90 reports].....  [900]
                                  Integrity Assessment
                                  Report (completed by
                                  a BAVO) to BSEE,
                                  OORP; report must
                                  include all
                                  requirements listed
                                  in this section; make
                                  all documentation
                                  available to BSEE
                                  upon request.
                                                        --------------------------------------
[733(b)(2)]....................  NEW: Describe in your    Burden covered under 1014-0025 for   0
                                  APD or APM your              APD; and 1014-0026 for APM
                                  annulus monitoring
                                  plan.
----------------------------------------------------------------------------------------------------------------
[734(a)(7)]....................  Demonstrate that any    5................  1 validation.....  5 *
                                  acoustic control       1................  10 submittals....  10
                                  system will function
                                  properly in proposed
                                  environment and
                                  conditions; submit
                                  any additional
                                  information requested.
----------------------------------------------------------------------------------------------------------------
[734(a)(9); 738(n)]............  Label all functions on  1.5..............  33 panels........  50 *
                                  all panels.
                                                        --------------------------------------
[734(a)(10)]...................  Develop written            Burden covered under 1014-0018     0
                                  procedures for
                                  operating the BOP
                                  stack and LMRP and
                                  minimum knowledge
                                  requirements for
                                  personnel authorized
                                  to operate and
                                  maintain BOP
                                  components.
                                                        --------------------------------------

[[Page 21559]]

 
[734(b), (c)]..................  Submit a revised APD/    Burden covered under 1014-0025 for   0
                                  APM with BAVO                APD; and 1014-0026 for APM
                                  [documenting repairs;
                                  before drilling out
                                  surface casing];
                                  perform a new BOP
                                  test upon relatch,
                                  etc.; receive
                                  approval from the
                                  District Manager.
                                                        --------------------------------------
[737(a)(3), (a)(4); (b)(2),      In your APD: submit        Burden covered under 1014-0025     0
 (b)(3); (d)(2)-(4), (d)(12),     stump, initial, or
 (d)(13)].                        pressure tests; and
                                  subsea BOP procedures
                                  and supporting
                                  relevant data/
                                  information; indicate
                                  which casing string
                                  and liner met the
                                  criteria of this
                                  section; quick
                                  disconnect procedures
                                  with your deadman
                                  test procedures, etc.
                                  Obtain District
                                  Manager approval of
                                  appropriate test
                                  pressures; may
                                  require more frequent
                                  testing on your BOP;
                                  or if you test
                                  annular BOP less than
                                  70 percent.
----------------------------------------------------------------------------------------------
[737(c); 746(a), (b), (c), (d)]  Record the time, date,  7.75.............  4,457 results....  34,542 *
                                  and results of all
                                  pressure tests,
                                  actuations, and
                                  inspections of the
                                  BOP system, system
                                  components, and
                                  marine riser in the
                                  daily report; onsite
                                  representative
                                  certify and sign/date
                                  reports, etc.;
                                  document sequential
                                  order of BOP, closing
                                  times, auxiliary
                                  testing, pressure,
                                  and duration of each
                                  test.
----------------------------------------------------------------------------------------------------------------
[737(d)(2), (d)(3), (d)(4)       Notify District         0.25.............  186 notifications  47 *
 (d)(12);].                       Manager at least 72    5.5..............  1,239 results....  6,815 *
                                  hours prior to
                                  pressure stump/
                                  initial tests on
                                  seafloor; if BSEE rep
                                  unable to witness
                                  test, provide results
                                  to BSEE within 72
                                  hours after
                                  completion; document
                                  all ROV intervention
                                  function test
                                  results; make
                                  available to BSEE
                                  upon request.
----------------------------------------------------------------------------------------------------------------
[737(d)(13)]...................  Document all            0.5..............  2,520 submittals.  1,260 *
                                  autoshear, EDS, and    1................  120 responses....  120
                                  deadman on your
                                  subsea BOP systems
                                  function test
                                  results; make
                                  available to BSEE
                                  upon request.
----------------------------------------------------------------------------------------------------------------
[737(e)].......................  Provide 72 hour         0.25.............  136 notices......  34 *
                                  advance notice of
                                  location of shearing
                                  ram tests or
                                  inspections; allow
                                  BSEE access to
                                  witness testing,
                                  inspections, and
                                  information
                                  verification.
[738; 746(e)]..................  NEW/Revised: Requires   [0.5]............  [25 requests]....  [13]
                                  District Manager
                                  Approval:
                                 (a), (d); 746(e)        [1]..............  [25 requests]....  [25]
                                  Report problems,
                                  issues, leaks;.
                                 (b) Put well in a safe  [1]..............  [25 requests]....  [25]
                                  condition;.
                                 (b) Prior to resuming   0.25.............  200 requests.....  50 *
                                  operations for new/
                                  repaired/reconfigured
                                  BOP.
                                 (g) Your well control   1................  15 requests......  15
                                  places demands above
                                  its rating pressure;
                                 (j) Two barriers in     [1]..............  [1 request]......  [1]
                                  place prior to BOP
                                  removal.
[738(b), (i)]..................  NEW: Submit a report/   [0.5]............  [50 submittals]..  [25]
                                  verification from
                                  BAVO that BOP is fit
                                  for service if have
                                  to repair, replace,
                                  or reconfigure a BOP.
[738(f)].......................  NEW: Notify the         [0.5]............  [15 submittals]..  [8]
                                  District Manager of
                                  BOP configuration
                                  changes.
[738(g)].......................  NEW: Demonstrate your   [1]..............  [15 submittals]..  [15]
                                  well-control
                                  procedures will not
                                  place demands above
                                  its rated working
                                  pressure.
[738(k)].......................  NEW: Contact District   [1]..............  [2 requests].....  [2]
                                  Manager for approval
                                  prior to latching up
                                  the BOP stack or re-
                                  establishing power.
                                                        --------------------------------------

[[Page 21560]]

 
[738(m)].......................  NEW: Request approval    Burden covered under 1014-0025 for   0
                                  in your APD or APM to        APD; and 1014-0026 for APM
                                  utilize any other
                                  well-control
                                  equipment.
                                                        --------------------------------------
[738(m)].......................  NEW: Request approval   [2]..............  [10 requests]....  [20]
                                  from District Manager
                                  to utilize any other
                                  well-control
                                  equipment; include
                                  report from BAVO on
                                  the equipment design
                                  and suitability; any
                                  other documentation/
                                  information required
                                  by District Manager.
                                                        --------------------------------------
[738(n)].......................  NEW: Include in your     Burden covered under 1014-0025 for   0
                                  APD or APM which pipe/       APD; and 1014-0026 for APM
                                  variable bore rams
                                  meet the criteria.
                                                        --------------------------------------
[738(o)].......................  NEW: Submit report to   [1]..............  [15 submittals]..  [15]
                                  the District Manager
                                  prepared by BAVO
                                  describing failure of
                                  redundant control and
                                  confirming no impact
                                  to the BOP that makes
                                  it unfit for well
                                  control purposes;
                                  receive approval to
                                  continue operations;
                                  submit any additional
                                  information requested
                                  by the District
                                  Manager.
[739]..........................  Document BOP            9.75.............  350 records......  3,413 *
                                  maintenance and
                                  inspection procedures
                                  used; record results
                                  of BOP inspections
                                  and maintenance
                                  actions; maintain BOP
                                  records for 2 years
                                  or longer if directed
                                  on the rig; maintain
                                  design, maintenance,
                                  inspection, and
                                  repair records for
                                  the life of the
                                  equipment; make
                                  available to BSEE
                                  upon request.
[739(b)].......................  NEW: Assemble a         [5]..............  [21 reports].....  [105]
                                  detailed report
                                  compiled by a BAVO
                                  documenting the once
                                  every 5-year
                                  inspection, including
                                  any problems and
                                  corrections; make
                                  available to BSEE
                                  upon request.
----------------------------------------------------------------------------------------------------------------
                                                                            9,122 responses..  46,216 hours *
                                                                            145 responses....  145 hours
                                                                            [532 responses]..  [3,244 hours]
    Subtotal (G--BOP SR).......  ......................  .................  9,799 responses..  49,605 hours
----------------------------------------------------------------------------------------------------------------
                                        Records and Reporting Requirement
----------------------------------------------------------------------------------------------------------------
[740; 711(b); 738(c); 745; 746]  Maintain a daily        25 min...........  312 reports......  130 *
                                  report and accurate    [1]..............  [25 responses]...  [25]
                                  records for each well
                                  onsite during
                                  operation [such items
                                  in the daily report
                                  include, but are not
                                  limited to, [date,
                                  time, type of drill],
                                  test results,
                                  actuations,
                                  inspection of the BOP
                                  system, system
                                  component, signoff
                                  approvals, etc.]; and
                                  any information
                                  required by the
                                  District Manager.
----------------------------------------------------------------------------------------------------------------
[740; 741].....................  Retain drilling         2.15.............  3,460 records....  7,439 *
                                  records for 90 days    [1]..............  [25 responses]...  [25]
                                  after drilling is
                                  complete; retain
                                  casing/liner
                                  pressure, diverter,
                                  BOP tests [and real-
                                  time data monitoring]
                                  for 2 years; retain
                                  well completion/well
                                  workover until well
                                  is permanently
                                  plugged/abandoned or
                                  lease is assigned;
                                  the records must
                                  contain appropriate
                                  information and any
                                  other information
                                  required by the
                                  District Manager.
----------------------------------------------------------------------------------------------------------------
[742] NTL......................  Record and submit well  3................  281 logs/surveys.  843 *
                                  logs and surveys run
                                  in the wellbore and/
                                  or charts of well
                                  logging operations.
                                                        --------------------------------------

[[Page 21561]]

 
                                 Record and submit       1................  281 reports......  281 *
                                  directional and
                                  vertical-well
                                  surveys..
                                 Record and submit       1................  55 reports.......  55 *
                                  velocity profiles and
                                  surveys..
                                 Record and submit core  1................  150 analyses.....  150 *
                                  analyses..
                                                        --------------------------------------
[743(a), (c)]..................  In the GOM OCS Region,     Burden covered under 1014-0018     0
                                  submit Well Activity
                                  Reports (WARs) weekly
                                  (District Manager may
                                  require more frequent
                                  submittals on case-by-
                                  case basis) on BSEE-
                                  0133 and BSEE-0133S
                                  (Open Hole Data
                                  Report) with
                                  supporting
                                  information described
                                  in this section; any
                                  additional
                                  information required
                                  by the District
                                  Manager.
                                                        --------------------------------------
[743(b), (c)]..................  In the Pacific and         Burden covered under 1014-0018     0
                                  Alaska OCS Regions
                                  during operations,
                                  submit WARs daily
                                  (BSEE-0133 and BSEE-
                                  0133S); with
                                  supporting
                                  information described
                                  in this section; any
                                  additional
                                  information required
                                  by the District
                                  Manager.
                                                        --------------------------------------
[744]..........................  Submit form BSEE-0125,     Burden covered under 1014-0018     0
                                  EOR.
                                                        --------------------------------------
[745]; NTL.....................  Submit copies of well   1.5..............  308 submissions..  462 *
                                  records;
                                  paleontological
                                  interpretations;
                                  service company
                                  reports; and other
                                  reports or records of
                                  operations to BSEE as
                                  requested.
[746]..........................  Record the time, date,  2................  4,160 results....  8,320 *
                                  and results of all
                                  casing and liner
                                  presser tests.
[746(f)].......................  Retain all records      1.5..............  1,563 records....  2,345 *
                                  pertaining to tests,
                                  actuations, and
                                  inspections at the
                                  facility; retain all
                                  the records listed in
                                  this section for a
                                  period of 2 years at
                                  the facility, at the
                                  lessee's field office
                                  nearest the OCS
                                  facility, or at
                                  another location
                                  conveniently
                                  available to BSEE;
                                  make all the records
                                  available to BSEE
                                  upon request.
----------------------------------------------------------------------------------------------------------------
                                                                            10,570 responses.  20,025 hours *
                                                                            [50 responses]...  [50 hours]
    Subtotal (G--Rec. & Rpt.     ......................  .................  10,620 responses.  20,075 hours.
     Req.).
----------------------------------------------------------------------------------------------------------------
                                                    Subpart P
----------------------------------------------------------------------------------------------------------------
1612...........................  Request exception from     Burden covered under 1014-0006     0
                                  30 CFR 250.711
                                  requirements.
----------------------------------------------------------------------------------------------------------------
                                                    Subpart Q
----------------------------------------------------------------------------------------------------------------
1704(g), [(h)].................  Submit Forms BSEE-0124   Burden covered under 1014-0018 for   0
                                  and BSEE-0125;           BSEE-0125; and 1014-0026 for BSEE-
                                  include all                             0124
                                  supporting
                                  documentation/
                                  information.
----------------------------------------------------------------------------------------------------------------
    Current burden.............  ......................  .................  52,235 responses.  174,686 hours *
    Revised burden.............  ......................  .................  1,159 responses..  5,052 hours
    [NEW burden]...............  ......................  .................  [2,172 responses]  [11,701 hours]
                                --------------------------------------------------------------------------------
        Grand Total............  ......................  .................  55,566 Responses.  191,439 Hours

[[Page 21562]]

 
                                                                                $102,500 Non-Hour Cost Burden
----------------------------------------------------------------------------------------------------------------
* Indicates burdens are covered under one of the following OMB approved control numbers: 1014-0022, Subpart A;
  1014-0024, Subpart B; 1014-0018, Subpart D; 1014-0004, Subpart E; 1014-0001, Subpart F; 1014-0006, Subpart P;
  1014-0010, Subpart Q; 1014-0013, GPS for MODUs; 1014-0025, APDs; or 1014-0026, APMs.
+ In the future BSEE will be allowing the option of electronic reporting for certain requirements.

    The BSEE specifically solicits comments on the following:
    (1) Is the IC necessary or useful for us to perform properly;
    (2) Is the proposed burden accurate;
    (3) Do you have any suggestions that will enhance the quality, 
usefulness, and clarity of the information to be collected; and
    (4) Can we minimize the burden on the respondents.
    In addition, the PRA requires agencies to also estimate the non-
hour cost burden to respondents or recordkeepers resulting from the 
collection of information. Therefore, if you have other than hour 
burden costs to generate, maintain, and disclose this information, you 
should comment and provide your total capital and startup cost 
components or annual operation, maintenance, and purchase of service 
components. Generally, your estimate should not include costs incurred 
for reasons other than to provide information or keep records for the 
government; or as part of customary and usual business or private 
practices. For further information on this burden, refer to 5 CFR 
1320.3(b)(1) and (2), or contact the BSEE Bureau Information Collection 
Clearance Officer.

National Environmental Policy Act of 1969 (NEPA)

    We prepared a draft environmental assessment that concludes that 
this proposed rule would not have a significant impact on the quality 
of the environment under NEPA. A copy of the draft Environmental 
Assessment can be viewed at www.regulations.gov (use the keyword/ID 
BSEE-2015-0002). We will consider any new information we receive during 
the public comment period for the proposed rule that may inform our 
analysis of the potential environmental impacts of the rule.

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 proposed 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.

Clarity of This Regulation

    We are required by E.O. 12866, E.O. 12988, and by the Presidential 
Memorandum of June 1, 1998, to write all rules in plain language. This 
means that each rule we publish must:
    (1) Be logically organized;
    (2) Use the active voice to address readers directly;
    (3) Use clear language rather than jargon;
    (4) Be divided into short sections and sentences; and
    (5) Use lists and tables wherever possible.
    If you feel that we have not met these requirements, send us 
comments by one of the methods listed in the ADDRESSES section. To 
better help us revise the rule, your comments should be as specific as 
possible. For example, you should tell us the numbers of the sections 
or paragraphs that you find unclear, which sections or sentences are 
too long, the sections where you feel lists or tables would be useful, 
etc.

Public Availability of Comments

    Before including your address, phone number, email address, or 
other personal identifying information in your comment, you should be 
aware that your entire comment--including your personal identifying 
information--may be made publicly available at any time. While you can 
ask us in your comment to withhold your personal identifying 
information from public review, we cannot guarantee that we will be 
able to do so.

List of Subjects in 30 CFR Part 250

    Administrative practice and procedure, Continental shelf, 
Environmental impact statements, Environmental protection, 
Incorporation by reference, Oil and gas exploration, Penalties, Public 
lands--mineral resources, Public lands--rights-of-way, Reporting and 
recordkeeping requirements, Sulphur.

    Dated: April 9, 2015.
Janice M. Schneider,
Assistant Secretary--Land and Minerals Management.

    For the reasons stated in the preamble, the Bureau of Safety and 
Environmental Enforcement (BSEE) is proposing to amend 30 CFR part 250 
as follows:

PART 250--OIL AND GAS AND SULPHUR 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.

0
2. In Sec.  250.102, revise paragraphs (b)(1) and (b)(11) through (13) 
and add paragraph (b)(19) to read as follows:


Sec.  250.102  What does this part do?

* * * * *
    (b) * * *

[[Page 21563]]



                           Table--Where To Find Information for Conducting Operations
----------------------------------------------------------------------------------------------------------------
           For information about . . .                                    Refer to . . .
----------------------------------------------------------------------------------------------------------------
(1) Applications for permit to drill (APD)......  30 CFR 250, subparts D and G.
 
                                                  * * * * * * *
(11) Oil and gas well-completion operations.....  30 CFR 250, subparts E and G.
(12) Oil and gas well-workover operations.......  30 CFR 250, subparts F and G.
(13) Decommissioning activities.................  30 CFR 250, subparts G and Q.
 
                                                  * * * * * * *
(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) The 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. The 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.
 Suspension of Production (SOO/                          250.171(e).
 SOP) Request.
(2) Deepwater Operations Plan   $3,599................  Sec.
 (DWOP).                                                 250.292(q).
(3) Application for Permit to   $2,113 for initial      Sec.
 Drill (APD); Form BSEE-0123.    applications only; no   250.410(d);
                                 fee for revisions.      Sec.
                                                         250.513(b);
                                                         Sec.
                                                         250.1617(a).
(4) Application for Permit to   $125..................  Sec.
 Modify (APM); Form BSEE-0124.                           250.465(b);
                                                         Sec.
                                                         250.513(b);
                                                         Sec.
                                                         250.613(b);
                                                         Sec.
                                                         250.1618(a);
                                                         Sec.
                                                         250.1704(g).
(5) New Facility Production     $5,426 A component is   Sec.
 Safety System Application for   a piece of equipment    250.802(e).
 facility with more than 125     or ancillary system
 components.                     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 fee   Sec.
 Safety System Application for   of $8,967 will be       250.802(e).
 facility with 25-125            charged if BSEE deems
 components.                     it necessary to visit
                                 a facility offshore,
                                 and $5,141 to visit a
                                 facility in a
                                 shipyard.
(7) New Facility Production     $652..................  Sec.
 Safety System Application for                           250.802(e).
 facility with fewer than 25
 components.
(8) Production Safety System    $605..................  Sec.
 Application--Modification                               250.802(e).
 with more than 125 components
 reviewed.
(9) Production Safety System    $217..................  Sec.
 Application--Modification                               250.802(e).
 with 25-125 components
 reviewed.
(10) Production Safety System   $92...................  Sec.
 Application--Modification                               250.802(e).
 with fewer than 25 components
 reviewed.
(11) Platform Application--     $22,734...............  Sec.
 Installation--Under the                                 250.905(l).
 Platform Verification Program.
(12) Platform Application--     $3,256................  Sec.
 Installation--Fixed Structure                           250.905(l).
 Under the Platform Approval
 Program.
(13) Platform Application--     $1,657................  Sec.
 Installation--Caisson/Well                              250.905(l)
 Protector.
(14) Platform Application--     $3,884................  Sec.
 Modification/Repair.                                    250.905(l).
(15) New Pipeline Application   $3,541................  Sec.
 (Lease Term).                                           250.1000(b).
(16) Pipeline Application--     $2,056................  Sec.
 Modification (Lease Term).                              250.1000(b).
(17) Pipeline Application--     $4,169................  Sec.
 Modification (ROW).                                     250.1000(b).
(18) Pipeline Repair            $388..................  Sec.
 Notification.                                           250.1008(e).
(19) Pipeline Right-of-Way      $2,771................  Sec.
 (ROW) Grant Application.                                250.1015(a).
(20) Pipeline Conversion of     $236..................  Sec.
 Lease Term to ROW.                                      250.1015(a).
(21) Pipeline ROW Assignment..  $201..................  Sec.
                                                         250.1018(b).

[[Page 21564]]

 
(22) 500 Feet From Lease/Unit   $3,892................  Sec.
 Line Production Request.                                250.1156(a).
(23) Gas Cap Production         $4,953................  Sec.   250.1157.
 Request.
(24) Downhole Commingling       $5,779................  Sec.
 Request.                                                250.1158(a).
(25) Complex Surface            $4,056................  Sec.
 Commingling and Measurement                             250.1202(a);
 Application.                                            Sec.
                                                         250.1203(b);
                                                         Sec.
                                                         250.1204(a).
(26) Simple Surface             $1,371................  Sec.
 Commingling and Measurement                             250.1202(a);
 Application.                                            Sec.
                                                         250.1203(b);
                                                         Sec.
                                                         250.1204(a).
(27) Voluntary Unitization      $12,619...............  Sec.
 Proposal or Unit Expansion.                             250.1303(d).
(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.
 Decommission a Pipeline                                 250.1751(a) or
 (Lease Term).                                           Sec.
                                                         250.1752(a).
(31) Application to             $2,170................  Sec.
 Decommission a Pipeline (ROW).                          250.1751(a) or
                                                         Sec.
                                                         250.1752(a).
------------------------------------------------------------------------

0
5. Amend Sec.  250.198 by revising paragraphs (h)(51), (63), (68), and 
(70) and adding paragraphs (h)(89) through (94) to read as follows:


Sec.  250.198  Documents incorporated by reference.

* * * * *
    (h) * * *
    (51) API RP 2RD, Design of Risers for Floating Production Systems 
(FPSs) and Tension-Leg Platforms (TLPs), First Edition, June 1998; 
Reaffirmed May 2006, Errata June 2009; incorporated by reference at 
Sec. Sec.  250.292, 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, 250.737, and 250.739;
* * * * *
    (68) ANSI/API Spec. Q1, Specification for Quality Programs for the 
Petroleum, Petrochemical and Natural Gas Industry, ISO TS 29001:2007 
(Identical), Petroleum, petrochemical and natural gas industries--
Sector specific requirements--Requirements for product and service 
supply organizations, Eighth Edition, December 2007, Effective Date: 
June 15, 2008; incorporated by reference at Sec. Sec.  250.730 and 
250.806;
* * * * *
    (70) ANSI/API Spec. 6A, Specification for Wellhead and Christmas 
Tree Equipment, Nineteenth Edition, July 2004; Effective Date: February 
1, 2005; Contains API Monogram Annex as Part of U.S. National Adoption; 
ISO 10423:2003 (Modified), Petroleum and natural gas industries--
Drilling and production equipment--Wellhead and Christmas tree 
equipment; Errata 1, September 2004, Errata 2, April 2005, Errata 3, 
June 2006, Errata 4, August 2007, Errata 5, May 2009; Addendum 1, 
February 2008; Addendum 2, 3, and 4, December 2008; incorporated by 
reference at Sec. Sec.  250.730, 250.806, and 250.1002;
* * * * *
    (89) ANSI/API Spec. 11D1, Packers and Bridge Plugs, ISO 14310:2008 
(Identical), Petroleum and natural gas industries--Downhole equipment--
Packers and bridge plugs, Second Edition, Effective Date: January 1, 
2010; incorporated by reference at Sec. Sec.  250.518, 250.619, and 
250.1703;
    (90) ANSI/API Spec. 16A, Specification for Drill-through Equipment, 
Third Edition, June 2004; incorporated by reference at Sec.  250.730;
    (91) ANSI/API Spec. 16C, Specification for Choke and Kill Systems, 
First Edition, January 1993; incorporated by reference at Sec.  
250.730;
    (92) API Spec. 16D, Specification for Control Systems for Drilling 
Well control Equipment and Control Systems for Diverter Equipment, 
Second Edition, July 2004; incorporated by reference at Sec.  250.730;
    (93) ANSI/API Spec. 17D, Design and Operation of Subsea Production 
Systems--Subsea Wellhead and Tree Equipment, Second Edition; May 2011; 
ISO 13628-4 (Identical), Design and operation of subsea production 
systems-Part 4: Subsea wellhead and tree equipment; incorporated by 
reference at Sec.  250.730; and
    (94) ANSI/API RP 17H, Remotely Operated Vehicle Interfaces on 
Subsea Production Systems, ISO 13628-8:2002 (Identical), Petroleum and 
natural gas industries--Design and operation of subsea production 
systems--Part 8: Remotely Operated Vehicle (ROV) 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-0132, Evacuation    on the OCS comply with
 Statistics; BSEE-0143, Facility/         statutory and regulatory
 Equipment Damage Report; BSEE-1832,      requirements; are safe and
 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.

[[Page 21565]]

 
(3) Subpart C, Pollution Prevention and  (i) Evaluate measures to
 Control (1014-0023).                     prevent unauthorized discharge
                                          of pollutants into the
                                          offshore waters.
                                         (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        procedures to be used in
 Forms BSEE-0125, End of Operations       drilling operations on the
 Report; BSEE-0133, Well Activity         OCS.
 Report; and BSEE-0133S, Open Hole Data  (ii) Ensure that drilling
 Report.                                  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          (i) Evaluate the equipment and
 Workover 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         (i) Evaluate the equipment and
 Systems (1014-xxxx), including Form      procedures to be used during
 BSEE-0144, Rig Movement Notification     well drilling, completion,
 Report.                                  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 of
 Form BSEE-0149, Assignment of Federal    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       for hydrocarbons produced on
 BSEE-0126, Well Potential Test Report    the OCS.
 and BSEE-0128, Semiannual Well Test     (ii) Ensure economic
 Report.                                  maximization of ultimate
                                          hydrocarbon recovery.
(12) Subpart L, Oil and Gas Production   (i) Evaluate the measurement of
 Measurement, Surface Commingling, and    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, Sulphur Operations       (i) Evaluate sulphur
 (1014-0006).                             exploration and development
                                          operations on the OCS.
                                         (ii) Ensure that OCS sulphur
                                          operations meet statutory and
                                          regulatory requirements and
                                          will result in diligent
                                          development and production of
                                          sulphur 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               (i) Evaluate operators'
 Environmental Management Systems (1014-  policies and procedures to
 0017), including Form BSEE-0131,         assure safety and
 Performance 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;      adequacy of the equipment,
 and Supplemental APD Information         materials, and/or procedures
 Sheet, Form BSEE-0123S, and all          that the lessee or operator
 supporting documentation (1014-0025).    plans to use during drilling.
                                         (ii) Ensure that applicable OCS
                                          operations meet statutory and
                                          regulatory requirements.

[[Page 21566]]

 
(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.
------------------------------------------------------------------------

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 (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) 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; 
and
* * * * *
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.


Sec.  Sec. Sec.  250.401 through 250.403  [Removed and Reserved]

0
9a. Remove and reserve Sec. Sec.  250.401 through 250.403, and 250.406.


Sec.  Sec.  250.406  [Removed and Reserved]

0
9b. Remove and reserve Sec.  250.406.
0
10. 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, including the 
following:

------------------------------------------------------------------------
                                                              Where  to
       Information that you  must include with an APD          find  a
                                                             description
------------------------------------------------------------------------
(a) Plat that shows locations of the proposed well.........         Sec.
                                                                 250.412
(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 an MODU, and....................         Sec.
                                                                 250.713
(h) Additional information.................................         Sec.
                                                                 250.418
------------------------------------------------------------------------

0
11. 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, maximum 
equivalent circulating density, and casing setting depths in true 
vertical measurements;
* * * * *
0
12. Amend Sec.  250.414 by revising paragraphs (c), (h), and (i) and 
adding paragraphs (j) and (k) to read as follows:


Sec.  250.414  What must my drilling prognosis include?

* * * * *
    (c) Planned safe drilling margins between proposed drilling fluid 
weights and the estimated pore pressures, and proposed drilling fluid 
weights and the lesser of estimated fracture gradients or casing shoe 
pressure integrity test. Your safe drilling margins must meet the 
following conditions:
    (1) Static downhole mud weight must be greater than estimated pore 
pressure;
    (2) Static downhole mud weight must be a minimum of one-half pound 
per gallon below the lesser of the casing shoe pressure integrity test 
or the lowest estimated fracture gradient;
    (3) The equivalent circulating density must be below the lesser of 
the casing shoe pressure integrity test or the lowest estimated 
fracture gradient; and
    (4) When determining the pore pressure and lowest estimated 
fracture gradient for a specific interval, you must consider related 
hole 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.
0
13. 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

[[Page 21567]]

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
14. 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 descriptions:
    (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 annular BOP 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
15. Remove and reserve Sec.  250.417.
0
16. In Sec.  250.418, revise paragraph (g) 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;
* * * * *
0
17. Amend Sec.  250.420 by:
0
a. Revising the introductory text and paragraph (a)(5);
0
b. Redesignating paragraph (a)(6) as (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.
    (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.
    (2) You must use a weighted fluid to maintain an overbalanced 
hydrostatic pressure during the cement setting time, except when 
cementing casings or liners in riserless hole sections.
0
18. 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?

* * * * *

------------------------------------------------------------------------
      Casing type          Casing requirements    Cementing requirements
------------------------------------------------------------------------
 
                              * * * * * * *
(b) Conductor..........  Design casing and        Use enough cement to
                          select setting depths    fill the calculated
                          based on relevant        annular space back to
                          engineering and          the mudline.
                          geologic factors.       Verify annular fill by
                          These factors include    observing cement
                          the presence or          returns. If you
                          absence of               cannot observe cement
                          hydrocarbons,            returns, use
                          potential hazards, and   additional cement to
                          water depths.            ensure fill-back to
                         Set casing immediately    the mudline.
                          before drilling into    For drilling on an
                          formations known to      artificial island or
                          contain oil or gas. If   when using a well
                          you encounter oil or     cellar, you must
                          gas or unexpected        discuss the cement
                          formation pressure       fill level with the
                          before the planned       District Manager.
                          casing point, you must
                          set casing immediately
                          and set it above the
                          encountered zone.
 
                              * * * * * * *
(f) Liners.............  If you use a liner as    Same as cementing
                          surface casing, you      requirements for
                          must set the top of      specific casing
                          the liner at least 200   types. For example, a
                          feet above the           liner used as
                          previous casing/liner    intermediate casing
                          shoe.                    must be cemented
                         If you use a liner as     according to the
                          an intermediate string   cementing
                          below a surface string   requirements for
                          or production casing     intermediate casing.
                          below an intermediate
                          string, you must set
                          the top of the liner
                          at least 100 feet
                          above the previous
                          casing shoe.
                         You may not use a liner
                          as conductor casing.
------------------------------------------------------------------------

0
19. 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.
    (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.
    (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.

[[Page 21568]]

Sec. Sec.  250.424 through 250.426  [Removed and Reserved]

0
20. Remove and reserve Sec. Sec.  250.424 through 250.426.
0
21. 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
22. In Sec.  250.428, revise paragraphs (b) through (d) and add 
paragraph (k) to 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   Submit those changes to the District
 depths or hole interval drilling    Manager for approval and include a
 depth (for a BHA with an under-     certification by a professional
 reamer, this means bit depth)       engineer (PE) that he or she
 more than 100 feet true vertical    reviewed and approved the proposed
 depth (TVD) from the approved APD   changes.
 due to conditions encountered
 during drilling operations.
(c) Have indication of inadequate   (1) Locate the top of cement by: (i)
 cement job (such as lost returns,   Running a temperature survey; (ii)
 no cement returns to mudline or     Running a cement evaluation log; or
 expected height, cement             (iii) Using a combination of these
 channeling, or failure of           techniques.
 equipment).                        (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.
 
                              * * * * * * *
(k) Plan to use a valve on the      Include a description of the plan in
 drive pipe during cementing         your APD. Your description must
 operations for the conductor        include a schematic of the valve
 casing, surface casing, or liner.   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
23. 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
24. Amend Sec.  250.456:
0
a. In paragraph (i), by adding the word ``and'' after the semi-colon
0
b. By removing paragraph (j); and
0
c. By redesignating paragraph (k) as (j).
0
25. Revise Sec.  250.462 to read as follows.


Sec.  250.462  What are the source control and containment 
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 ability to deploy Source Control 
and Containment Equipment (SCCE) necessary 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 
whose collective purpose is to control a spill source and stop the flow 
of fluids into the environment or to contain fluids escaping into the 
environment. This 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, hydrate 
control, and dispersant injection equipment;
    (3) Riser systems;
    (4) Remotely operated vehicles (ROVs);
    (5) Capture vessels;
    (6) Support vessels; and
    (7) 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,

[[Page 21569]]

    (2) A discussion of the determination required in paragraph (a) of 
this section, and
    (3) Information showing that you have access to and 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 and 
containment equipment identified in the following table according to 
these requirements:

------------------------------------------------------------------------
                                Requirements, you        Additional
          Equipment                   must:              information
------------------------------------------------------------------------
(1) Capping stacks..........  (i) Function test     Pressure holding
                               all pressure          critical components
                               holding critical      are those
                               components on a       components that
                               quarterly frequency   will experience
                               (not to exceed 104    wellbore pressure
                               days between tests).  during a shut-in
                                                     after being
                                                     functioned.
                              (ii) Pressure test    Pressure holding
                               pressure holding      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 and a BSEE-   blind rams,
                               approved              wellhead
                               verification          connectors, and
                               organization.         outlet valves.
                              (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 30 CFR
                               250.800-250.808,
                               Subpart H.
                              (ii) Have all
                               equipment unique to
                               containment
                               operations
                               available for
                               inspection at all
                               times..
(3) Subsea utility equipment  Have all equipment    Subsea utility
                               unique to             equipment includes,
                               containment           but is not limited
                               operations            to: Hydraulic power
                               available for         sources, debris
                               inspection at all     removal, hydrate
                               times.                control equipment,
                                                     and dispersant
                                                     injection
                                                     equipment.
------------------------------------------------------------------------

0
26. 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
27. Remove and reserve Sec. Sec.  250.466 through 250.469.
0
28. 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.


Sec. Sec.  250.502 and 250.506   [Removed and Reserved]

0
29. Remove and reserve Sec. Sec.  250.502 and 250.506.


Sec.  250.514  [Amended]

0
30. In Sec.  250.514, remove paragraph (d).


Sec. Sec.  250.515 through 250.517   [Removed and Reserved]

0
31. Remove and reserve Sec. Sec.  250.515 through 250.517.
0
32. 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) Installed packers and bridge plugs must meet the following:
    (1) All packers and bridge plugs must comply with API Spec. 11D1 
(as incorporated by reference in Sec.  250.198);
    (2) During well completion operations, 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.
0
33. 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.


Sec.  250.602  [Removed and Reserved]

0
34a. Remove and reserve Sec.  250.602.


Sec.  250.606  [Removed and Reserved]

0
34b. Remove and reserve Sec.  250.606.


Sec.  250.614  [Amended]

0
35. In Sec.  250.614, remove paragraph (d).


Sec.  250.615  [Removed and Reserved]

0
36. Remove and reserve Sec.  250.615.
0
37. 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:

[[Page 21570]]

Sec.  250.616  Coiled tubing and snubbing operations.

* * * * *


Sec. Sec.  250.617 and 250.618  [Removed and Reserved]

0
38. Remove and reserve Sec. Sec.  250.617 and 250.618.
0
39. 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:
    (1) All 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 during 
well completion operations 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.
0
40. 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) or lift boat 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 MODUs and 
jack-ups?

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 
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 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 of this part. 
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 of this part.


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 that 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;
    (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 
most extreme service conditions to which it will 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) Date and time of safety meetings. The safety requirements for 
the

[[Page 21571]]

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. 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 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.
    (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 72 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 72 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 of 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) or lift boat for well operations?

    If you plan to use a MODU or lift boat for well operations, you 
must provide:
    (a) Fitness requirements. Information and data to demonstrate the 
capability to perform at the proposed location. This information must 
include the most extreme environmental and operational conditions that 
the unit 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 has the right 
to revoke the approval of the APD or APM if information collected 
during operations shows that the MODU or lift boat 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 MODU or lift boat. 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, lift boat, or 
equipment installed on a subsea wellhead. For moored rigs, you must 
submit a plat of the rigs' 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 or lift boat 
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 or lift boat design. If 
required, you must obtain a third-party review of your MODU or lift 
boat 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 or lift boat. 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 US Flagged vessels) or Certificate of 
Compliance (for Foreign Flagged 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 rig unit. If you use a dynamically 
positioned MODU, you must include in your APD or APM your contingency 
plan for

[[Page 21572]]

moving off location in an emergency situation. Your plan must include, 
but not be limited to, such emergency events caused by storms, 
currents, station-keeping failure, power failure, and loss of well 
control. The District Manager may require your plan to include 
additional events and information.
    (f) Inspection of unit. The MODU or lift boat 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.


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.


Sec.  250.715  Do I need a global positioning system (GPS) for MODUs 
and jack-ups?

    All jack-up and moored 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 each hurricane season.
    (a) The GPS must be capable of monitoring the position and tracking 
the path in real-time if the moored MODU or jack-up 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) Contact the Regional Office and allow real-time access to the 
MODU or jack-up location data. When you contact the Regional Office, 
provide the following:
    (1) Name of the lessee and operator with contact information;
    (2) Rig/facility/platform 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 BSEE 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-lap 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-lap 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.

[[Page 21573]]

    (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 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 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 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 test prior to unlatching the BOP at 
any point in the well. The negative 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.
    (4) You must submit for approval with your APD or APM, test 
procedures and criteria for a successful negative 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 BSEE 
District Manager; and
    (ii) Submit a description of the corrective action taken and 
receive approval from the appropriate BSEE 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's casing with either a pressure test, caliper 
tool, or imaging tool. On a case-by-case basis the District Manager may 
require a specific method of evaluation; 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.
    (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) When conducting well operations with a subsea BOP or surface 
BOP on a floating facility or when operating in an HPHT environment you 
must, within 3 years of publication of the final rule, gather and 
monitor real-time well data using an independent, automatic, and 
continuous monitoring system capable of recording, storing, and 
transmitting all aspects of:
    (1) The BOP control system;
    (2) The well's fluid handling systems on the rig; and
    (3) The well's downhole conditions with the bottom hole assembly 
tools (if any tools are installed).
    (b) You must immediately transmit these data as they are gathered 
to a

[[Page 21574]]

designated onshore location during operations where they must be 
monitored by qualified personnel who must be in continuous contact with 
rig personnel during operations. After operations, you must preserve 
and store this data at a designated location for recordkeeping purposes 
as required in Sec. Sec.  250.740 and 250.741. You must designate the 
location where the data will be stored and monitored during operations 
in your APD or APM. The location and the data must be made accessible 
to BSEE upon request.
    (c) If you lose any real-time monitoring capability during 
operations covered by this section, you must immediately notify the 
District Manager. The District Manager may require other measures until 
real-time monitoring capability is restored.

Blowout Preventer (BOP) System Requirements


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

    (a) You must design, install, maintain, inspect, test, and use the 
BOP system and system components to ensure well control. The working-
pressure rating of each BOP component 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. Each ram (excluding casing shear/
supershear) must be capable of closing and sealing the wellbore at all 
times, including under flowing conditions as defined for the operation 
and 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 you may encounter. Your BOP system must 
meet the following requirements:
    (1) The BOP requirements of API Standard 53 (incorporated by 
reference in Sec.  250.198) and the requirements of Sec. Sec.  250.733 
through 250.739. If there is a conflict between API Standard 53 and the 
requirements of this subpart, you must follow the requirements of this 
subpart.
    (2) The following industry standards (all incorporated by reference 
in Sec.  250.198):
    (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 
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 design, fabricate, maintain, and repair your BOP 
system according to the requirements contained in this subpart, 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, and:
    (1) You must provide a written report of equipment failure to the 
manufacturer of such equipment within 30 days after the discovery and 
identification of the failure.
    (2) You must ensure that an investigation and a failure analysis 
are initiated within 60 days of the failure to determine the cause of 
the failure. If the investigation and analysis are performed by an 
entity other than the manufacturer, you must ensure that the 
manufacturer receives a copy of the analysis.
    (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 notice or change, report the design change or 
modified procedures in writing to the Chief, Office of Offshore 
Regulatory Programs; Bureau of Safety and Environmental Enforcement; HE 
3314; 45600 Woodland Road, Sterling, Virginia 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) The BSEE may consider accepting equipment manufactured under 
quality assurance programs other than API Spec. Q1, provided you submit 
a request to BSEE containing relevant information about the alternative 
program and receive BSEE approval under Sec.  250.141.
    (2) You must submit this request to the Chief, Office of Offshore 
Regulatory Programs; Bureau of Safety and Environmental Enforcement; HE 
3314: 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.

------------------------------------------------------------------------
            You must submit:                        Including:
------------------------------------------------------------------------
(a) A complete description of the BOP    (1) Pressure ratings of 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;

[[Page 21575]]

 
                                         (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-approved     Verification that:
 verification organization,
                                         (1) Test data clearly
                                          demonstrates the shear ram(s)
                                          will shear the drill pipe at
                                          the water depth as required in
                                          Sec.   250.732;
                                         (2) The BOP was designed,
                                          tested, and maintained to
                                          perform at the most extreme
                                          anticipated conditions; and
                                         (3) The accumulator system has
                                          sufficient fluid to function
                                          the BOP system without
                                          assistance from the charging
                                          system.
(d) Additional certification by a BSEE-  Verification that:
 approved verification organization, if
 you use a subsea BOP, a BOP in an HPHT
 environment as defined in Sec.
 250.807, or a surface BOP on a
 floating facility,
                                         (1) The BOP stack is designed
                                          for the specific equipment on
                                          the rig and for the specific
                                          well design;
                                         (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, deadman,      their sequences and timing.
 and emergency disconnect sequence
 (EDS) systems,
(f) Certification stating that the       ...............................
 Mechanical Integrity Assessment 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 
requirements for BOP systems and system components?

    (a) The BSEE will maintain a list of BSEE-approved verification 
organizations that you may use. For an organization to become a BSEE 
approved verification organization, it must submit the following 
information to the Chief, Office of Regulatory Programs: Bureau of 
Safety and Environmental Enforcement: 45600 Woodland Road, Sterling, 
Virginia, 20166, for BSEE review and approval:
    (1) Previous experience in verification or in the design, 
fabrication, installation, repair, or major modification of BOPs and 
related systems and equipment;
    (2) Technical capabilities;
    (3) Size and type of organization;
    (4) In-house availability of, or access to, appropriate technology. 
This should include computer programs, hardware, and testing materials 
and equipment;
    (5) Ability to perform the verification functions for projects 
considering current commitments;
    (6) Previous experience with BSEE requirements and procedures; and
    (7) 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 BSEE-approved verification 
organization and supporting documentation as required by this paragraph 
to the appropriate 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;

[[Page 21576]]

 
                                         (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 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 all testing
                                          results.
(2) Pressure integrity testing, and....  (i) Shows that testing is
                                          conducted immediately after
                                          the shearing tests;
                                         (ii) Demonstrates that the
                                          equipment will seal at the
                                          rated working pressure of the
                                          BOP for 30 minutes; and
                                         (iii) Includes all 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 BSEE-approved 
verification organization that the verification organization conducted 
a comprehensive review of the BOP system and related equipment you 
propose to use. You must provide the BSEE-approved verification 
organization 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 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 overall    reasonable potential modes of
 system have been proven in a testing     failure, and
 process that demonstrates the           (ii) Evaluation of the design
 performance and reliability of the       verification tests. The design
 equipment in a manner that is            verification tests must assess
 repeatable and reproducible,             the equipment for the
                                          identified potential modes of
                                          failure.
(3) Verification that the BOP equipment  ...............................
 will perform as designed in the
 temperature, pressure, and environment
 that will be encountered, and
(4) Verification that the fabrication,   For the quality control and
 manufacture, and assembly of             assurance mechanisms, complete
 individual components and the overall    material and quality controls
 system uses recognized engineering       over all contractors,
 practices and quality control and        subcontractors, distributors,
 assurance mechanisms.                    and suppliers at every stage
                                          in the fabrication,
                                          manufacture, and assembly
                                          process.
------------------------------------------------------------------------

    (d) 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 BSEE-approved verification 
organization. You must submit this report to the Chief, Office of 
Regulatory Programs: Bureau of Safety and Environmental Enforcement: 
45600 Woodland Road, Sterling, Virginia, 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 systems meet recognized 
engineering practices and 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.

[[Page 21577]]

    (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 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, 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, excluding the 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) Follow the BOP requirements in Sec.  250.734(a)(1). You must 
comply with this requirement within 5 years from the publication of the 
final rule.
    (2) Use a dual bore riser configuration, for risers installed after 
the effective date of this rule, 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 most extreme anticipated operating and 
environmental conditions.
    (i) For a dual bore riser configuration, the annulus between the 
risers must be monitored 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 for testing the casing or liner at Sec.  250.721.
    (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.
    (e) You must install hydraulically operated locks.
    (f) For a surface BOP used in HPHT environments, if operations are 
suspended to make repairs to any part of the BOP system, you must stop 
operations at a safe downhole location. Before resuming operations you 
must:
    (1) Submit a revised APD or APM including documentation of the 
repairs and a certification from a BSEE-approved verification 
organization stating that they reviewed the repairs, and that the BOP 
is fit for service; and
    (2) Receive approval from the District Manager.


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 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-           You must have at least one
 controlled, hydraulically operated       annular BOP, two BOPs equipped
 BOPs;                                    with pipe rams, and two BOPs
                                          equipped with shear rams. For
                                          the two shear ram requirement,
                                          you must comply with this
                                          requirement within 5 years
                                          from the publication of the
                                          final rule.
                                         (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, excluding the
                                          bottom hole assembly that
                                          includes heavy-weight pipe or
                                          collars, and bottom-hole
                                          tools.

[[Page 21578]]

 
                                         (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 that includes heavy-
                                          weight pipe or collars),
                                          workstring, tubing,
                                          appropriate area for the liner
                                          or casing landing string,
                                          shear sub on subsea test tree,
                                          and any electric-, wire-,
                                          slick-line in the hole under
                                          MASP. At least one shear ram
                                          must be capable of sealing the
                                          wellbore after shearing under
                                          MASP conditions as defined for
                                          the operation. Any non-sealing
                                          shear rams must be installed
                                          below the sealing shear rams.
(2) Have an operable dual-pod control    ...............................
 system to ensure proper and
 independent operation of the BOP
 system;
(3) Have the accumulator capacity        The accumulator capacity must:
 located subsea, to provide fast         (i) Function each required
 closure of the BOP components and to     shear ram, choke and kill side
 operate all critical functions in case   outlet valves, one pipe ram,
 of a loss of the power fluid             and disconnect the LMRP.
 connection to the surface;
                                         (ii) Have the capability of
                                          delivering fluid to each ROV
                                          function i.e., flying leads.
                                         (iii) Have dedicated
                                          independent bottles for the
                                          autoshear, deadman, and EDS
                                          systems.
                                         (iv) Perform under MASP
                                          conditions as defined for the
                                          operation.
(4) Have a subsea BOP stack equipped     The ROV must be capable of
 with remotely operated vehicle (ROV)     performing critical functions,
 intervention capability;                 including opening and closing
                                          each shear ram, choke and kill
                                          side outlet valves, all pipe
                                          rams, 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   The crew must be trained in the
 ROV crew on each rig unit on a           operation of the ROV. The
 continuous basis once BOP deployment     training must include
 has been initiated from the rig until    simulator training on stabbing
 recovered to the surface. The crew       into an ROV intervention panel
 must examine all ROV related well-       on a subsea BOP stack. The ROV
 control equipment (both surface and      crew must be in communication
 subsea) to ensure that it is properly    with designated rig personnel
 maintained and capable of shutting in    who are knowledgeable about
 the well during emergency operations;    the BOP's capabilities.
(6) Provide autoshear, deadman, and EDS  (i) Autoshear system means a
 systems for dynamically positioned       safety system that is designed
 rigs; provide autoshear and deadman      to automatically shut-in the
 systems for moored rigs;                 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 their
                                          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 shearing efficiency.
                                         (vi) The control system for the
                                          emergency functions must be a
                                          fail-safe design, and the
                                          logic must provide for the
                                          subsequent step to be
                                          independent from the previous
                                          step having to be completed.
(7) Demonstrate that any acoustic        If you choose to install an
 control system will function in the      acoustic control system in
 proposed 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 system will function
                                          in the proposed environment
                                          and conditions. The District
                                          Manager may require additional
                                          information.
(8) Have operational or physical         Incorporate enable buttons on
 barrier(s) on BOP control panels to      control panels to ensure two-
 prevent accidental disconnect            handed operation for all
 functions;                               critical functions.
(9) Clearly label all control panels     Label other BOP control panels
 for the subsea BOP system;               such as hydraulic control
                                          panel.
(10) Develop and use a management        The management system must
 system for operating the BOP system,     include written procedures for
 including the prevention of accidental   operating the BOP stack and
 or unplanned disconnects of the          LMRP (including proper
 system;                                  techniques to prevent
                                          accidental disconnection of
                                          these components) and minimum
                                          knowledge requirements for
                                          personnel authorized to
                                          operate and maintain BOP
                                          components.
(11) Establish minimum requirements for  Personnel must have:
 personnel authorized to operate         (i) Training in deepwater well-
 critical BOP equipment;                  control theory and practice
                                          according to the requirements
                                          of Subpart O; and
                                         (ii) A comprehensive knowledge
                                          of BOP hardware and control
                                          systems.

[[Page 21579]]

 
(12) Before removing the marine riser,   You must maintain sufficient
 displace the fluid in the riser with     hydrostatic pressure or take
 seawater;                                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 deep
 cellar when in an ice-scour area;        enough to ensure that the top
                                          of the stack is below the
                                          deepest probable ice-scour
                                          depth.
(14) Install at least two side outlets   (i) If your stack does not have
 for a choke line and two side outlets    side outlets, you must install
 for a kill line;                         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 each 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;.       pressure from both directions;
                                         (ii) If you have dual annulars,
                                          where one annular is on the
                                          LMRP and one annular is on the
                                          lower BOP stack, you must
                                          install a gas bleed line on
                                          each 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, including
                                          connection, 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 within 7 years from
                                          the publication of the final
                                          rule;
                                         (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 BSEE-
approved verification organization documenting the repairs and that the 
BOP is fit for service;
    (2) Perform a new BOP test in accordance with Sec. Sec.  250.737 
and 250.738 upon relatch including deadman and ROV intervention; 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) A surface accumulator system that provides 1.5 times the volume 
of fluid capacity 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 all BOP functions 
without assistance from a charging system, with the blind shear ram 
being the last in the sequence, and still have enough pressure to shear 
pipe and seal the well with a minimum pressure of 200 psi remaining on 
the bottles above the precharge 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 that may be installed below the bottom ram, but 
it must be installed beneath at least one pipe ram;
    (f) A fill-up line above the uppermost BOP;
    (g) Hydraulically operated locking devices installed on the sealing 
ram-type BOPs; and
    (h) A wellhead assembly with a rated working pressure that exceeds 
the maximum anticipated wellhead pressure.


Sec.  250.736  What are the requirements for choke manifolds, kelly 
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 rated working pressure at 
least as great as the rated working pressure 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 rated working pressure at 
least as great as the rated working pressure of the ram BOPs.
    (d) You must use the following BOP equipment with a rated working 
pressure and temperature of at least as great as the working pressure 
and

[[Page 21580]]

temperature of the ram BOP during all operations:
    (1) A kelly valve installed below the swivel (upper kelly valve);
    (2) A kelly valve installed at the bottom of the kelly (lower kelly 
valve). You must be able to strip the lower kelly valve through the BOP 
stack;
    (3) If you operate with a mud motor and use drill pipe instead of a 
kelly, one kelly valve installed above, and one strippable kelly valve 
installed below, the joint of pipe used in place of a kelly;
    (4) On a top-drive system equipped with a remote-controlled valve, 
a strippable kelly-type valve installed below the remote-controlled 
valve;
    (5) 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;
    (6) 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;
    (7) 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;
    (8) All required manual and remote-controlled kelly 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
    (9) 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 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 warrants.
    (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 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-shear   The high-pressure test must
 ram-type BOPs, ram-type BOPs, the        equal the rated working
 choke manifold, outside of all choke     pressure of the equipment or
 and kill side outlet valves (and         be 500 psi greater than your
 annular gas bleed valves for subsea      calculated MASP, as defined
 BOP), inside of all choke and kill       for the operation for the
 side outlet valves below uppermost       applicable section of hole.
 ram, and other BOP components.           Before you may test BOP
                                          equipment to the MASP plus 500
                                          psi, the District Manager must
                                          have approved those test
                                          pressures in your APD.
(3) High-pressure test for annular-type  The high pressure test must
 BOPs, inside of choke or kill valves     equal 70 percent of the rated
 (and annular gas bleed valves for        working pressure of the
 subsea BOP) above the uppermost ram      equipment or be 500 psi
 BOP.                                     greater than your calculated
                                          MASP, as defined for the
                                          operation for the applicable
                                          section of hole. Before you
                                          may test BOP equipment to the
                                          MASP plus 500 psi, the
                                          District Manager must have
                                          approved those test pressures
                                          in your APD.
------------------------------------------------------------------------

    (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 requirements of   If there is a conflict between
 API Standard 53 (as incorporated in      API Standard 53 testing
 Sec.   250.198).                         requirements and this section,
                                          you must follow the
                                          requirements of this section.
(2) Use water to test a surface BOP      (i) You must submit test
 system..                                 procedures with your APD or
                                          APM for District Manager
                                          approval.
                                         (ii) Contact the District
                                          Manager at least 72 hours
                                          prior to beginning the 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.
(3) Stump test a subsea BOP system       (i) You must use water to
 before installation..                    conduct this test. You may use
                                          drilling fluids to conduct
                                          subsequent tests of a subsea
                                          BOP system.

[[Page 21581]]

 
                                         (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 (b) and (c)
                                          of this section.
(4) Perform an initial subsea BOP test.  (i) You must perform the
                                          initial 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
                                          (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.
                                          You must pressure test the
                                          selected rams according to (b)
                                          and (c) of this section.
(5) Alternate tests between control      (i) For two complete BOP
 stations and pods..                      control 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 the pod
                                          used for pressure testing must
                                          be alternated between pressure
                                          tests.
                                         (ii) Any additional control
                                          stations must be function
                                          tested every 14 days.
(6) Pressure test variable bore-pipe     ...............................
 ram BOPs against the largest and
 smallest sizes of pipe in use,
 excluding the bottom hole assembly
 that includes heavy-weight pipe or
 collars and bottom-hole tools.
(7) Pressure test annular type BOPs      ...............................
 against the smallest pipe in use.
(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 blind-shear ram BOPs  ...............................
 every 14 days.
(11) Actuate safety valves assembled     ...............................
 with proper casing connections before
 running casing.
(12) Test and verify closure capability  (i) Each ROV must be fully
 of all ROV intervention functions on     compatible with the BOP stack
 your subsea BOP.                         ROV intervention panels.
                                         (ii) You must submit test
                                          procedures, including how you
                                          will test each ROV
                                          intervention function, with
                                          your APD or APM for District
                                          Manager approval.
                                         (iii) You must document all
                                          your test results and make
                                          them available to BSEE upon
                                          request.
(13) Function test autoshear, deadman,   (i) You must submit test
 and EDS systems separately on your       procedures with your APD or
 subsea BOP stack during the stump        APM for District Manager
 test. The District Manager may require   approval. The procedures for
 additional testing of the emergency      these function tests must
 systems. You must also test the          include the schematics of the
 deadman system and verify closure of     actual controls and circuitry
 the shearing rams during the initial     of the system that will be
 test on the seafloor.                    used during an actual
                                          autoshear or deadman event.
                                         (ii) The procedures must also
                                          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.

[[Page 21582]]

 
                                         (vi) You must pressure test the
                                          blind-shear ram(s) according
                                          to (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 BSEE District Manager at least 72 hours in 
advance, to ensure that a representative of BSEE 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, to the District Manager
                                          and 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. You must
                                          submit a report from a BSEE-
                                          approved verification
                                          organization to the District
                                          Manager certifying that the
                                          BOP is fit for service.
(c) Need to postpone a BOP test due to   Record the reason for
 well-control problems such as lost       postponing the test in the
 circulation, formation fluid influx,     daily report and conduct the
 or stuck pipe;.                          required BOP test on 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 two sets
                                          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 ram bonnets before
 casing shear rams in a surface BOP       running casing to the rated
 stack;.                                  working pressure or MASP plus
                                          500 psi. The BOP must also
                                          provide for sealing the well
                                          after casing is sheared. 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-
 rated working pressure less than the     control procedures or the
 anticipated surface pressure;.           anticipated well conditions
                                          will not place demands above
                                          its rated working pressure and
                                          obtain approval from the
                                          District Manager.
(h) Plan to use a subsea BOP system in   Install the BOP stack in a well
 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 pipe  Retrieve, physically inspect,
 or casing is sheared;.                   and conduct a full pressure
                                          test of the BOP stack after
                                          the situation is fully
                                          controlled. You must submit to
                                          the District Manager a report
                                          from 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.
(k) In the event of a deadman or         Place the blind-shear ram
 autoshear activation, if there is a      opening function in the block
 possibility of the blind-shear ram       position prior to re-
 opening immediately upon re-             establishing power to the
 establishing power to the BOP stack;     stack. Contact the 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;.......  Conduct the initial BOP test
                                          after latching up using a test
                                          tool, and test the wellhead/
                                          BOP connection to the maximum
                                          pressure for the approved ram
                                          test for the well. All
                                          hydraulically operated BOP
                                          components must also be
                                          functioned during the well
                                          connection test.

[[Page 21583]]

 
(m) Plan to utilize any other well-      Contact the District Manager
 control equipment (e.g., but not         and request approval in your
 limited to, subsea isolation device,     APD or APM. Your request must
 subsea accumulator module, or gas        include a report from a BSEE-
 handler) that is in addition to the      approved verification
 equipment required in this subpart;      organization on the
                                          equipment's design and
                                          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
 that have no current utility or well-    which pipe/variable bore rams
 control purposes;                        meet 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., pipe/  that are applicable to those
 variable bore rams, shear rams,          well-control components. If
 annular preventers, gas bleed lines,     any redundant component fails
 and choke/kill side outlets or lines);   a test, you must submit a
                                          report from a BSEE-approved
                                          verification organization 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
                                          additional information.
(p) Need to position the bottom hole     Ensure that the well has been
 assembly, including heavy-weight pipe    stable for a minimum of 30
 or collars, and bottom-hole tools        minutes prior to positioning
 across the BOP for tripping or any       the bottom hole assembly
 other operations.                        across the BOP. You must have,
                                          as part of your well-control
                                          plan required by Sec.
                                          250.710, procedures that
                                          enable the immediate 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 all critical components 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 not be performed in 
phased intervals. A BSEE-approved verification organization is required 
to be present during the inspection and must compile a detailed report 
documenting the inspection, including descriptions of any problems and 
how they were corrected. You must make this report available to BSEE 
upon request.
    (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, meet the 
qualification and training criteria specified by the OEMs and 
recognized engineering practices.
    (e) You must make all records available to BSEE upon request. You 
must ensure that the rig owner maintains your BOP maintenance, 
inspection, and repair records on the rig for 2 years from the date the 
records are created or for a longer period if directed by BSEE. You 
must maintain all design, maintenance, inspection, and repair records 
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 
monitoring data;
    (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.


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 of
 diverter tests, BOP tests, and real-     operations.
 time monitoring data;

[[Page 21584]]

 
(c) Completion of a well or of any       You permanently plug and
 workover activity that materially        abandon the well or until you
 alters the completion configuration or   assign the lease and forward
 affects a hydrocarbon-bearing zone.      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 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 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. 
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 wells' 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.


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;
    (b) Require your onsite lessee representative, designated rig or 
contractor representative, and pump operator to sign and date the 
pressure charts 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 are considered problems or irregularities 
and must be reported immediately to the District Manager, and 
documented in the WAR. If any problems or irregularities are observed 
during testing, operations must be suspended

[[Page 21585]]

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 facility 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 facility. 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.
0
41. 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 of this 
part or as approved by the District Manager.
0
42. Amend Sec.  250.1703 by:
0
a. Revising paragraphs (b) and (e);
0
b. Redesignating paragraph (f) as paragraph (g); and
0
c. Adding a 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. All 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; and
* * * * *
0
43. Amend Sec.  250.1704 by revising paragraph (g) and adding paragraph 
(h) to 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        (i) Include
 Application for Permit to     temporarily abandon   information
 Modify (APM). The             or permanently plug   required under Sec.
 submission of your APM must   a well or zone,        Sec.   250.1712
 be accompanied by payment                           and 250.1721.
 of the service fee listed                          (ii) When using a
 in Sec.   250.125;                                  BOP for abandonment
                                                     operations, include
                                                     information
                                                     required under Sec.
                                                       250.731.
                              (2) Before you        Refer to Sec.
                               install a subsea      250.1722(a).
                               protective device,
                              (3) Before you        Refer to Sec.
                               remove any casing     250.1723.
                               stub or mud line
                               suspension
                               equipment and any
                               subsea protective
                               device,
(h) Form BSEE-0125, End of    (1) Within 30 days    Include information
 Operations Report (EOR);      after you complete    required under Sec.
                               a protective device     250.1722(d).
                               trawl test,
                              (2) Within 30 days    Include information
                               after you complete    required under Sec.
                               site clearance          250.1743(a).
                               verification
                               activities,
------------------------------------------------------------------------

Sec.  250.1705  [Removed and Reserved]

0
44. Remove and reserve Sec.  250.1705.
0
45. Amend Sec.  250.1706 by:
0
a. Revising the section heading;
0
b. Removing paragraphs (a) through (e); and
0
c. Redesignating paragraph (f) through (h) as paragraphs (a) through 
(c). The revision reads as follows:


Sec.  250.1706  Coiled tubing and snubbing operations.

* * * * *


Sec. Sec.  250.1707 through 250.1709   [Removed and Reserved]

0
46. Remove and reserve Sec. Sec.  250.1707 through 250.1709.
0
47. 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) * * *
    (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
48. Remove and reserve Sec.  250.1717.


Sec.  250.1721  [Amended]

0
49. Amend Sec.  250.1721 by removing paragraph (g) and redesignating 
paragraph (h) as paragraph (g).

[FR Doc. 2015-08587 Filed 4-13-15; 4:15 pm]
 BILLING CODE 4310-VH-P