21504 Federal Register / Vol. 80, No. 74 / Friday, April 17, 2015 / Proposed Rules 

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. 

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: http:// 

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 http:// 

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 wellcontrol best practices to advance safety 

and protection of the environment. 

This proposed rulemaking would: 

(1) Incorporate the following industry 

standards: 


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Federal Register / Vol. 80, No. 74 / Friday, April 17, 2015 / Proposed Rules 21505 

—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: http:// 

www.bsee.gov/Regulations-andGuidance/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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21506 Federal Register / Vol. 80, No. 74 / Friday, April 17, 2015 / Proposed Rules 

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 wellcontrol 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. Standardsdeveloping 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: http://www.api.org/ 

publications-standards-and-statistics/ 

publications/government-cited-safetydocuments. 

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: http://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, nonpartisan 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 WellDeepwater 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-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-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 decisionmakers, 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: http://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: 


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—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 http://

www.bsee.gov/Technology-andResearch/Technology-AssessmentPrograms/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 


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1See DOI JIT investigation recommendation, D6. 

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 § 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. 

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 highlytrained 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 BSEEapproved 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 BSEEapproved 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 


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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 

§ 250.617(b)) and decommissioning 

(current § 250.1707(b)) operations to 14 

days, which is consistent with the 

testing frequency requirements 

(reference current § 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 


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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 § 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? (§ 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? 

(§ 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 riskbased 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. (§ 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. 

(§ 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 optout 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. (§ 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? (§ 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. 


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2See DOI JIT investigation recommendation, A3. 

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. (§ 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 § 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? (§ 250.401) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed § 250.703. 

When and how must I secure a well? 

(§ 250.402) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed § 250.720. 

What drilling unit movements must I 

report? (§ 250.403) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed § 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? 

(§ 250.406) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed § 250.723. 

What information must I submit with 

my application? (§ 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? 

(§ 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? (§ 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. 

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? (§ 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 


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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? (§ 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 §§ 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)? 

(§ 250.417) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed § 250.713. 

What additional information must I 

submit with my APD? (§ 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? (§ 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? 

(§ 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? (§ 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 § 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? (§ 250.424) 

This section would be removed and 

reserved. The content of this section 

would be moved to in proposed 

§ 250.722. 

What are the requirements for pressure 

testing liners? (§ 250.425) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed § 250.721. 

What are the recordkeeping 

requirements for casing and liner 

pressure tests? (§ 250.426) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed § 250.746. 

What are the requirements for pressure 

integrity tests? (§ 250.427) 

Paragraph (b) would be revised to 

clarify that operators must maintain the 

drilling margins as described in 

§ 250.414. 

What must I do in certain cementing 

and casing situations? (§ 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 


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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 wellcontrol 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? 

(§ 250.440) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed § 250.730. 

What are the requirements for a surface 

BOP stack? (§ 250.441) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed §§ 250.733 

and 250.735. 

What are the requirements for a subsea 

BOP system? (§ 250.442) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed § 250.734. 

What associated systems and related 

equipment must all BOP systems 

include? (§ 250.443) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed 

§§ 250.733, 250.734, and 250.735. 

What are the choke manifold 

requirements? (§ 250.444) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed § 250.736. 

What are the requirements for kelly 

valves, inside BOPs, and drill-string 

safety valves? (§ 250.445) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed § 250.736. 

What are the BOP maintenance and 

inspection requirements? (§ 250.446) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed § 250.739. 

When must I pressure test the BOP 

system? (§ 250.447) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed § 250.737. 

What are the BOP pressure tests 

requirements? (§ 250.448) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed § 250.737. 

What additional BOP testing 

requirements must I meet? (§ 250.449) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed § 250.737. 

What are the recordkeeping 

requirements for BOP tests? (§ 250.450) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed § 250.746. 

What must I do in certain situations 

involving BOP equipment or systems? 

(§ 250.451) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed § 250.738. 

What safe practices must the drilling 

fluid program follow? (§ 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 § 250.720 to clarify that this 

requirement applies to drilling, 

workover, completion, and 

abandonment operations. 

What are the source control and 

containment requirements? (§ 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 §§ 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; 


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—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: 

Equipment Requirements Additional information 

(1) Capping stacks ....................... (i) Function test all pressure holding critical components on a quarterly frequency (not to exceed 104 

days), 

Pressure holding critical components are those components that will experience wellbore pressure 

during a shut-in after being functioned. 

(ii) Pressure test pressure holding critical components on a bi-annual basis, but not later than 210 

days from the last pressure test. All pressure testing must be witnessed by BSEE and a BSEE-approved verification organization, 

Pressure holding critical components are those components that will experience wellbore pressure 

during a shut-in. These components include, but 

are not limited to: all blind rams, wellhead connectors, and outlet valves. 

(iii) Notify BSEE at least 21 days prior to commencing any pressure testing. 

(2) Production safety systems 

used for flow and capture operations.

(i) Meet or exceed the requirements 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 unique to containment operations available for inspection at all times, Subsea utility equipment includes, but is not limited 

to: hydraulic power sources, debris 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? (§ 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 § 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? (§ 250.466) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed § 250.740. 

How long must I keep records? 

(§ 250.467) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed § 250.741. 

What well records am I required to 

submit? (§ 250.468) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed §§ 250.742 

and 250.743. 

What other well records could I be 

required to submit? (§ 250.469) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed § 250.745. 

Subpart E—Oil and Gas WellCompletion Operations 

General requirements. (§ 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. (§ 250.502) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed § 250.723. 

Crew instructions. (§ 250.506) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed § 250.710. 


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Well-control fluids, equipment, and 

operations. (§ 250.514) 

Paragraph (d) would be removed and 

its content would be moved to proposed 

§ 250.720. 

What BOP information must I submit? 

(§ 250.515) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed §§ 250.731 

and 250.732. 

Blowout prevention equipment. 

(§ 250.516) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed 

§§ 250.730, 250.733, 250.734, 250.735, 

and 250.736. 

Blowout preventer system tests, 

inspections, and maintenance. 

(§ 250.517) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed 

§§ 250.711, 250.737, 250.738, 250.739, 

and 250.746. 

Tubing and wellhead equipment. 

(§ 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 § 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. (§ 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. (§ 250.602) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed § 250.723. 

Crew instructions. (§ 250.606) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed § 250.710. 

Well-control fluids, equipment, and 

operations. (§ 250.614) 

Paragraph (d) would be removed and 

its content would be moved to proposed 

§ 250.720. 

What BOP information must I submit? 

(§ 250.615) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed §§ 250.731 

and 250.732. 

Coiled tubing and snubbing operations. 

(§ 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 §§ 250.730 and 250.733 

through 250.736. 

Blowout preventer system testing, 

records, and drills. (§ 250.617) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed 

§§ 250.711, 250.737, and 250.746. 

What are my BOP inspection and 

maintenance requirements? (§ 250.618) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed § 250.739. 

Tubing and wellhead equipment. 

(§ 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 § 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? (§ 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? 

(§ 250.701) 

Content in this proposed section is 

similar to existing § 250.408. This 

proposed section would explain that 

operators may seek approval to use 

alternate procedures or equipment 

following the process set forth in 

§ 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 


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§ 250.408 applicable to all operations 

covered by this subpart. 

May I obtain departures from these 

requirements? (§ 250.702) 

The content of this proposed section 

is similar to existing § 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 § 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? (§ 250.703) 

The content of this proposed section 

was moved from existing § 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? 

(§ 250.710) 

The content of this proposed section 

was moved from existing §§ 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 wellcontrol drills? (§ 250.711) 

The content of this proposed section 

was moved from existing §§ 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 wellcontrol equipment. 

What rig unit movements must I report? 

(§ 250.712) 

The content of this proposed section 

was moved from existing § 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 § 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? (§ 250.713) 

The content of this proposed section 

would be moved from existing 

§ 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? (§ 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 


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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? 

(§ 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? 

(§ 250.720) 

The content of this proposed section 

would be moved from existing 

§§ 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 

§ 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 

§ 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 § 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 

§§ 250.456(j), 250.514(d), 250.614(d), 

and 250.1709. 

What are the requirements for pressure 

testing casing and liners? (§ 250.721) 

The content of this proposed section 

would be moved from existing 

§§ 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 (§ 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? (§ 250.722) 

The content of this proposed section 

would be moved from existing 

§§ 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? (§ 250.723) 

This proposed section would reflect a 

combination of existing §§ 250.406, 

250.502, and 250.602. 

Paragraph (b) would be modified from 

existing § 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. 


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What are the real-time monitoring 

requirements? (§ 250.724) 

This proposed new section would 

include a requirement covering realtime 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? 

(§ 250.730) 

This proposed section would reflect a 

combination of existing §§ 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 Drillthrough Equipment; 

—ANSI/API Spec. 16C, Specification for 

Choke and Kill Systems; 

—API Spec. 16D, Specification for 

Control Systems for Drilling Wellcontrol 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. 

Industry standard Applicable topics in API standard 53 (but not limited to): 

ANSI/API Spec. 6A, Specification for Wellhead and Christmas Tree 

Equipment; 

Flanges and hubs, Bolting and clamps, Gaskets, Choke and kill lines, 

Equipment marking and storage, Equipment modifications, Maintenance and testing. 

API Spec. 16A, Specification for Drill-through Equipment; Flanges and hubs, Bolting and clamps, Gaskets, Choke and kill lines, 

Equipment marking and storage, Maintenance and testing. 

ANSI/API Spec. 16C, Specification for Choke and Kill Systems; Choke manifolds, Choke and kill lines. 

API Spec. 16D, Specification for Control Systems for Drilling Well-control Equipment and Control Systems for Diverter Equipment; Control systems, Maintenance and testing. Electro-hydraulic and multiplex control systems, Auxiliary equipment, Accumulators. 


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Industry standard Applicable topics in API standard 53 (but not limited to): 

ANSI/API Spec. 17D, Design and Operation of Subsea Production Systems — Subsea Wellhead and Tree Equipment; Flanges and hubs, Bolting and clamps, Choke and kill lines, 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? 

(§ 250.731) 

This proposed section would reflect a 

combination of existing §§ 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 § 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 

§ 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; 


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21522 Federal Register / Vol. 80, No. 74 / Friday, April 17, 2015 / Proposed Rules 

—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 § 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 § 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? (§ 250.732) 

This proposed section would reflect a 

combination of existing §§ 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 BSEEapproved 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 thirdparty 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: http://www.bsee.gov/

Technology-and-Research/TechnologyAssessment-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? (§ 250.733) 

This proposed section would be a 

combination of existing §§ 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 slickline. 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 § 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; 


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—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 § 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 § 250.441(d) would not be 

carried forward to proposed § 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 

§ 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 § 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? (§ 250.734) 

This proposed section would reflect a 

combination of existing §§ 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 § 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 failsafe 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 § 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 

§ 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 

§§ 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. 


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3For 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. 

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 nonsealing 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. 

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? (§ 250.735) 

This proposed section would reflect a 

combination of existing §§ 250.441, 

250.443, 250.516, 250.616, and 

250.1706. 

Proposed paragraph (a) would contain 

content from existing § 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? 

(§ 250.736) 

This proposed section would reflect a 

combination of existing §§ 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? (§ 250.737) 

This proposed section would reflect a 

combination of existing §§ 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 shutin 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 highpressure test requirements for BSR-type 


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BOPs, outside of all choke and kill sideoutlet 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? 

(§ 250.738) 

This proposed section would be a 

combination of existing §§ 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 §§ 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 


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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 

§ 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 reestablishing power, the operator would 

have to examine the system to 

determine if the possibility exists for the 

BSR opening immediately upon reestablishing 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 reestablished 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 BSEEapproved 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 BSEEapproved 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 § 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? (§ 250.739) 

This proposed section would reflect a 

combination of existing §§ 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 BSEEapproved 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? (§ 250.740) 

This proposed section would include 

content from existing § 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? 

(§ 250.741) 

This proposed section would contain 

content from existing § 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. 


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What well records am I required to 

submit? (§ 250.742) 

This proposed section would contain 

some content from existing § 250.468. 

The remainder of the existing § 250.468 

would be included in proposed 

§ 250.743. 

What are the well activity reporting 

requirements? (§ 250.743) 

This proposed section would include 

content from existing paragraphs (b) and 

(c) of existing § 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? (§ 250.744) 

This proposed section would combine 

provisions from existing §§ 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? (§ 250.745) 

This proposed section would reflect 

content from existing § 250.469. 

What are the recordkeeping 

requirements for casing, liner, and BOP 

tests, and inspections of BOP systems 

and marine risers? (§ 250.746) 

This proposed section would reflect a 

combination of existing §§ 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 (§ 250.1612) 

This section would update the 

reference for the drilling crew 

requirements under proposed § 250.711. 

Subpart Q—Decommissioning Activities 

What are the general requirements for 

decommissioning? (§ 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? (§ 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? 

(§ 250.1705) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed §§ 250.731 

and 250.732. 

Coiled tubing and snubbing operations. 

(§ 250.1706) 

Paragraphs (a) through (e) would be 

moved to proposed §§ 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? (§ 250.1707) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed 

§§ 250.711, 250.736, 250.737, and 

250.746. 

What are my BOP inspection and 

maintenance requirements? (§ 250.1708) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed § 250.739. 

What are my well-control fluid 

requirements? (§ 250.1709) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed § 250.720. 

How must I permanently plug a well? 

(§ 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 


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21528 Federal Register / Vol. 80, No. 74 / Friday, April 17, 2015 / Proposed Rules 

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? (§ 250.1717) 

This section would be removed and 

reserved. The content of this section 

would be moved to proposed § 250.744. 

If I temporarily abandon a well that I 

plan to re-enter, what must I do? 

(§ 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 § 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. 

Rig type Estimated daily operating cost 

Rigs that utilize a subsea BOP (e.g. drillships, semi-submersibles) ........................................................................ $1,000,000 

Rigs that utilize a surface BOP (e.g. jack-ups, lift boats) ......................................................................................... 200,000 

(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 widespread 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 


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4See recommendations of Offshore Energy Safety 

Advisory Committee, August 2012 meeting, 

available at: http://www.bsee.gov/uploadedFiles/

BSEE/About_BSEE/Public_Engagement/Ocean_

Energy_Safety_Advisory_Committee/OESC%20

Recommendations%20August%202012%20

Meeting%20Chairman%20Letter%20to%20BSEE

%20101512.pdf. 

5For 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 

http://www.npr.org/2011/04/19/135513456/oilfirms-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 

http://www.maersk.com/en/the-maersk-group/

about-us/maersk-post/2014-5/pushingtechnological-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 http://www.forbes.com/sites/

christopherhelman/2013/05/08/mcmoran-givesupdate-on-davy-jones-the-1-billion-ultradeep-well/; 

http://www.spe.org/tech/2012/04/highpressurehigh-temperature-challenges/. See also 

http://www.shell.com/global/aboutshell/majorprojects-2/perdido/unlocking-energy.html (Shell 

uses innovative, first-of-its-kind technology to 

produce ultra-deep Perdido well). 

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 § 250.734 of the final 

rule for subsea BOPs: 

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

In addition, BSEE is considering 

whether to also make this type of 

requirement applicable to surface BOPs 

in § 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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
21530 Federal Register / Vol. 80, No. 74 / Friday, April 17, 2015 / Proposed Rules 

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.’’ 


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tkelley on DSK3SPTVN1PROD with PROPOSALS2EP17AP15.005</GPH>

RIG MOVEMENT NOTIFICATION REPORT 

U. S. Department of the Interior OMB Control Number 1014-NEW 

Bureau of Safety & Environmental Enforcement OMB Approval Expires: xx/xx/xxxx 

Use this form to report the movement (including skids, stacking, and moving in or out of the 

OCS) of all rig units include MODUs, platform rigs, snubbing units, wire-line units used for 

non-routine operations, and coiled tubing units. If the rig is moving from one location to 

another, you may show this by completing the information for both rig departure and rig arrival 

on the same form. It is preferred by BSEE that the report information be submitted utilizing the 

BSEE eWell web based system at or you have the option to e-mail or 

telefax (see page 2 for contact information) to the appropriate BSEE Office(s) at least 72 hours 

before ou move the ri . 

GENERAL INFORMATION 

Report Date I Lease Operator 

Rig Name Rig Type: Barge ___ Coiled Tubing Unit ___ 

Drill Ship Jackup Platform 

Snubbing Unit Semisubmersible 

Submersible Wire-Line Unit --- ---

Rig Representative I Rig Telephone Number 

RIG ARRIVAL INFORMATION 

Rig Arrival Date Work Scheduled: Drilling ___ Workover ___ Completion ___ T A ___ PA ---

Other (specify) 

Is rig new to OCS? Location where rig came from: 

Yes No --------------------------------------------

Well API Number (10 digits) Well Name Expected Duration of Well Operations 

Well Surface Lease Area Name Block Latitude Longitude( Optional) 

Location No. No. (Optional) 

Information 

Structure Location Is Well Adjacent to If Yes, Identify Structure Distance from Structure 

Information Structure? 

(Optional) Yes No 

Remarks (Include size and extent of the mooring system and number of lighted and unlighted buoys 

deployed) (Optional) 
21532 Federal Register / Vol. 80, No. 74 / Friday, April 17, 2015 / Proposed Rules 


tkelley on DSK3SPTVN1PROD with PROPOSALS2EP17AP15.006</GPH>

RIG DEPARTURE INFORMATION 

Rig Departure Date I Well Status: Completed ___ DSI TA PA --- --- ---

Well API Number (10 digits) Well Name Is Rig Being Skidded on the Platform? 

Yes No --- ---

Well Surface Lease Area Name Block Latitude Longitude(Optional) 

Location No. No. (Optional) 

Information 

Area Clearance Is Area Clear of If No, Explain 

Information Obstructions? 

(Optional) Yes No 

Remarks (Include any significant en route movements) (Optional) 

RIG STACKING INFORMATION 

Rig Arrival Date Rig Departure Date 

Manned (warm) Un-manned (cold) Location: 

Any modifications, Date of Area Name Block No. Latitude(Optional) Longitude 

repairs, or Modifications, (Optional) 

construction: repairs, or 

construction 

Yes No 

Area Clearance Is Area Clear of Obstructions? If No, Explain 

Information Yes No --- roptional) 

Remarks (Explain any modifications, repairs, or construction.) 

CERTIFICATION: I certify that the information submitted above is complete and accurate to the 

best of my knowledge. I understand that making a false statement may subject me to criminal 

penalties under 18 U.S.C. 1001. 

Name and Title: Date: 
Federal Register / Vol. 80, No. 74 / Friday, April 17, 2015 / Proposed Rules 21533 

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-bysection 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. 

Subpart Removed and/or Reserved in 30 

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: 

Current regulations section Proposed rule section Nature of change 

Subpart A 

250.102(b) ....................................... 250.102(b) ..................................... Added reference to new subpart G. 

NEW ................................................ 250.107(a)(3), (a)(4); (e) ............... Added the use of 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. 


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Current regulations section Proposed rule section Nature of change 

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); 250.730; 250.731; 

250.732.

Revised to remove only the BOP 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 (f) .......................... Revised paragraph (b) 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. 


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Current regulations section Proposed rule section Nature of change 

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 250.711 .................... Removed heading and 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; 250.734; 

250.735; 250.736.

Removed—similar language found in new Subpart G. 

250.517 ........................................... 250.711; 250.737, 250.738, 

250.739; 250.746.

Removed—similar language found in 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; 250.734; 

250.735; 250.736.

Removed—similar language found in new Subpart G. 

250.616(f) through (h) ..................... 250.616(a) through (c) ................... Redesignated with no changes made to regulatory text. 

250.617 ........................................... 250.711; 250.737; 250.746 ........... Removed—similar 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; 

250.1707.

250.711 .......................................... Similar language was 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. 


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Current regulations section Proposed rule section Nature of change 

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); 250.514(d); 

250.614(d); 250.1709.

250.720 .......................................... Similar language was revised and 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; 

250.616(a) through (e); 250.1706.

250.730 .......................................... Similar language was revised and incorporated into this section about 

general requirements for BOP systems and their components. 

250.416; 250.515; 250.615; 

250.1705.

250.731 .......................................... Similar language was revised and incorporated into this section about 

submittal requirements for information about BOP systems and 

their components. 

250.416; 250.515; 250.615; 

250.1705.

250.732 .......................................... Similar language was revised and incorporated into this section relating to third-party information for BOP systems and their components. 

250.441; 250.443(c), (d); 250.516; 

250.616(a) through (e); 250.1706.

250.733 .......................................... Similar language was revised and incorporated into this section and 

new language was added relating to requirements for a surface 

BOP stack. 

250.442; 250.443(c), (d); 250.516; 

250.616(a) through (e); 250.1706.

250.734 .......................................... Similar language was revised and incorporated into this section and 

new language was added relating to requirements for a subsea 

BOP system. 

250.441; 250.443; 250.516; 

250.616; 250.1706.

250.735 .......................................... Similar language was 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; 

250.616(a) through (e); 250.1707.

250.736 .......................................... Similar language was revised and 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; 

250.517; 250.617; 250.1707.

250.737 .......................................... Added new language 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; 

250.1708.

250.739 .......................................... Similar language was 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; 

250.617; 250.1707.

250.746 .......................................... Similar language was 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. 


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6For 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: http:// 

www.fas.org/sgp/crs/misc/R42942.pdf. 

Current regulations section Proposed rule section Nature of change 

250.1706(a) through (e) .................. 250.730; 250.733, 250.734, and 

250.735.

Removed—similar language found in new Subpart G. 

250.1706(f) through (h) ................... 250.1706(a) through (c) ................. Revised the section heading; redesignated. 

250.1707 ......................................... 250.711, 250.736, 250.737, 

250.746.

Removed—similar 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)(iii)(B) ..................... Added the word ‘‘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. 

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 wellcontrol 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 


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7See 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 WellDeepwater Horizon Blowout, December 14, 2011; 

BSEE public offshore energy safety forum, May 22, 

2012. 

8BSEE considers compliance with permits, 

DWOPs, and industry standards to be ‘‘selfimplementing,’’ as addressed in Section E.2 of OMB 

Circular A–4, ‘‘Regulatory Analysis’’ (2003), and 

thus includes these costs in the baseline. 

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

Operation Current testing frequency Proposed 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. 

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’’). 

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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 80, No. 74 / Friday, April 17, 2015 / Proposed Rules 21539 

9Moreover, 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. 

10Trip 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. 

11See http://www.bsee.gov/Inspection-andEnforcement/Accidents-and-Incidents/Spills/. 

12BSEE 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. 

13Previous 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. 

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 BSEEapproved 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 realtime monitoring; and 

— Industry familiarization with the new 

rule. 

The BSEE estimated the benefits 

derived from time savings associated 

with § 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 § 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

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. 

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. 

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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
21540 Federal Register / Vol. 80, No. 74 / Friday, April 17, 2015 / Proposed Rules 

14Several 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. 

15The 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: http://www.boem.gov/uploadedFiles/

BOEM/Oil_and_Gas_Energy_Program/Leasing/Five_

Year_Program/2012–2017_Five_Year_Program/

PFP%20EconMethodology.pdf. 

16The 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. 

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. 

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. 

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

Year Total benefits 

(alternative 1) 

Total benefits 

(alternative 2) Total costs Net benefits (alternative 1) 

Net benefits 

(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 


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17Between 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 × $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 × $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. 

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

Annual risk 

reduction (%) Annual benefits Benefits (7% discounting) 

Benefits 

(3% discounting) 

Net benefits 

(undiscounted) 

Net benefits 

(7% discounting) 

Net benefits 

(3% 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). 

EXHIBIT 3—MONETIZED BENEFITS FROM AVERTED FATALITIES W/NET BENEFITS 1

Fatality risk reduction 

(%) 

Fatality risk 

reduction benefit 

Net benefits of 

proposed rule 

without fatality risk 

reduction (at a 1- 

percent risk 

reduction) 

Net benefits of proposed rule with fatality risk reduction 

(at a 1-percent risk reduction) 

Undiscounted 

Undiscounted 

Undiscounted 3% Discounting 7% Discounting 

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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
21542 Federal Register / Vol. 80, No. 74 / Friday, April 17, 2015 / Proposed Rules 

EXHIBIT 3—MONETIZED BENEFITS FROM AVERTED FATALITIES W/NET BENEFITS 1—Continued 

Fatality risk reduction 

(%) 

Fatality risk 

reduction benefit 

Net benefits of 

proposed rule 

without fatality risk 

reduction (at a 1- 

percent risk 

reduction) 

Net benefits of proposed rule with fatality risk reduction 

(at a 1-percent risk reduction) 

Undiscounted 

Undiscounted 

Undiscounted 3% Discounting 7% Discounting 

Total 10-year 

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 

1For 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 standardsdevelopment organizations, and 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 80, No. 74 / Friday, April 17, 2015 / Proposed Rules 21543 

18See 5 U.S.C. 601. 

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 wellcontrol operations, including BOP 

performance. 

The BSEE determined that the wellcontrol 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. 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
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19API 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. 

20Sums presented in the sections below may not 

equal the sums of the costs identified in this section 

because of rounding. 

21We 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 × $88.38 × 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). 

22We 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 × $88.38 × 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). 

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: 

—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 BSEEapproved 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 realtime 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

(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

(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

(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. 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 80, No. 74 / Friday, April 17, 2015 / Proposed Rules 21545 

23We 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 × 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 × 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). 

24We 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 × $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). 

25We 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 × $88.38 × 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). 

26We 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 × 

$88.38 × 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). 

27We 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 × 

$29.82 × 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). 

This provision would result in an 

average annual equipment and labor 

cost to industry of $6,115 per entity.23

(d) Additional capping stack testing 

requirements. 

Proposed § 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

(e) Additional information in the 

APM for installed packers. 

Proposed paragraphs (e) and (f) in 

§ 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

(f) Additional information in the APM 

for pulled and reinstalled packers. 

In § 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

(g) Rig movement reporting. 

Proposed § 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

(h) Fitness requirements for MODUs 

and lift boats. 

Proposed § 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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
21546 Federal Register / Vol. 80, No. 74 / Friday, April 17, 2015 / Proposed Rules 

28We 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 × $88.38 × 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). 

29We 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 × $88.38 × 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). 

30We 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 × 

$5,000 × 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). 

31For proposed § 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 × 

320), resulting in an average annual cost of 

$1,280,000 to industry. For § 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 × 10). 

For § 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 × 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). 

in an average annual labor cost to 

industry of $340 per entity.28

(i) Foundation requirements for 

MODUs and lift boats. 

Proposed § 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 sitespecific 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

(j) Real-time monitoring of well 

operations. 

Proposed § 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

(k) Additional documentation and 

verification requirements for BOP 

systems and system components. 

Proposed § 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 § 250.731(c) 

would require verification by a BSEEapproved 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 

§ 250.732(c) would require a 

comprehensive review by a BSEEapproved verification organization of 

BOP and related equipment being 

proposed for use in HPHT service. 

Proposed § 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

(l) Additional information in the APD, 

APM, or other submittals for BOP 

systems and system components. 

Proposed § 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 


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32We 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 × $88.38 × 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). 

33For 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 × 320). For 

labor costs, we assumed that industry staff (a midlevel 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 × 

$88.38 × 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). 

34API 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 × 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). 

35We 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 × 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 × $88.38 × 90). Summing the 

equipment and labor costs resulted in a total onetime 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). 

36We 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 × 90). We assumed that industry staff (rig 

crew) would spend five minutes (0.08 hours) per rig 

Continued 

pipe at the water depth (per proposed 

§ 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. 

(m) Submission of a Mechanical 

Integrity Assessment Report by a BSEEapproved verification organization. 

Proposed § 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 § 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

(n) New surface BOP requirements. 

Proposed § 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 § 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. 

(p) New surface accumulator system 

requirements. 

Proposed § 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

(q) Chart recorders. 

Proposed § 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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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 × 

$56.80 × 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). 

37We 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 × $88.38 × 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). 

38We 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 × $1 million 

× 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 × $200,000 × 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). 

39We 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 × 120 

× $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). 

40We 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 × 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 × 40 × $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). 

41We 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 × $88.38 × 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). 

(r) Notification and procedure 

requirements for testing of surface BOP 

systems. 

Proposed § 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

(s) Alternating BOP control station 

function testing. 

Proposed § 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. 

(t) ROV intervention function testing. 

Proposed § 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

(u) Autoshear, deadman, and EDS 

system function testing on subsea BOPs. 

Proposed § 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 § 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

(v) Approval for well-control 

equipment not covered in Subpart G. 

Proposed § 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 

§ 250.738(m) would include a similar 

change and introduce a requirement that 

an operator request approval from the 

BSEE District Manager to use wellcontrol 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. 

(w) Breakdown and inspection of the 

BOP system and components. 

Proposed § 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 BSEEapproved 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 


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42For 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 × 

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 × 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). 

43We 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 × $29.82 

× 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). 

44We 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 × $107.92 × 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). 

45The 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: http://

www.regulations.gov/#!documentDetail;D=BSEE2012-0002-0047. 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. 

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. 

(x) Additional recordkeeping for realtime monitoring. 

Proposed §§ 250.740(a) and 

§ 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

(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

(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. 

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 cost 

per entity 

(undiscounted) 

Average annual 

cost per entity 

(undiscounted) 

Percent of total 

cost 

(a) Additional information in the description of well drilling design criteria ............... $2,176 $218 0.03 

(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 packers ...................................... 442 44 0.01 

(f) Additional information in the APM for pulled and reinstalled packers .................. 1,717 172 0.03 

(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 requirements for BOP systems and 

system components ............................................................................................... 137,059 13,706 2.02 

(l) Additional information in the APD, APM, or other submittal for BOP systems 

and system components ........................................................................................ 2,176 218 0.03 

(m) Submission of a Mechanical Integrity Assessment Report by a BSEE-approved verification organization ............................................................................. 370,319 37,032 5.46 

(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 


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EXHIBIT 4—PER ENTITY COST OF THE PROPOSED RULE BY PROVISION 1—Continued 

Total 10 year cost 

per entity 

(undiscounted) 

Average annual 

cost per entity 

(undiscounted) 

Percent of total 

cost 

(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 on subsea BOPs ........ 385,385 38,538 5.68 

(v) Approval for well-control equipment not covered in Subpart G ........................... 7 1 0.00 

(w) Breakdown and inspection of BOP system and components ............................. 330,769 33,077 4.88 

(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

Year 2015 2016–2019 (each 

year the same) 2020 2021–2024 (each year the same) 

Annual Industry Cost Stream for Proposed Rule a ................. $164,728,509 $77,297,317 $98,797,317 $77,297,317 

Total Entities b ......................................................................... 130 130 130 130 

Average Annual Cost per Entity c = a ÷ b .............................. 1,268,175 595,628 761,012 595,628 

Average Annual Revenue for Small Entities 1 d ...................... 45,700,000 45,700,000 45,700,000 45,700,000 

Cost from Proposed Rule as a Percentage of Annual Revenue e = c ÷ d ...................................................................... 2.78% 1.30% 1.67% 1.30% 

1The 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: http://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

Operation Current testing 

frequency 

Proposed testing 

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

Operation Current testing 

frequency 

Proposed testing 

frequency (Alternative 1) 

Alternative 2 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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 80, No. 74 / Friday, April 17, 2015 / Proposed Rules 21551 

46See sources listed in n. 6. 

(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

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 foreignbased 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 

http://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. 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
21552 Federal Register / Vol. 80, No. 74 / Friday, April 17, 2015 / Proposed Rules 

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] 

30 CFR 250 Current 

Revision NEW 

Reporting and recordkeeping requirement+ 

(BSEE-Approved Verification Organization = 

BAVO) 

Hour burden Average number of 

annual responses 

Annual burden hours 

(rounded) 

Subpart A 

[107] ........................... NEW: Produce and submit documents ordered by BSEE to ensure compliance with 

this part.

Burden covered under various 30 CFR 250 

regulations (depending on the operational requirement(s)). 

0 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 80, No. 74 / Friday, April 17, 2015 / Proposed Rules 21553 

BURDEN TABLE—Continued 

[Current regulations are regular font with an asterisk (*); Italic font show revision(s) of existing requirements; and bracketed text indicates new 

requirements] 

30 CFR 250 Current 

Revision NEW 

Reporting and recordkeeping requirement+ 

(BSEE-Approved Verification Organization = 

BAVO) 

Hour burden Average number of 

annual responses 

Annual burden hours 

(rounded) 

141; 198; [701; 

720(a)(2); 

730(d)(1)]; 1612.

Request approval to use new or alternative 

procedures, along with supporting documentation if applicable, including BAST not 

specifically covered elsewhere in regulatory requirements.

20 ............................... 496 requests .............. 9,920 * 

142; 198; 702 ............. Request approval of departure from operating requirements not specifically covered 

elsewhere in regulatory requirements, 

along with supporting documentation if applicable.

2.5 .............................. 952 requests .............. 2,380 * 

Subtotal (A) ......... ......................................................................... .................................... 1,448 responses ........ 12,300 hours * 

Subpart B 

287; 291; 292(p) ........ Submit DWOP and accompanying/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.

750 .............................

4 .................................

12 plans ..................... 9,000 * 

48 

12 responses 9,000 hours * 

48 hours 

Subtotal (B) ......... ......................................................................... .................................... .................................... 9,048 hours 

Applications for Permit to Drill (APD) 

410–418; [420(a)(7)]; 

423(c)(1); [428(b), 

(k)]; plus various 

references in Subparts A, D, E, F, [G 

(701; 702; 713(a), 

(b), (e), (g); 720(b); 

721(g)(4); 724(b); 

731; 733(b);734(b), 

(c); 737(a)(3), 

(b)(2), (b)(3), (d)(2), 

(d)(3), (d)(4), 

(d)(12), (d)(13); 

738(m), (n)]; H; and 

P.

Apply for permit to drill APD (Form BSEE– 

0123) that includes any/all supporting documentation/evidence (including, but not 

limited to, test results, calculations, pressure integrity, 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 

§§ 250.418(g); 427, 428, 432, 460, 490(c)) 

and submitted via the form; upon request, 

make available to BSEE.

114.98 ........................

2.75 ............................

408 applications .........

....................................

46,912 * 

1,122 

[420(b)(4)]; 428; 

465(a)(1); 

[721(g)(4); 731; 

733(f); 734(b), (c)].

Obtain approval to revise your drilling 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)].

1.34 ............................ 662 submittals ............ 888 * 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
21554 Federal Register / Vol. 80, No. 74 / Friday, April 17, 2015 / Proposed Rules 

BURDEN TABLE—Continued 

[Current regulations are regular font with an asterisk (*); Italic font show revision(s) of existing requirements; and bracketed text indicates new 

requirements] 

30 CFR 250 Current 

Revision NEW 

Reporting and recordkeeping requirement+ 

(BSEE-Approved Verification Organization = 

BAVO) 

Hour burden Average number of 

annual responses 

Annual burden hours 

(rounded) 

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 A, D, E 518(f); 

F, 619(f); [G, 701; 

702; 713(a), (b), (e), 

(g); 720(b); 

721(g)(4); 724(b); 

731; 733(b), (f), 

734(b)(1); 737(d)(2), 

(d)(3), (d)(4), 

(d)(12), (d)(13); 

738(m), (n)],; H; P; 

and Q 1704(g).

Provide revised plans and the additional supporting information required by the cited 

regulations [test results; calculations; 

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.

3.377 ..........................

[40 min] ......................

2,893 applications 9,770 * 

[1,929] 

Subparts D, E, F, H, 

P, Q.

Submit Revised APM plans (BSEE–0124). 

(This burden represents only the filling out 

of the form).

1 ................................. 1,551 applications ...... 1,551* 

Subtotal (APM) ... ......................................................................... .................................... .................................... 11,321 hours * 

[1,929 hours] 

4,444 responses 13,250 hours 

Subpart D 

420(b)(3); 465(a) 

(b)(3); plus various 

ref in A, D, E, F, [G, 

721(g)(8); 744]; P; 

Q (1704([h]));.

Submit form BSEE–0125 (End-of-Operations 

Report (EOR)) and all additional supporting information as required by the cited 

regulations; and any additional information 

required by the District Manager.

2 .................................

1 .................................

239 submittals 478 * 

239 

421(b) ......................... Alaska only: Discuss the cement fill level 

with the District Manager.

1 ................................. 1 discussion ............... 1 * 

423(c)(2) .................... Document all your test results and make 

them available to BSEE upon request.

0.5 .............................. 300 results ................. 150 * 

428(c)(3); [428(k); 

743(a), (c); 746(e)]; 

plus various references in Subparts 

A, D, [G].

In the GOM OCS Region, submit drilling activity reports 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.

1 ................................. 4,160 submittals ......... 4,160* 

428(c)(3); [428(k); 

743(b), (c)] plus various references in 

Subparts A, D, [G].

In the Pacific and Alaska Regions during 

drilling operations, submit daily drilling reports on Forms BSEE–0133 (Well Activity 

Report (WAR)) and BSEE–0133S (Bore 

Hole Data) with supporting documentation.

1 ................................. 14 wells × 365 days × 

20% year = 1,022.

1,022 * 

428(d) ......................... Submit all remedial actions for review and 

approval by District Manager (before taking action); and any other requirements of 

the District Manager.

5 ................................. 1,000 submittals ......... 5,000 * 

428(d) ......................... Submit descriptions of 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.

5 ................................. 564 submittals ............ 2,820 

428(d) ......................... Submit PE certification of any proposed 

changes to your well program; and any 

other requirements of the District Manager.

4 ................................. 450 submittals ............ 1,800 

[428(k)] ....................... NEW: Maintain daily drilling report (cementing requirements).[0.5] ............................ [75 reports] ................. [38] 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 80, No. 74 / Friday, April 17, 2015 / Proposed Rules 21555 

BURDEN TABLE—Continued 

[Current regulations are regular font with an asterisk (*); Italic font show revision(s) of existing requirements; and bracketed text indicates new 

requirements] 

30 CFR 250 Current 

Revision NEW 

Reporting and recordkeeping requirement+ 

(BSEE-Approved Verification Organization = 

BAVO) 

Hour burden Average number of 

annual responses 

Annual burden hours 

(rounded) 

[428(k)] ....................... NEW: If cement returns are not observed, 

contact the District Manager to obtain approval before continuing with operations.

[1] ............................... [10 requests] .............. [10] 

[462(c)] ....................... NEW: Submit a description of source control 

and containment capabilities to the Regional Supervisor for approval.

[8] ............................... [150 submittals] .......... [1,200] 

[462(d)] ....................... NEW: Request re-evaluation of your source 

containment capabilities from the District 

Manager and Regional Supervisor..

[1] ............................... [600 requests] ............ [600] 

[462(e)(1)] .................. NEW: Notify BSEE at least 21 days prior to 

pressure testing; needs to be witnessed by 

BSEE and a BAVO.

[0.5] ............................ [150 notifications] ....... [75] 

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 descriptions and calculations of production packer setting 

depth(s).

Burden covered under 1014–0026 0 

Subpart F 

619(f) .......................... Include in your APM descriptions and calculations of production packer setting 

depth(s).

Burden covered under 1014–0026 0 

Subpart G 

General Requirements 

[701; 720(a); 

730(d)(1)] 

[(250.141)].

Request alternative procedures or equipment 

from District Manager; along with any supporting documentation/information required.

Burden cover under 1014–0022 0 

[702] [(250.142)] ........ Request departures from District Manager; 

include justification; and submit supporting 

documentation if applicable.

Burden cover under 1014–0022 0 

Rig Requirements 

[710(a)] ....................... Instruct crew members in safety requirements of operations—record dates and 

times of meetings, include potential hazards; make available to BSEE.

0.75 ............................ 7,512 meetings .......... 5,634 * 

[710(b); 738(p)] .......... Prepare a well-control 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.

0.5 .............................. 308 plans ................... 154 * 

[711(b), (c)] ................ Record in the daily 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.

1 ................................. 8,320 drills ................. 8,320 * 

[712(a), (b), (f)] .......... Notify BSEE of all rig movements on or off 

locations.

0.1 .............................. 20 notices .................. 2 * 

Rig movements reported 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.

0.2 .............................. 151 submittals ............ 30 * 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
21556 Federal Register / Vol. 80, No. 74 / Friday, April 17, 2015 / Proposed Rules 

BURDEN TABLE—Continued 

[Current regulations are regular font with an asterisk (*); Italic font show revision(s) of existing requirements; and bracketed text indicates new 

requirements] 

30 CFR 250 Current 

Revision NEW 

Reporting and recordkeeping requirement+ 

(BSEE-Approved Verification Organization = 

BAVO) 

Hour burden Average number of 

annual responses 

Annual burden hours 

(rounded) 

[712(c), (e)] ................ NEW: Notify District Manager if MODU or 

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.

[0.5] ............................ [25 notifications] ......... [13] 

[712(d)] ....................... NEW: Prior to resuming operations, report to 

District Manager any construction repairs 

or modifications that were made to the 

MODU or rig.

[2] ............................... [10 responses] ........... [20] 

[713] ........................... Submit MODU or lift boat information if being 

used for well operations with your APD/

APM.

Burden covered under 1014–0025 for APD; 

and 1014–0026 for APM 

0 

[713(a), (b)] ................ Collect and report additional information on a 

case-by-case basis if sufficient information 

is not available.

5 ................................. 30 reports ................... 150 * 

[713(b)] ....................... Reference to Exploration Plan, Development 

and Production Plan, and Development 

Operations Coordination Document (30 

CFR 550, Subpart B).

Burden covered under 1010–0151 0 

[713(c)(1)] .................. Submit 3rd party review of drilling unit according to 30 CFR 250, Subpart I.Burden covered under 1014–0011 0 

[713(c)(2); (417(c)(2))] Have a Contingency Plan that addresses design and operating limitations of MODU or 

lift boat.

Burden covered under 1014–0025 0 

[713(d) (417(d))] ......... Submit current certificate of inspection/compliance from USCG and classification; submit documentation of operational limitations by a classification societ.Burden covered under 1014–0025 0 

[714] ........................... NEW: Develop and implement dropped objects plan with supporting documentation/

information; any additional information required by the District Manager; make 

available to BSEE upon request.

[40] ............................. [40 plans] ................... [1,600] 

[715] NTL ................... GPS for MODUs ............................................ 0.25 ............................ 1 rig.

1—Notify BSEE with tracking/locator data 

access and supporting information; notify 

BSEE Hurricane Response Team as soon 

as operator is aware a rig has moved off 

location.

.................................... 1 notification 1 * 

2–Install and protect tracking/locator devices—(these are replacement GPS devices or new rigs).20 devices per year for replacement and/or new × $325.00 = $6,500 * 

3—Pay monthly tracking fee for GPS devices already placed on MODUs/rig..40 rigs × $50/month = ($600/year per 1 rig) = $24,000 * 

4—Rent GPS devices and pay monthly 

tracking fee per rig.

40 rigs @$1,800 per year = $72,000 * 

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 * 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 80, No. 74 / Friday, April 17, 2015 / Proposed Rules 21557 

BURDEN TABLE—Continued 

[Current regulations are regular font with an asterisk (*); Italic font show revision(s) of existing requirements; and bracketed text indicates new 

requirements] 

30 CFR 250 Current 

Revision NEW 

Reporting and recordkeeping requirement+ 

(BSEE-Approved Verification Organization = 

BAVO) 

Hour burden Average number of 

annual responses 

Annual burden hours 

(rounded) 

Well Operations 

[720(a)] ....................... NEW: Notify and obtain approval from the 

District Manager when interrupting operations before getting off the well.

[5] ............................... [150 notifications] ....... [750] 

[720(a)(2)] .................. Request approval to use alternate procedures/barriers.Burden covered under 1014–0022 0 

[720(b)] ....................... Submit with your APD or APM reasons for 

displacing kill-weight fluid with detailed 

step-by-step written procedures how to 

displace the fluids, shear pipe procedures, 

etc.

Burden covered under 1014–0025 for APD; 

and 1014–0026 for APM 

0 

[721(d), (f), (g)] .......... Submit to the District 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.

0.5 .............................. 88 requests ................ 44 * 

[721(g)(4)] .................. Submit test procedures and criteria for a 

successful test with APD/APM; if changes 

made to procedures, submit changes with 

revised APD or APM.

Burden covered under 1014–0025 for APD; 

and 1014–0026 for APM. 

0 

[721(g)(5)] .................. Document all your test results and make 

them available to BSEE upon request.

0.75 ............................ 1,340 results .............. 1,005 * 

[721(g)(6)] .................. Contact the 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.

1 ................................. 14 notifications ........... 14 * 

[721(g)(8); 744(a)] ...... Submit Form BSEE–0125, EOR .................... Burden covered under 1014–0018 0 

[722] ........................... Caliper, pressure 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).

3 ................................. 247 reports ................. 741 * 

[722(b)(3)] .................. [ Perform a pressure test after repairs made/

casing installed and report results.

[1] ............................... [300 results] ............... [300] 

[723(d)] ....................... Request exceptions prior to moving rig(s) or 

related equipment.

1.5 .............................. 845 requests .............. 1,268 * 

[724] ........................... NEW: Immediately transmit real-time monitoring data onshore during operations or in 

HPHT reservoirs; store and monitor by 

qualified personnel.

[12] ............................. [50 submittals] ............ [600] 

[724(b)] ....................... NEW: List designated location where realtime data will be stored and monitored in 

your APD or APM; make location and data 

accessible to BSEE upon request.

Burden covered under 1014–0025 for APD; 

and 1014–0026 for APM 

0 

2,534 responses ........ 3,072 hours * 

[500 responses] ......... [1,650 hours] 

Subtotal (G—Well 

Op.).

3,034 responses ........ 4,722 hours 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
21558 Federal Register / Vol. 80, No. 74 / Friday, April 17, 2015 / Proposed Rules 

BURDEN TABLE—Continued 

[Current regulations are regular font with an asterisk (*); Italic font show revision(s) of existing requirements; and bracketed text indicates new 

requirements] 

30 CFR 250 Current 

Revision NEW 

Reporting and recordkeeping requirement+ 

(BSEE-Approved Verification Organization = 

BAVO) 

Hour burden Average number of 

annual responses 

Annual burden hours 

(rounded) 

BOP System Requirements 

[730; 731; 732] ........... Submit BOP descriptions with your applicable APD or APM; third-party verification 

and supporting information/documentation.

Burden covered under 1014–0025 for APD; 

and 1014–0026 for APM 

0 

[730(a)(4)] .................. NEW: Maintain current 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.

[24] ............................. [10 requests] .............. [240] 

[730(c)(1)] .................. NEW: Provide written report to manufacturer 

within 30 days of identifying equipment 

failure.

[2] ............................... [30 reports] ................. [60] 

[730(c)(2)] .................. NEW: Initiate investigation and analysis within 60 days to determine cause of equipment failure; provide the manufacturer a 

copy of analysis report.

[5] ............................... [30 reports] ................. [150] 

[730(c)(3)] .................. NEW: Report the design change/modified 

procedures in writing to BSEE, OORP; 

within 30 days of manufacturer’s notification.

[5] ............................... [2 reports] ................... [10] 

[730(d)(2)] .................. NEW: Request for alternate to API Spec. Q1 

to BSEE, OORP.

[5] ............................... [1 response] ............... [5] 

[731] ........................... Resubmit BOP system component documentation in your APD or APM when information changes or moved off location from 

well.

Burden covered under 1014–0025 for APD; 

and 1014–0026 for APM. 

0 

[732(a)] ....................... NEW: Submit all relevant information to 

nominate a verification organization for 

BSEE approval.

[5] ............................... [5 submittals] .............. [25] 

[732(b)] ....................... NEW: Submit BAVO verification and all supporting documentation related to this section (such as, but not limited to sharing 

testing, pressure integrity testing, calculations, etc.).

[10] ............................. [150 Verifications] ...... [1,500] 

[732(c)] ....................... NEW: Submit 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.

[10] ............................. [10 wells] .................... [100] 

[732(d), (e)] ................ NEW: Submit Mechanical 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.

[10] ............................. [90 reports] ................. [900] 

[733(b)(2)] .................. NEW: Describe in your APD or APM your 

annulus monitoring plan.

Burden covered under 1014–0025 for APD; 

and 1014–0026 for APM 

0 

[734(a)(7)] .................. Demonstrate that any acoustic control system will function properly in proposed environment and conditions; submit any additional information requested.5 .................................

1 .................................

1 validation .................

10 submittals ..............

5 * 

10 

[734(a)(9); 738(n)] ...... Label all functions on all panels .................... 1.5 .............................. 33 panels ................... 50 * 

[734(a)(10)] ................ Develop written procedures for operating the 

BOP stack and LMRP and minimum 

knowledge requirements for personnel authorized to operate and maintain BOP 

components.

Burden covered under 1014–0018 0 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 80, No. 74 / Friday, April 17, 2015 / Proposed Rules 21559 

BURDEN TABLE—Continued 

[Current regulations are regular font with an asterisk (*); Italic font show revision(s) of existing requirements; and bracketed text indicates new 

requirements] 

30 CFR 250 Current 

Revision NEW 

Reporting and recordkeeping requirement+ 

(BSEE-Approved Verification Organization = 

BAVO) 

Hour burden Average number of 

annual responses 

Annual burden hours 

(rounded) 

[734(b), (c)] ................ Submit a revised APD/APM with BAVO [documenting repairs; before drilling out surface casing]; perform a new BOP test 

upon relatch, etc.; receive approval from 

the District Manager.

Burden covered under 1014–0025 for APD; 

and 1014–0026 for APM 

0 

[737(a)(3), (a)(4); 

(b)(2), (b)(3); (d)(2)- 

(4), (d)(12), (d)(13)].

In your APD: submit stump, initial, or 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.

Burden covered under 1014–0025 0 

[737(c); 746(a), (b), 

(c), (d)].

Record the time, date, 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.

7.75 ............................ 4,457 results .............. 34,542 * 

[737(d)(2), (d)(3), 

(d)(4) (d)(12);].

Notify District Manager at least 72 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.

0.25 ............................

5.5 ..............................

186 notifications .........

1,239 results ..............

47 * 

6,815 * 

[737(d)(13)] ................ Document all autoshear, EDS, and deadman 

on your subsea BOP systems function test 

results; make available to BSEE upon request.

0.5 ..............................

1 .................................

2,520 submittals .........

120 responses ...........

1,260 * 

120 

[737(e)] ....................... Provide 72 hour advance notice of location 

of shearing ram tests or inspections; allow 

BSEE access to witness testing, inspections, and information verification.

0.25 ............................ 136 notices ................ 34 * 

[738; 746(e)] .............. NEW/Revised: Requires District Manager 

Approval: 

[0.5] ............................ [25 requests] .............. [13] 

(a), (d); 746(e) Report problems, issues, 

leaks;.

[1] ............................... [25 requests] .............. [25] 

(b) Put well in a safe condition; ..................... [1] ............................... [25 requests] .............. [25] 

(b) Prior to resuming operations for new/repaired/reconfigured BOP.0.25 ............................ 200 requests .............. 50 * 

(g) Your well control places demands above 

its rating pressure; 

1 ................................. 15 requests ................ 15 

(j) Two barriers in place prior to BOP removal.[1] ............................... [1 request] .................. [1] 

[738(b), (i)] ................. NEW: Submit a report/verification from 

BAVO that BOP is fit for service if have to 

repair, replace, or reconfigure a BOP.

[0.5] ............................ [50 submittals] ............ [25] 

[738(f)] ........................ NEW: Notify the District Manager of BOP 

configuration changes.

[0.5] ............................ [15 submittals] ............ [8] 

[738(g)] ....................... NEW: Demonstrate your well-control procedures will not place demands above its 

rated working pressure.

[1] ............................... [15 submittals] ............ [15] 

[738(k)] ....................... NEW: Contact District Manager for approval 

prior to latching up the BOP stack or reestablishing power.

[1] ............................... [2 requests] ................ [2] 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
21560 Federal Register / Vol. 80, No. 74 / Friday, April 17, 2015 / Proposed Rules 

BURDEN TABLE—Continued 

[Current regulations are regular font with an asterisk (*); Italic font show revision(s) of existing requirements; and bracketed text indicates new 

requirements] 

30 CFR 250 Current 

Revision NEW 

Reporting and recordkeeping requirement+ 

(BSEE-Approved Verification Organization = 

BAVO) 

Hour burden Average number of 

annual responses 

Annual burden hours 

(rounded) 

[738(m)] ...................... NEW: Request approval in your APD or 

APM to utilize any other well-control equipment.

Burden covered under 1014–0025 for APD; 

and 1014–0026 for APM 

0 

[738(m)] ...................... NEW: Request approval 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.

[2] ............................... [10 requests] .............. [20] 

[738(n)] ....................... NEW: Include in your APD or APM which 

pipe/variable bore rams meet the criteria.

Burden covered under 1014–0025 for APD; 

and 1014–0026 for APM 

0 

[738(o)] ....................... NEW: Submit report to 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.

[1] ............................... [15 submittals] ............ [15] 

[739] ........................... Document BOP 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.

9.75 ............................ 350 records ................ 3,413 * 

[739(b)] ....................... NEW: Assemble a detailed report compiled 

by a BAVO documenting the once every 

5-year inspection, including any problems 

and corrections; make available to BSEE 

upon request.

[5] ............................... [21 reports] ................. [105] 

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 report and accurate 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.

25 min ........................

[1] ...............................

312 reports .................

[25 responses] ...........

130 * 

[25] 

[740; 741] ................... Retain drilling records for 90 days 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.

2.15 ............................

[1] ...............................

3,460 records .............

[25 responses] ...........

7,439 * 

[25] 

[742] NTL ................... Record and submit well logs and surveys run 

in the wellbore and/or charts of well logging operations.

3 ................................. 281 logs/surveys ........ 843 * 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 80, No. 74 / Friday, April 17, 2015 / Proposed Rules 21561 

BURDEN TABLE—Continued 

[Current regulations are regular font with an asterisk (*); Italic font show revision(s) of existing requirements; and bracketed text indicates new 

requirements] 

30 CFR 250 Current 

Revision NEW 

Reporting and recordkeeping requirement+ 

(BSEE-Approved Verification Organization = 

BAVO) 

Hour burden Average number of 

annual responses 

Annual burden hours 

(rounded) 

Record and submit directional and verticalwell surveys..1 ................................. 281 reports ................. 281 * 

Record and submit velocity profiles and surveys..1 ................................. 55 reports ................... 55 * 

Record and submit core analyses. ................ 1 ................................. 150 analyses .............. 150 * 

[743(a), (c)] ................ In the GOM OCS Region, 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.

Burden covered under 1014–0018 0 

[743(b), (c)] ................ In the Pacific and 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.

Burden covered under 1014–0018 0 

[744] ........................... Submit form BSEE–0125, EOR ..................... Burden covered under 1014–0018 0 

[745]; NTL .................. Submit copies of well records; paleontological interpretations; service company reports; and other reports or records of operations to BSEE as requested.1.5 .............................. 308 submissions ........ 462 * 

[746] ........................... Record the time, date, and results of all casing and liner presser tests.2 ................................. 4,160 results .............. 8,320 * 

[746(f)] ........................ Retain all records 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.

1.5 .............................. 1,563 records ............. 2,345 * 

10,570 responses ...... 20,025 hours * 

[50 responses] ........... [50 hours] 

Subtotal (G—Rec. 

& Rpt. Req.).

......................................................................... .................................... 10,620 responses ...... 20,075 hours. 

Subpart P 

1612 ........................... Request exception from 30 CFR 250.711 requirements.Burden covered under 1014–0006 0 

Subpart Q 

1704(g), [(h)] .............. Submit Forms BSEE–0124 and BSEE–0125; 

include all supporting documentation/information.

Burden covered under 1014–0018 for BSEE– 

0125; and 1014–0026 for BSEE–0124 

0 

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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
21562 Federal Register / Vol. 80, No. 74 / Friday, April 17, 2015 / Proposed Rules 

BURDEN TABLE—Continued 

[Current regulations are regular font with an asterisk (*); Italic font show revision(s) of existing requirements; and bracketed text indicates new 

requirements] 

30 CFR 250 Current 

Revision NEW 

Reporting and recordkeeping requirement+ 

(BSEE-Approved Verification Organization = 

BAVO) 

Hour burden Average number of 

annual responses 

Annual burden hours 

(rounded) 

$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 § 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 

■ 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. 

■ 2. In § 250.102, revise paragraphs 

(b)(1) and (b)(11) through (13) and add 

paragraph (b)(19) to read as follows: 

§ 250.102 What does this part do? 

* * * * * 

(b) * * * 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 80, No. 74 / Friday, April 17, 2015 / Proposed Rules 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. 

■ 3. Amend § 250.107 by: 

■ a. Removing the word ‘‘and’’ from the 

end of paragraph (a)(1); 

■ b. Removing the period from the end 

of paragraph (a)(2) and adding in its 

place a semicolon; and 

■ c. Adding paragraphs (a)(3) and (4) 

and (e). 

The additions read as follows: 

§ 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. 

■ 4. In § 250.125, revise the table in 

paragraph (a) to read as follows: 

§ 250.125 Service fees. 

(a) * * * 

Service—processing of the following: Fee amount 30 CFR citation 

(1) Suspension of Operations/Suspension of Production 

(SOO/SOP) Request.

$2,123 ............................................................................. § 250.171(e). 

(2) Deepwater Operations Plan (DWOP) ......................... $3,599 ............................................................................. § 250.292(q). 

(3) Application for Permit to Drill (APD); Form BSEE– 

0123.

$2,113 for initial applications only; no fee for revisions § 250.410(d); § 250.513(b); 

§ 250.1617(a). 

(4) Application for Permit to Modify (APM); Form BSEE– 

0124.

$125 ................................................................................ § 250.465(b); § 250.513(b); 

§ 250.613(b); 

§ 250.1618(a); 

§ 250.1704(g). 

(5) New Facility Production Safety System Application 

for facility with more than 125 components.

$5,426 A component is a piece of equipment or ancillary system that is protected by one or more of the 

safety devices required by API RP 14C (as incorporated by reference in § 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.

§ 250.802(e). 

(6) New Facility Production Safety System Application 

for facility with 25–125 components.

$1,314 Additional fee of $8,967 will be charged if BSEE 

deems it necessary to visit a facility offshore, and 

$5,141 to visit a facility in a shipyard.

§ 250.802(e). 

(7) New Facility Production Safety System Application 

for facility with fewer than 25 components.

$652 ................................................................................ § 250.802(e). 

(8) Production Safety System Application—Modification 

with more than 125 components reviewed.

$605 ................................................................................ § 250.802(e). 

(9) Production Safety System Application—Modification 

with 25–125 components reviewed.

$217 ................................................................................ § 250.802(e). 

(10) Production Safety System Application—Modification 

with fewer than 25 components reviewed.

$92 .................................................................................. § 250.802(e). 

(11) Platform Application—Installation—Under the Platform Verification Program.$22,734 ........................................................................... § 250.905(l). 

(12) Platform Application—Installation—Fixed Structure 

Under the Platform Approval Program.

$3,256 ............................................................................. § 250.905(l). 

(13) Platform Application—Installation—Caisson/Well 

Protector.

$1,657 ............................................................................. § 250.905(l) 

(14) Platform Application—Modification/Repair ................ $3,884 ............................................................................. § 250.905(l). 

(15) New Pipeline Application (Lease Term) .................... $3,541 ............................................................................. § 250.1000(b). 

(16) Pipeline Application—Modification (Lease Term) ..... $2,056 ............................................................................. § 250.1000(b). 

(17) Pipeline Application—Modification (ROW) ................ $4,169 ............................................................................. § 250.1000(b). 

(18) Pipeline Repair Notification ....................................... $388 ................................................................................ § 250.1008(e). 

(19) Pipeline Right-of-Way (ROW) Grant Application ...... $2,771 ............................................................................. § 250.1015(a). 

(20) Pipeline Conversion of Lease Term to ROW ........... $236 ................................................................................ § 250.1015(a). 

(21) Pipeline ROW Assignment ........................................ $201 ................................................................................ § 250.1018(b). 


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Service—processing of the following: Fee amount 30 CFR citation 

(22) 500 Feet From Lease/Unit Line Production Request $3,892 ............................................................................. § 250.1156(a). 

(23) Gas Cap Production Request ................................... $4,953 ............................................................................. § 250.1157. 

(24) Downhole Commingling Request .............................. $5,779 ............................................................................. § 250.1158(a). 

(25) Complex Surface Commingling and Measurement 

Application.

$4,056 ............................................................................. § 250.1202(a); 

§ 250.1203(b); 

§ 250.1204(a). 

(26) Simple Surface Commingling and Measurement Application.$1,371 ............................................................................. § 250.1202(a); 

§ 250.1203(b); 

§ 250.1204(a). 

(27) Voluntary Unitization Proposal or Unit Expansion .... $12,619 ........................................................................... § 250.1303(d). 

(28) Unitization Revision ................................................... $896 ................................................................................ § 250.1303(d). 

(29) Application to Remove a Platform or Other Facility $4,684 ............................................................................. § 250.1727. 

(30) Application to Decommission a Pipeline (Lease 

Term).

$1,142 ............................................................................. § 250.1751(a) or 

§ 250.1752(a). 

(31) Application to Decommission a Pipeline (ROW) ...... $2,170 ............................................................................. § 250.1751(a) or 

§ 250.1752(a). 

■ 5. Amend § 250.198 by revising 

paragraphs (h)(51), (63), (68), and (70) 

and adding paragraphs (h)(89) through 

(94) to read as follows: 

§ 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 §§ 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 §§ 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 §§ 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 §§ 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 §§ 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 § 250.730; 

(91) ANSI/API Spec. 16C, 

Specification for Choke and Kill 

Systems, First Edition, January 1993; 

incorporated by reference at § 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 

§ 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 systemsPart 4: Subsea wellhead and tree 

equipment; incorporated by reference at 

§ 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 § 250.734. 

* * * * * 

■ 6. In § 250.199, revise paragraph (e) to 

read as follows: 

§ 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 

(OMB Control No.) BSEE collects this information and uses it to: 

(1) Subpart A, General (1014–0022), including Forms BSEE–0132, 

Evacuation Statistics; BSEE–0143, Facility/Equipment Damage Report; BSEE–1832, Notification of Incidents of Noncompliance.

(i) Determine that activities on the OCS comply with statutory and regulatory requirements; are safe and protect the environment; and 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 (1014–0024) ................................. Evaluate Deepwater Operations Plans for compliance with statutory 

and regulatory requirements. 


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30 CFR subpart, title and/or BSEE Form 

(OMB Control No.) BSEE collects this information and uses it to: 

(3) Subpart C, Pollution Prevention and Control (1014–0023) ................ (i) Evaluate measures to 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 Operations (1014–0018), including Forms BSEE–0125, End of Operations Report; BSEE–0133, 

Well Activity Report; and BSEE–0133S, Open Hole Data Report.

(i) Evaluate the equipment and procedures to be used in drilling operations on the OCS. 

(ii) Ensure that drilling operations meet statutory and regulatory requirements. 

(5) Subpart E, Oil and Gas Well-Completion Operations (1014–0004) .. (i) Evaluate the equipment and procedures to be used in well-completion operations on the OCS. 

(ii) Ensure that well-completion operations meet statutory and regulatory requirements. 

(6) Subpart F, Oil and Gas Well Workover Operations (1014–0001) ..... (i) Evaluate the equipment and procedures to be used during wellworkover operations on the OCS. 

(ii) Ensure that well-workover operations meet statutory and regulatory 

requirements. 

(7) Subpart G, Blowout Preventer Systems (1014-xxxx), including Form 

BSEE–0144, Rig Movement Notification Report.

(i) Evaluate the equipment and procedures to be used during well drilling, completion, workover, and abandonment operations on the 

OCS. 

(ii) Ensure that well operations meet statutory and regulatory requirements. 

(8) Subpart H, Oil and Gas Production Safety Systems (1014–0003) .... (i) Evaluate the equipment and 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 (1014–0011) .............................. (i) Evaluate the design, 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 Rights-of-Way (1014–0016), including Form BSEE–0149, Assignment of Federal OCS Pipeline 

Right-of-Way Grant.

(i) Evaluate the design, installation, and operation of pipelines on the 

OCS. 

(ii) Ensure that pipeline operations meet statutory and regulatory requirements. 

(11) Subpart K, Oil and Gas Production Rates (1014–0019), including 

Forms BSEE–0126, Well Potential Test Report and BSEE–0128, 

Semiannual Well Test Report.

(i) Evaluate production rates for hydrocarbons produced on the OCS. 

(ii) Ensure economic maximization of ultimate hydrocarbon recovery. 

(12) Subpart L, Oil and Gas Production Measurement, Surface Commingling, and Security (1014–0002).(i) Evaluate the measurement of production, commingling of 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 Production Safety Training (1014– 

0008).

(i) Evaluate training program 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 (1014–0006) ................................... (i) Evaluate sulphur 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 Activities (1014–0010) ...................... Ensure that decommissioning activities, site clearance, and platform or 

pipeline removal are properly performed to meet statutory and regulatory requirements and do not conflict with other users of the OCS. 

(18) Subpart S, Safety and Environmental Management Systems 

(1014–0017), including Form BSEE–0131, Performance Measures 

Data.

(i) Evaluate operators’ policies and procedures to assure safety and 

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 (APD, Revised APD), Form BSEE– 

0123; and Supplemental APD Information Sheet, Form BSEE– 

0123S, and all supporting documentation (1014–0025).

(i) Evaluate and approve the adequacy of the equipment, materials, 

and/or procedures that the lessee or operator plans to use during 

drilling. 

(ii) Ensure that applicable OCS operations meet statutory and regulatory requirements. 


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30 CFR subpart, title and/or BSEE Form 

(OMB Control No.) BSEE collects this information and uses it to: 

(20) Application for Permit to Modify (APM), Form BSEE–0124, and 

supporting documentation (1014–0026).

(i) Evaluate and approve the adequacy of the equipment, 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. 

■ 7. Amend § 250.292 by: 

■ a. Removing the word ‘‘and’’ from the 

end of paragraph (o); 

■ b. Redesignating paragraph (p) as (q); 

and 

■ c. Adding new paragraph (p). 

The addition reads as follows: 

§ 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 § 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 

* * * * * 

■ 8. Revise § 250.400 to read as follows: 

§ 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. 

§ §§ 250.401 through 250.403 [Removed 

and Reserved] 

■ 9a. Remove and reserve §§ 250.401 

through 250.403, and 250.406. 

§ § 250.406 [Removed and Reserved] 

■ 9b. Remove and reserve § 250.406. 

■ 10. Revise § 250.411 to read as 

follows: 

§ 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: 

Information that you 

must include with an APD 

Where 

to find 

a description 

(a) Plat that shows locations of 

the proposed well .................. § 250.412 

(b) Design criteria used for the 

proposed well ........................ § 250.413 

(c) Drilling prognosis ................. § 250.414 

(d) Casing and cementing programs .................................... § 250.415 

(e) Diverter systems descriptions ....................................... § 250.416 

(f) BOP system descriptions ..... § 250.731 

(g) Requirements for using an 

MODU, and ........................... § 250.713 

(h) Additional information ......... § 250.418 

■ 11. In § 250.413, revise paragraph (g) 

to read as follows: 

§ 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; 

* * * * * 

■ 12. Amend § 250.414 by revising 

paragraphs (c), (h), and (i) and adding 

paragraphs (j) and (k) to read as follows: 

§ 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 § 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. 

■ 13. In § 250.415, revise paragraph (a) 

to read as follows: 

§ 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 


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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); 

* * * * * 

■ 14. Revise § 250.416 to read as 

follows: 

§ 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. 

§ 250.417 [Removed and Reserved] 

■ 15. Remove and reserve § 250.417. 

■ 16. In § 250.418, revise paragraph (g) 

to read as follows: 

§ 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; 

* * * * * 

■ 17. Amend § 250.420 by: 

■ a. Revising the introductory text and 

paragraph (a)(5); 

■ b. Redesignating paragraph (a)(6) as 

(a)(7); 

■ c. Adding new paragraph (a)(6) and 

paragraph (b)(4); and 

■ d. Revising paragraph (c). 

The revisions and additions read as 

follows: 

§ 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. 

■ 18. In § 250.421, revise paragraphs (b) 

and (f) to read as follows: 

§ 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 select setting depths based on relevant 

engineering and geologic factors. These factors include the 

presence or absence of hydrocarbons, potential hazards, 

and water depths.

Set casing immediately before drilling into formations known 

to contain oil or gas. If you encounter oil or gas or unexpected formation pressure before the planned casing point, 

you must set casing immediately and set it above the encountered zone.

Use enough cement to fill the calculated annular space back 

to the mudline. 

Verify annular fill by observing cement returns. If you cannot 

observe cement returns, use additional cement to ensure 

fill-back to the mudline. 

For drilling on an artificial island or when using a well cellar, 

you must discuss the cement fill level with the District Manager. 

* * * * * * * 

(f) Liners ........... If you use a liner as surface casing, you must set the top of 

the liner at least 200 feet above the previous casing/liner 

shoe.

If you use a liner as an intermediate string below a surface 

string or production 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 ..........................

Same as cementing requirements for specific casing types. 

For example, a liner used as intermediate casing must be 

cemented according to the cementing requirements for intermediate casing. 

■ 19. Revise § 250.423 to read as 

follows: 

§ 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. 


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§§ 250.424 through 250.426 [Removed and 

Reserved] 

■ 20. Remove and reserve §§ 250.424 

through 250.426. 

■ 21. In § 250.427, revise paragraph (b) 

to read as follows: 

§ 250.427 What are the requirements for 

pressure integrity tests? 

* * * * * 

(b) While drilling, you must maintain 

the safe drilling margins identified in 

§ 250.414. When you cannot maintain 

the safe margins, you must suspend 

drilling operations and remedy the 

situation. 

■ 22. In § 250.428, revise paragraphs (b) 

through (d) and add paragraph (k) to 

read as follows: 

§ 250.428 What must I do in certain 

cementing and casing situations? 

* * * * * 

If you encounter the following situation: Then you must . . . 

*******

(b) Need to change casing setting depths or hole interval 

drilling depth (for a BHA with an under-reamer, this 

means bit depth) more than 100 feet true vertical depth 

(TVD) from the approved APD due to conditions encountered during drilling operations.

Submit those changes to the District Manager for approval and include a certification 

by a professional engineer (PE) that he or she reviewed and approved the proposed changes. 

(c) Have indication of inadequate cement job (such as 

lost returns, no cement returns to mudline or expected 

height, cement channeling, or failure of equipment).

(1) Locate the top of cement by: (i) Running a temperature survey; (ii) Running a cement evaluation log; or (iii) Using a combination of these techniques. 

(2) Determine if your cement job is inadequate. If your cement job is determined to 

be inadequate, refer to paragraph (d) of this section. 

(3) If your cement job is determined to be adequate, report the results to the District 

Manager in your submitted WAR. 

(d) Inadequate cement job ................................................. Take remedial actions. The District Manager must review and approve all remedial 

actions before you may take them, unless immediate actions must be taken to ensure the safety of the crew or to prevent a well-control event. If you complete any 

immediate action to ensure the safety of the crew or to prevent a well-control 

event, submit a description of the action to the District Manager when that action is 

complete. Any changes to the well program will require submittal of a certification 

by a professional engineer (PE) certifying that he or she reviewed and approved 

the proposed changes, and must meet any other requirements of the District Manager. 

*******

(k) Plan to use a valve on the drive pipe during cementing operations for the conductor casing, surface casing, 

or liner.

Include a description of the plan in your APD. Your description must include a schematic of the valve and height above the water line. The valve must be remotely 

operated and full opening with visual observation while taking returns. The person 

in charge of observing returns must be in communication with the drill floor. You 

must record in your daily report and in the WAR if cement returns were observed. 

If cement returns are not observed, you must contact the District Manager and obtain approval of proposed plans to locate the top of cement before continuing with 

operations. 

§ § 250.440 through 250.451 [Removed 

and Reserved] 

■ 23. Remove the undesignated center 

heading ‘‘Blowout Preventer (BOP) 

System Requirements’’ and remove and 

reserve §§ 250.440 through 250.451. 

§ 250.456 [Amended] 

■ 24. Amend § 250.456: 

■ a. In paragraph (i), by adding the word 

‘‘and’’ after the semi-colon 

■ b. By removing paragraph (j); and 

■ c. By redesignating paragraph (k) as 

(j). 

■ 25. Revise § 250.462 to read as 

follows. 

§ 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, 


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(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: 

Equipment Requirements, you must: Additional information 

(1) Capping stacks ............... (i) Function test all pressure holding critical components 

on a quarterly frequency (not to exceed 104 days between tests).

Pressure holding critical components are those components that will experience wellbore pressure during a 

shut-in after being functioned. 

(ii) Pressure test pressure holding critical components 

on a bi-annual basis, but not later than 210 days 

from the last pressure test. All pressure testing must 

be witnessed by BSEE and a BSEE- approved 

verification organization.

Pressure holding critical components are those components that will experience wellbore pressure during a 

shut-in. These components include, but are not limited to: All blind rams, wellhead connectors, and outlet valves. 

(iii) Notify BSEE at least 21 days prior to commencing 

any pressure testing.

(2) Production Safety Systems used for flow and 

capture operations.

(i) Meet or exceed the requirements 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 unique to containment operations 

available for inspection at all times.

Subsea utility equipment includes, but is not limited to: 

Hydraulic power sources, debris removal, hydrate 

control equipment, and dispersant injection equipment. 

■ 26. In § 250.465, revise paragraph 

(b)(3) to read as follows: 

§ 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 § 250.744. 

§§ 250.466 through 250.469 [Removed and 

Reserved] 

■ 27. Remove and reserve §§ 250.466 

through 250.469. 

■ 28. Revise § 250.500 to read as 

follows: 

§ 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. 

§§ 250.502 and 250.506 [Removed and 

Reserved] 

■ 29. Remove and reserve §§ 250.502 

and 250.506. 

§ 250.514 [Amended] 

■ 30. In § 250.514, remove paragraph 

(d). 

§§ 250.515 through 250.517 [Removed and 

Reserved] 

■ 31. Remove and reserve §§ 250.515 

through 250.517. 

■ 32. Amend § 250.518 by: 

■ a. Removing paragraph (b); 

■ b. Redesignating paragraphs (c) 

through (e) as paragraphs (b) through 

(d); and 

■ c. Adding new paragraph (e) and 

paragraph (f). 

The additions read as follows: 

§ 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 § 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. 

■ 33. Revise § 250.600 to read as 

follows: 

§ 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. 

§ 250.602 [Removed and Reserved] 

■ 34a. Remove and reserve § 250.602. 

§ 250.606 [Removed and Reserved] 

■ 34b. Remove and reserve § 250.606. 

§ 250.614 [Amended] 

■ 35. In § 250.614, remove paragraph 

(d). 

§ 250.615 [Removed and Reserved] 

■ 36. Remove and reserve § 250.615. 

■ 37. Amend § 250.616 by: 

■ a. Revising the section heading; 

■ b. Removing paragraphs (a) through 

(e); and 

■ c. Redesignating paragraphs (f) 

through (h) as paragraphs (a) through 

(c). 

The revision reads as follows: 


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§ 250.616 Coiled tubing and snubbing 

operations. 

* * * * * 

§§ 250.617 and 250.618 [Removed and 

Reserved] 

■ 38. Remove and reserve §§ 250.617 

and 250.618. 

■ 39. Amend § 250.619 by: 

■ a. Removing paragraph (b); 

■ b. Redesignating paragraphs (c) 

through (e) as paragraphs (b) through 

(d); and 

■ c. Adding new paragraph (e) and 

paragraph (f). 

The additions read as follows; 

§ 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 § 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. 

■ 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 wellcontrol 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 

§ 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. 

§ 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 

§ 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 § 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 § 250.141 of this part. 

§ 250.702 May I obtain departures from 

these requirements? 

You may apply for a departure from 

these requirements as described in 

§ 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 § 250.414(h)) or your 

APM. 

§ 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 

§ 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 


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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. 

§ 250.711 What are the requirements for 

well-control drills? 

You must conduct a weekly wellcontrol 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 § 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. 

§ 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. 

§ 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 thirdparty review of your MODU or lift boat 

similar to the process outlined in 

§§ 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 


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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. 

§ 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. 

§ 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 realtime access. 

Well Operations 

§ 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 § 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 § 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 § 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. 

§ 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 wellheads. ........................................... 250 psi. 

(3) Surface, Intermediate, and Production, .............................................. 70 percent of its minimum 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. 


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(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 recement, 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 § 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). 

§ 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 

§ 250.721. 

§ 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 jackedup 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 pumpthrough-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. 

§ 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 


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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 

§§ 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 

§ 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 § 250.198) and the requirements of 

§§ 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 

§ 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 

§ 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 § 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. 

§ 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 system and system components, (1) Pressure ratings of BOP 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; 


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You must submit: Including: 

(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 organization, Verification that: 

(1) Test data clearly demonstrates the shear ram(s) will shear the drill 

pipe at the water depth as required in § 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-approved verification organization, if you use a subsea BOP, a BOP in an HPHT environment as 

defined in § 250.807, or a surface BOP on a floating facility, 

Verification that: 

(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, descriptions of autoshear, 

deadman, and emergency disconnect sequence (EDS) systems, 

A listing of the functions with their sequences and timing. 

(f) Certification stating that the Mechanical Integrity Assessment Report 

required in § 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 § 250.807, or a surface BOP on a floating facility. 

§ 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; 


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You must submit verification and documentation related to: That: 

(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 

§ 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 § 250.807(b), 

you must submit verification by a BSEEapproved 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 individual components and the overall system have been proven in a testing process that demonstrates 

the performance and reliability of the equipment in a manner that is 

repeatable and reproducible, 

(i) Identification of all reasonable potential modes of failure, and 

(ii) Evaluation of the design verification tests. The design verification 

tests must assess 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, manufacture, and assembly of individual components and the overall system uses recognized engineering practices and quality control and assurance mechanisms. For the quality control and assurance mechanisms, complete material 

and quality controls over all contractors, subcontractors, distributors, 

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 § 250.807, or 

a surface BOP on a floating facility. This 

report must be completed by a BSEEapproved 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. 


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(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. 

§ 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 

§ 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 § 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 § 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, fullopening 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 BSEEapproved verification organization 

stating that they reviewed the repairs, 

and that the BOP is fit for service; and 

(2) Receive approval from the District 

Manager. 

§ 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-controlled, hydraulically operated BOPs; You must have at least one annular BOP, two BOPs equipped 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. 


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When operating with a subsea BOP system, you must: Additional requirements 

(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 located subsea, to provide fast closure of the BOP components and to operate all critical functions in 

case of a loss of the power fluid connection to the surface; 

The accumulator capacity must: 

(i) Function each required shear ram, choke and kill side outlet valves, 

one pipe ram, and disconnect the LMRP. 

(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 with remotely operated vehicle 

(ROV) intervention capability; 

The ROV must be capable of performing critical functions, 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 § 250.198). 

(5) Maintain an ROV and have a trained ROV crew on each rig unit on 

a continuous basis once BOP deployment has been initiated from 

the rig until recovered to the surface. The crew must examine all 

ROV related well-control equipment (both surface and subsea) to ensure that it is properly maintained and capable of shutting in the well 

during emergency operations; 

The crew must be trained in the operation of the ROV. The training 

must include simulator training on stabbing into an ROV intervention 

panel on a subsea BOP stack. The ROV crew must be in communication with designated rig personnel who are knowledgeable about 

the BOP’s capabilities. 

(6) Provide autoshear, deadman, and EDS systems for dynamically positioned rigs; provide autoshear and deadman systems for moored 

rigs; 

(i) Autoshear system means a safety system that is designed to automatically shut-in the wellbore in the event of a disconnect of the 

LMRP. This is considered a rapid discharge system. 

(ii) Deadman system means a safety system that is designed to automatically shut-in the wellbore in the event of a simultaneous absence 

of hydraulic supply and signal transmission capacity in both subsea 

control pods. This is considered a rapid discharge system. 

(iii) Emergency Disconnect Sequence (EDS) system means a safety 

system that is designed to be manually activated to shut-in the 

wellbore and disconnect the LMRP in the event of an emergency situation. This is considered a rapid discharge system. 

(iv) Each emergency function must close at a minimum, two shear 

rams in sequence and be capable of performing 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 control system will function in the 

proposed environment and conditions; 

If you choose to install an acoustic control system in addition to the 

autoshear, deadman, and EDS requirements, you must demonstrate 

to the District Manager, as part of the information submitted under 

§ 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 barrier(s) on BOP control panels to 

prevent accidental disconnect functions; 

Incorporate enable buttons on control panels to ensure two-handed operation for all critical functions. 

(9) Clearly label all control panels for the subsea BOP system; Label other BOP control panels such as hydraulic control panel.

(10) Develop and use a management system for operating the BOP 

system, including the prevention of accidental or unplanned disconnects of the system; 

The management system must include 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. 

(11) Establish minimum requirements for personnel authorized to operate critical BOP equipment; Personnel must have: 

(i) Training in deepwater well-control theory and practice according to 

the requirements of Subpart O; and 

(ii) A comprehensive knowledge of BOP hardware and control systems. 


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When operating with a subsea BOP system, you must: Additional requirements 

(12) Before removing the marine riser, displace the fluid in the riser 

with seawater; 

You must maintain sufficient hydrostatic pressure or take other suitable 

precautions to compensate for the reduction in pressure and to 

maintain a safe and controlled well condition. You must follow the requirements of § 250.720(b). 

(13) Install the BOP stack in a well cellar when in an ice-scour area; Your well cellar must be deep enough to ensure that the top of the 

stack is below the deepest probable ice-scour depth. 

(14) Install at least two side outlets for a choke line and two side outlets for a kill line; (i) If your stack does not have side outlets, you must install a drilling 

spool with side outlets. 

(ii) Each side outlet must have two full-bore, full-opening valves. 

(iii) The valves must hold pressure from both directions and must be 

remote-controlled. 

(iv) You must install a side outlet below 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 valves for the annular preventer; .. (i) The valves must hold 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 following mechanisms and capabilities: (i) A mechanism coupled with 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 BSEEapproved verification organization 

documenting the repairs and that the 

BOP is fit for service; 

(2) Perform a new BOP test in 

accordance with §§ 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. 

§ 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 ramtype BOPs; and 

(h) A wellhead assembly with a rated 

working pressure that exceeds the 

maximum anticipated wellhead 

pressure. 

§ 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 


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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 remotecontrolled kelly valves, drill-string 

safety valves, and comparable-type 

valves (i.e., kelly-type valve in a topdrive 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. 

§ 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 blindshear 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. 

You must conduct a . . . According to the following 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 ram-type BOPs, ram-type BOPs, 

the choke manifold, outside of all choke and kill side outlet valves 

(and annular gas bleed valves for subsea BOP), inside of all choke 

and kill side outlet valves below uppermost ram, and other BOP 

components.

The high-pressure test must equal the rated working pressure of the 

equipment or be 500 psi 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. 

(3) High-pressure test for annular-type BOPs, inside of choke or kill 

valves (and annular gas bleed valves for subsea BOP) above the uppermost ram BOP.

The high pressure test must equal 70 percent of the rated working 

pressure of the equipment or be 500 psi 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 API Standard 53 (as incorporated in § 250.198). If there is a conflict between API Standard 53 testing requirements and 

this section, you must follow the requirements of this section. 

(2) Use water to test a surface BOP system. .......................................... (i) You must submit test 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 before installation. ....................... (i) You must use water to conduct this test. You may use drilling fluids 

to conduct subsequent tests of a subsea BOP system. 


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You must . . . Additional requirements . . . 

(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 stations and pods. ........................... (i) For two complete BOP 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 of all ROV intervention functions 

on your subsea BOP. 

(i) Each ROV must be fully compatible with the BOP stack 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, and EDS systems separately 

on your subsea BOP stack during the stump test. The District Manager may require additional testing of the emergency systems. You 

must also test the deadman system and verify closure of the shearing rams during the initial test on the seafloor. 

(i) You must submit test procedures with your APD or APM for District 

Manager approval. The procedures for these function tests must include the schematics of the actual controls and circuitry of the system that will be 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. 


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You must . . . Additional requirements . . . 

(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. 

§ 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 required pressure during a test; Correct the problem and retest 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 § 250.746. 

(b) Need to repair, replace, or reconfigure a surface or subsea BOP 

system; 

(1) First place the well in a safe, controlled condition as 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 well-control problems such as 

lost circulation, formation fluid influx, or stuck pipe;.

Record the reason for postponing the test in the daily report and conduct the required BOP test on the first trip out of the hole. 

(d) BOP control station or pod that does not function properly; .............. Suspend operations until that 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 string; ................................................ Install two or more sets of 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 casing shear rams in a surface BOP 

stack;.

Test the ram bonnets before running casing to the rated 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 rated working pressure less 

than the anticipated surface pressure;.

Demonstrate that your well-control procedures or the 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 an ice-scour area; .................. Install the BOP stack in a well 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 or casing is sheared; ............... Retrieve, physically inspect, 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 autoshear activation, if there is a possibility of the blind-shear ram opening immediately upon re-establishing power to the BOP stack; Place the blind-shear ram opening function in the block position prior to 

re-establishing power to the 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. 


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If you encounter the following situation: Then you must . . . 

(m) Plan to utilize any other well-control equipment (e.g., but not limited 

to, subsea isolation device, subsea accumulator module, or gas handler) that is in addition to the equipment required in this subpart; 

Contact the District Manager and request approval in your APD or 

APM. Your request must include a report from a BSEE-approved 

verification 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 that have no current utility or 

well-control purposes; 

Indicate in your APD or APM which pipe/variable bore rams 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 for well control in your BOP system that are in addition to the required components of this subpart 

(e.g., pipe/variable bore rams, shear rams, annular preventers, gas 

bleed lines, and choke/kill side outlets or lines); 

Comply with all testing, maintenance, and inspection requirements in 

this subpart that are applicable to those well-control components. 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. 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 assembly, including heavy-weight 

pipe or collars, and bottom-hole tools across the BOP for tripping or 

any other operations. 

Ensure that the well has been stable for a minimum of 30 minutes prior 

to positioning the bottom hole assembly across the BOP. You must 

have, as part of your well-control plan required by § 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. 

§ 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 § 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 

§ 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 § 250.741 at a 

location of your choice, except as 

required in § 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. 

§ 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, diverter tests, BOP tests, and realtime monitoring data; 2 years after the completion of operations. 


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You must keep records relating to . . . Until . . . 

(c) Completion of a well or of any workover activity that materially alters the completion configuration or affects a hydrocarbon-bearing 

zone. 

You permanently plug and abandon the well or until you assign the 

lease and forward the records to the assignee. 

§ 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. 

§ 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. 

§ 250.744 What are the end of operation 

reporting requirements? 

(a) Within 30 days after completing 

operations, except routine operations as 

defined in § 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 § 250.186(b). 

§ 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 

§ 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. 

§ 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 § 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 


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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. 

■ 41. Revise § 250.1612 to read as 

follows: 

§ 250.1612 Well-control drills. 

Well-control drills must be conducted 

for each drilling crew in accordance 

with the requirements set forth in 

§ 250.711 of this part or as approved by 

the District Manager. 

■ 42. Amend § 250.1703 by: 

■ a. Revising paragraphs (b) and (e); 

■ b. Redesignating paragraph (f) as 

paragraph (g); and 

■ c. Adding a new paragraph (f). 

The revisions and addition read as 

follows: 

§ 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 § 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 

* * * * * 

■ 43. Amend § 250.1704 by revising 

paragraph (g) and adding paragraph (h) 

to read as follows: 

§ 250.1704 When must I submit 

decommissioning applications and reports? 

* * * * * 

Decommissioning applications and reports When to submit Instructions 

*******

(g) Form BSEE–0124, Application for Permit to 

Modify (APM). The submission of your APM 

must be accompanied by payment of the 

service fee listed in § 250.125; 

(1) Before you temporarily abandon or permanently plug a well or zone, (i) Include information required under 

§§ 250.1712 and 250.1721. 

(ii) When using a BOP for abandonment operations, include information required under 

§ 250.731. 

(2) Before you install a subsea protective device, Refer to § 250.1722(a). 

(3) Before you remove any casing stub or mud 

line suspension equipment and any subsea 

protective device, 

Refer to § 250.1723. 

(h) Form BSEE–0125, End of Operations Report (EOR); (1) Within 30 days after you complete a protective device trawl test, Include information required under 

§ 250.1722(d). 

(2) Within 30 days after you complete site 

clearance verification activities, 

Include information required under 

§ 250.1743(a). 

§ 250.1705 [Removed and Reserved] 

■ 44. Remove and reserve § 250.1705. 

■ 45. Amend § 250.1706 by: 

■ a. Revising the section heading; 

■ b. Removing paragraphs (a) through 

(e); and 

■ c. Redesignating paragraph (f) through 

(h) as paragraphs (a) through (c). The 

revision reads as follows: 

§ 250.1706 Coiled tubing and snubbing 

operations. 

* * * * * 

§§ 250.1707 through 250.1709 [Removed 

and Reserved] 

■ 46. Remove and reserve §§ 250.1707 

through 250.1709. 

■ 47. In § 250.1715, revise paragraph 

(a)(3)(iii)(B) to read as follows: 

§ 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; 

* * * * * 

§ 250.1717 [Removed and Reserved] 

■ 48. Remove and reserve § 250.1717. 

§ 250.1721 [Amended] 

■ 49. Amend § 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 


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