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

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 well-control best practices to advance safety and protection of the environment.

This proposed rulemaking would:

(1) Incorporate the following industry standards:

—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-and-Guidance/index.aspx.

The BSEE regulatory program regulates a wide range of facilities and activities, including drilling, completion, workover, production, pipeline, and decommissioning operations. Drilling, completion, and workover operations are types of well operations offshore operators perform throughout the OCS from fixed and floating facilities. These well operations are the primary topic of this proposed rulemaking.

Ensuring the integrity of the wellbore and maintaining control over the pressure and fluids during well operations are critical aspects of protecting worker safety and the environment. The investigations that followed the

Deepwater Horizon

incident documented gaps or deficiencies in the OCS regulatory programs and made recommendations for improvements. The objective of this

rulemaking is to address many of these recommendations, especially those related to BOP system design, performance, and reliability.

The BOP equipment and systems are critical components of many well operations. The BOP systems can be the last defense against a release of hydrocarbons into the environment, when all other forms of well control have failed (

e.g.,

the drilling fluid program). The BOPs may be the last line of defense in preventing release of gas that is volatile and considered to be an extreme safety hazard to rig personnel (uncontrolled gas releases can lead to explosions). The primary purpose of BOP systems is to prevent the uncontrolled release of hydrocarbons in an emergency situation by mechanically closing valves or rams that block the flow of fluid from the well. In some situations, this may require shear rams on the BOP stack to sever the drill pipe before the well can be sealed.

The BOP equipment and systems have increased in complexity as the industry moves into deeper water and develops reservoirs with pressures greater than 15,000 pounds per square inch (psi) or temperatures greater than 350 degrees Fahrenheit (F). Reservoirs with these conditions are considered high pressure high temperature (HPHT). Most of the BOPs that are used in deep water operations (400 to 10,000 feet) are located on the seabed, which presents technological and operational challenges. Additionally, HPHT operations create special metallurgical and design issues.

In this rulemaking, BSEE intends to:

• Implement many of the recommendations related to well-control equipment and fill gaps in the regulatory program.

• Increase the performance and reliability of well-control equipment, especially BOPs.

• Improve regulatory oversight over the design, fabrication, maintenance, inspection, and repair of critical equipment.

• Gain information on leading and lagging indicators of BOP component failures, identify trends in those failures, and help prevent accidents.

• Ensure that the industry uses recognized engineering practices, as well as innovative technology and techniques to increase overall safety.

Availability of Incorporated Documents for Public Viewing

When a copyrighted technical industry standard is incorporated by reference into our regulations, BSEE is obligated to observe and protect that copyright. The BSEE provides members of the public with Web site addresses where these standards may be accessed for viewing—sometimes for free and sometimes for a fee. Standards-developing organizations decide whether to charge a fee. The API provides free online public access to key industry standards, including a broad range of technical standards. These free standards represent almost one-third of all API standards and include all that are safety-related or have been or are proposed to be incorporated into Federal regulations, including the standards in this rule. These standards are available for online review, and hardcopies and printable versions will continue to be available for purchase. We are proposing to incorporate certain API standards. The API Web site address is:

http://www.api.org/publications-standards-and-statistics/publications/government-cited-safety-documents.

For the convenience of the viewing public, who may not wish to purchase or view these proposed documents online, they may be inspected at BSEE, 45600 Woodland Road, Sterling, Virginia 20166; phone: 703-787-1665; or at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202-741-6030, or go to:

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

continual improvement, emphasizing defect prevention and the reduction of variation and waste in the supply chain and from service providers. The goal of this specification is to increase equipment reliability through better manufacturing controls.

API Specification 6A—Specification for Wellhead and Christmas Tree Equipment

This specification defines minimal requirements for the design of valves, wellheads and Christmas tree equipment that is used during drilling and production operations. This specification includes requirements related to dimensional and functional interchangeability, design, materials, testing, inspection, welding, marking, handling, storing, shipment, purchasing, repair and remanufacture.

ANSI/API Specification 11D1—Packers and Bridge Plugs

This specification provides minimum requirements and guidelines for packers and bridge plugs used downhole in oil and gas operations. The performance of this equipment is often critical to maintaining control of a well during drilling or production operations. This specification provides requirements for the functional specification and technical specification, including design, design verification and validation, materials, documentation and data control, repair, shipment, and storage.

ANSI/API Specification 16A—Specification for Drill-Through Equipment

This specification defines requirements for performance, design, materials, testing and inspection, welding, marking, handling, storing and shipping of BOPs and drill-through equipment used for drilling for oil and gas. It also defines service conditions in terms of pressure, temperature and wellbore fluids for which the equipment will be designed. This standard is applicable to and establishes requirements for the following specific equipment: ram blowout preventers; ram blocks, packers and top seals; annular blowout preventers; annular packing units; hydraulic connectors; drilling spools; adapters; loose connections; and clamps.

Conformance to this standard is necessary to ensure that this critical safety equipment has been designed and fabricated in a manner that ensures reliable performance.

API Specification 16C—Specification for Choke and Kill Systems

This specification was formulated to provide for safe and functionally interchangeable surface and subsea choke and kill systems equipment utilized for drilling oil and gas wells. This equipment is used during emergencies to circulate out a “kick” and therefore, the design and fabrication of the components is extremely important. The technical content in the document provides the minimum requirements for performance, design, materials, welding, testing, inspection, storing and shipping. Equipment specific to and covered by this specification includes:

Actuated valve control lines;

Articulated choke & kill line;

Drilling choke actuators;

Drilling choke control lines, exclusive of BOP control lines;

Subsurface safety valve control lines;

Drilling choke controls;

Drilling chokes;

Flexible choke and kill lines;

Union connections;

Rigid choke and kill lines; and

Swivel unions.

API Specification 16D—Specification for Control Systems for Drilling Well Control Equipment and Control Systems for Diverter Equipment

This specification establishes design standards for systems that are used to control BOPs and associated valves that control well pressure during drilling operations. Although diverters are not considered well control devices, their controls are often incorporated as part of the BOP control system. Thus, control systems for diverter equipment are included in the specification. Control systems for drilling well control equipment typically employ stored energy in the form of pressurized hydraulic fluid (power fluid) to operate (open and close) the BOP stack components. For deepwater operations, transmission subsea of electric/optical (rather than hydraulic) signals may be used to short response times. The failure of these controls to perform as designed can result in a major well control event. As a result, conformance to this specification is critical to ensuring that the BOPs and related equipment will operate in an emergency.

ANSI/API Specification 17D—Design and Operation of Subsea Production Systems—Subsea Wellhead and Tree Equipment

This specification provides specifications for subsea wellheads, mudline wellheads, drill-through mudline wellheads and both vertical and horizontal subsea trees. These devices are located on the seafloor, and therefore, ensuring the safe and reliable performance of this equipment is extremely important. This document specifies the associated tooling necessary to handle, test and install the equipment. It also specifies the areas of design, material, welding, quality control (including factory acceptance testing), marking, storing and shipping for both individual sub-assemblies (used to build complete subsea tree assemblies) and complete subsea tree assemblies.

API Recommended Practice 17H—Remotely Operated Tools and Interfaces on Subsea Production Systems

This recommended practice has been prepared to provide general recommendations and overall guidance for the design and operation of remotely operated tools (ROT) comprising ROT and ROV tooling used on offshore subsea systems. ROT and ROV performance is critical to ensuring safe and reliable deepwater operations and this document provides general performance guidelines for the equipment.

Deepwater Horizon Investigations

This section discusses relevant investigations that have significant bearing on this proposed rulemaking.

DOI/DHS Investigation

The joint DOI/DHS investigation started on April 27, 2010, when the Secretaries of DOI and DHS convened a joint investigation team (JIT) comprised of staff from the MMS and the U.S. Coast Guard (USCG). The JIT held seven public hearings and heard testimony from more than 80 witnesses. The DOI JIT issued a report on September 14, 2011, entitled,

REPORT REGARDING THE CAUSES OF THE APRIL 20, 2010 MACONDO WELL BLOWOUT,

which included its findings, conclusions, and recommendations.

National Commission

On May 22, 2010, President Barack Obama announced the creation of the

National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

(National Commission), an independent, non-partisan entity. The President charged the National Commission to determine the causes of the disaster, to make recommendations for improvement to the country's ability to respond to spills, and to recommend reforms to make offshore energy production safer. The National Commission published its final

report on January 11, 2011, entitled,

DEEP WATER, The Gulf Oil Disaster and the Future of Offshore Drilling.

Chief Counsel for the National Commission

Given the factual and technical complexity of some of the underlying causes of the blowout, the National Commission's Chief Counsel issued a separate report setting forth in greater detail its findings and conclusions regarding the technical, managerial, and regulatory aspects of the blowout. The report contains findings and conclusions about the loss of well control, and also contains recommendations to industry and government to enhance well design. The Chief Counsel's report was published on February 17, 2011, and is entitled,

Macondo: The Gulf Oil Disaster.

National Academy of Engineering

At the request of DOI, a National Academy of Engineering (NAE)/National Research Council committee examined the probable causes of the

Deepwater Horizon

explosion, fire, and oil spill in order to identify measures for preventing similar harm in the future. The final report was released December 14, 2011, and is entitled,

Macondo Well-Deepwater Horizon Blowout.

The final report provides findings about the causes of the loss of well control and the failure of the BOP to prevent release of hydrocarbons and offers recommendations to industry and government that would strengthen oversight of deepwater wells, enhance system safety, and improve cementing practices and the technical skills of industry and regulatory staff.

Recommendations on BOPs

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

—The BSEE should consider promulgating regulations that require operators/contractors to have the capability to monitor the subsea electronic module (SEM) battery(ies) from the drilling rig, to ensure that there is sufficient battery power to operate the system.

—The BSEE should consider requiring standardization of: Remotely Operated Vehicle (ROV) intervention panels, ROV intervention capabilities, and maximum closing times when using an ROV; ROV hot stab and receptacles per API RP 17H; and hot stab designs between drilling and production operations.

—The BSEE should consider requiring a blind-shear ram design that incorporates improved pipe‐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 decision-makers, and the public the opportunity for free and open dialogue. Discussion panels consisted of representatives from government organizations, trade associations, equipment manufacturers, offshore operators, consultants, training companies, and others. During the forum, five separate panels discussed the following BOP topics:

—BOP technology needs identified by

Deepwater Horizon

investigations;

—Real-time technologies that can aid in diagnostics and kick detection;

—Design requirements needed to provide assurance that BOPs would cut casing or drill pipe and seal a well effectively;

—Manufacturing, testing, maintenance, and certification requirements needed to ensure operability and reliability of BOP equipment; and

—Training and certification needs for industry personnel operating or maintaining BOPs.

You can find additional information about the forum, including presentations and transcripts, on the BSEE Web page at:

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:

—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-and-Research/Technology-Assessment-Programs/Categories/Drilling/.

The research indicated that there was a large amount of uncertainty related to the shearing capability of existing BOPs. These reports documented that there were inconsistent and inadequate testing protocols used by manufacturers to demonstrate shearing capability, a failure to share shearing data that would allow for a better understanding of shearing capability, and a concern that not all operators and drilling contractors are aware of the limitations of the equipment they are using.

Following the

Deepwater Horizon

incident, the Agency received recommendations from multiple investigations and studies concerning the need for new and more rigorous requirements and technologies to ensure that drilling components can be severed and a well safely shut-in during an emergency. The BSEE is proposing a series of new requirements to address the gaps that were identified in these reports, incorporate recent industry standards, and assist in the adoption of improved technology through performance-based requirements.

Some of the limitations of current designs are well known. Industry acknowledges that BOP equipment would not shear drill collars, heavy weight drill pipe, or drill pipe tool joints. This inability to shear all of the components in the drill string can create significant complications in an emergency situation and increase the likelihood of a catastrophic event occurring. As the industry continues to develop more technically challenging resources, shearing and sealing become more difficult for several reasons, including:

—The improvements in drill pipe properties, particularly increased material strength and ductility, result in higher forces being required to shear the drill pipe in the future.

—Increased water depths, in combination with drilling fluid density and shut-in pressure, contribute to a BOP having to generate additional force to successfully shear.

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

—Require operators to assure that shearing capability for existing equipment complies with BSEE requirements related to shearing by performing tests and providing detailed results to a BSEE-approved verification organization. This organization would perform an independent engineering review of the test protocols and data and ensure that the testing would provide reasonable assurances that the equipment would perform as designed on drill pipe of specific mechanical and physical properties and under the operating conditions relevant to the particular well at which the equipment will be used. The BSEE expects that the independent engineering review would be based on recognized engineering practices. To become a BSEE-approved verification organization, organizations would need to submit documentation for BSEE approval describing the applicable qualifications and experience. This engineering review process would assist in developing more standardized testing protocols, increase data sharing within the industry, and provide information for future BSEE determinations of best available and safest technologies under section 21 of OSCLA, 43 U.S.C. 1347. The BSEE anticipates that industry would play an important role in this process by developing rigorous testing procedures and protocols for organizations that perform the testing.

—Require compliance with the latest industry standards contained in API Standard 53. In addition to these industry standards, BSEE would also include a requirement that operators use two shear rams in subsea BOP stacks. The use of double shear rams would increase the likelihood that a drill string can be sheared by ensuring that a shearable component is opposite a shear ram. In this proposed rulemaking, BSEE will not propose adopting the provision in API

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.

1

See

DOI JIT investigation recommendation, D6.

Equipment Reliability and Performance

Prior to the

Deepwater Horizon

incident, the industry's guidance document for the operation of BOPs was API RP 53—

Recommended Practices for Blowout Prevention Equipment Systems for Drilling Wells,

Third Edition, March 1, 1997 (Reaffirmed September 1, 2004). The BSEE currently incorporates only specific sections of this document in existing regulations, including sections related to maintenance, inspection, and accumulator systems. Following the

Deepwater Horizon

incident, industry recognized the need to enhance BOP guidance and concluded that it was necessary to completely rewrite API RP 53 and upgrade the document from an RP to a standard. The BSEE participated in the development of the industry standard and is proposing to incorporate the newly published standard into its regulations. Additionally, other key industry standards concerning this type of equipment would be incorporated by reference.

The BSEE concluded that incorporating new API Standard 53 provisions into its regulations would allow for better regulatory oversight and would ensure improved BOP design and operability. The BSEE believes that the incorporation of this document, and other key industry standards, such as ANSI/API Spec. 6A, ANSI/API Spec. 16A, API Spec. 16C, API Spec. 16D, ANSI/API Spec. 17D, and API Spec. Q1, would establish minimum design, manufacture, and performance baselines for this equipment and is essential to ensure the reliability and performance of this equipment. The BSEE anticipates that BOP equipment that meets these new requirements, along with several supplemental requirements (such as requiring blind-shear rams that incorporate improved pipe-centering designs), would perform in a more reliable manner.

The BSEE believes that the reliability of BOP-related equipment would also increase if its inspection, maintenance, and repair are performed by highly-trained personnel. Operators are currently required by BSEE regulations to ensure that all personnel are properly trained. The BSEE proposes to add requirements that specify that these personnel be qualified and trained pursuant to original equipment manufacturer (OEM) recommendations, unless otherwise specified by BSEE. The BSEE encourages industry to develop standards and certification programs for these personnel.

Third-Party Verification

Regulatory oversight of the lifecycle of BOP equipment, ranging from design, installation, inspection, testing, maintenance, and repair, presents a variety of logistical and technical challenges, especially because the equipment might be used at multiple locations. In several sections of the proposed regulations, BSEE would require third-party verification of the design, maintenance, inspection, testing, and repair of BOP systems and equipment by a BSEE-approved entity. We believe that the use of third-party verification organizations would help BSEE ensure that these systems are designed and maintained during their entire service life to minimize risk. For subsea BOPs or BOPs used in HPHT applications, we are proposing that BSEE-approved verification organizations submit reports verifying compliance with these new requirements. This verification would provide BSEE with reasonable assurance that the equipment is fit for service as intended.

The BSEE is also proposing an additional qualification and verification process for BOP(s) and related equipment used in HPHT wells. The verification must be specific to the conditions of the particular well at which the BOP(s) will be used. This verification process is needed because there are currently no engineering standards for the design, fabrication, and testing of equipment used in HPHT conditions. The use of a BSEE-approved verification organization would provide an additional layer of review and verification during the development and operation of the equipment. It would be the responsibility of the operator to clearly demonstrate to the BSEE-approved verification organization and BSEE that the equipment was designed for the HPHT conditions specific to the well, and will perform in a reliable manner during its service life under those conditions. To become a BSEE-approved verification organization, the organization would have to submit documentation for approval describing the organization's applicable qualifications and experience.

Failure Reporting/Near-Miss Reporting

Several of the standards that BSEE proposes to incorporate by reference contain failure reporting processes that ensure that operators share information with OEMs related to the performance of their equipment. This sharing of information makes it possible for the OEMs to notify users of any safety issues that arise. In 2009, the industry provided the MMS with a BOP reliability study that specifically noted the importance of ANSI/API Spec. 16A, Annex F, and referred to this requirement as “an excellent practice that assists manufacturers in identifying problems that occur in the operation and maintenance of their projects.” The BSEE agrees with this statement and is including this requirement in the proposed regulations.

Because the same equipment designs are often used by multiple operators, ensuring the timely reporting of this type of data can play an important role in preventing future incidents. The need for a formalized process for disseminating information to the industry was clearly demonstrated following the December 2012 failures of certain bolts used in BOPs and wellhead connectors in the Gulf of Mexico (GOM). Subsequent investigations revealed that although these failures had occurred over a period of years, most of the industry was not aware of the safety issues. The BSEE is proposing that the operators report any significant problems with BOP or well-control equipment to BSEE to ensure that this information can be provided in a timely manner to OCS operators and the international community. In the long term, BSEE would continue to encourage industry to develop a comprehensive and formalized method of collecting, analyzing, and disseminating failure data involving critical equipment.

Safe Drilling Practices

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

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

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 risk-based approach in its regulations. This risk reduction principle has also been included in a recently published industry document (API Bulletin 97) which addresses drilling, completion, and workover activities.

Proposed paragraph (e) would be added to clarify BSEE's authority to issue orders when necessary to protect health, safety, property, or the environment. The first sentence authorizes BSEE to issue orders to ensure compliance with the regulations. The second sentence clarifies that BSEE may order that operations of a component or facility be shut-in because of a threat of serious, irreparable, or immediate harm to health, safety, property, or the environment posed by those operations or because the operations violate law, including a regulation, order, or provision of a lease, plan, or permit.

Service fees. (§ 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 opt-out provision);

—Revising paragraph (h)(68) to update cross-references to the sections incorporating API Spec. Q1, Specification for Quality Programs for the Petroleum, Petrochemical and Natural Gas Industry;

—Revising paragraph (h)(70) to update cross-references to the sections incorporating ANSI/API Spec. 6A, Specification for Wellhead and Christmas Tree Equipment;

—Adding new paragraph (h)(89) to incorporate ANSI/API Spec. 11D1, Packers and Bridge Plugs;

—Adding new paragraph (h)(90) to incorporate ANSI/API Spec. 16A, Specification for Drill-through Equipment;

—Adding new paragraph (h)(91) to incorporate API Spec. 16C, Specification for Choke and Kill Systems;

—Adding new paragraph (h)(92) to incorporate API Spec. 16D, Specification for Control Systems for Drilling Well Control Equipment and Control Systems for Diverter Equipment;

—Adding new paragraph (h)(93) to incorporate ANSI/API Spec. 17D, Design and Operation of Subsea Production Systems—Subsea Wellhead and Tree Equipment;

—Adding new paragraph (h)(94) to incorporate ANSI/API RP 17H, Remotely Operated Vehicle Interfaces on Subsea Production Systems.

Paperwork Reduction Act statements—information collection. (§ 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.

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.

2

See

DOI JIT investigation recommendation, A3.

Paragraphs (h) and (i) would be revised with only minor wording changes.

New paragraph (j) would be added to require that the drilling prognosis include the type of wellhead and liner hanger systems to be installed and a descriptive schematic. The descriptive schematic would include, among other information, pressure ratings, dimensions, valves, load shoulders, and locking mechanism, if applicable. This information would assist BSEE in its review of the APD, and assist staff in ensuring that the wellhead and liner hanger systems are adequate for the proposed use.

New paragraph (k) would be added to require submittal of any additional information required by the District Manager.

What must my casing and cementing programs include? (§ 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

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

evaluation log (such as an ultrasonic or equivalent bond log), or a combination of these or other techniques to check cement integrity by verifying the top of cement, density, condition, bond, etc. If the cement job is determined to be adequate, the results of the cement job determination would be submitted to the District Manager in the WAR.

Paragraph (d) of the table in this section would be revised to clarify that if an operator has an inadequate cement job, the District Manager would have to review and approve all proposed remedial actions, unless immediate actions must be taken to ensure the safety of the crew or to prevent a well-control event. If the operator needs to take immediate action, a description would be required to be submitted to the District Manager once the action is completed. The paragraph would also clarify that any changes to the well program would require PE certification and would need to meet any other requirements imposed by the District Manager.

New paragraph (k) would be added to the table in this section and would add clarification concerning the use of valves on drive pipes during cementing operations for the conductor casing, surface casing, or liner, and require the following to assist BSEE in assessing the structural integrity of the well:

—The operator would include a description in the APD of the plan to use a valve that includes a schematic of the valve and height above the water line.

—The valve would be remotely operated and full opening with visual observation while taking returns.

—The person in charge of observing returns would be in communication with the drill floor.

—The operator would record in the daily report and in the WAR if cement returns were observed; and

—If cement returns were not observed, the operator would have to contact the District Manager and obtain approval of proposed plans to locate the top of cement, before continuing with operations.

These proposed additions in paragraph (k) would help BSEE assess the well's structural integrity and verify cement suitability to the mudline.

The overall changes to this section would help BSEE assess actual well operations and conditions, and also would help ensure proper design with additional PE review.

What are the general requirements for BOP systems and system components? (§ 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;

—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 Well-Completion 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.

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

§ 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 well-control 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 well-control 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

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.

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

This proposed new section would include a requirement covering real-time monitoring by onshore personnel of the BOP system, fluid handling system of the rig, and downhole conditions. This section would be added, in part, based on multiple recommendations from various

Deepwater Horizon

investigation reports. Having the real-time data available to onshore personnel would increase the level of oversight throughout operations. Onshore personnel could review data and help rig personnel conduct operations in a safe manner. Also, onshore personnel would be able to assist the rig crew in identifying and evaluating abnormalities or unusual conditions while conducting operations. This section would require that BSEE be provided access to the real-time monitoring facility, upon request. Operators would also be required to record and retain the data at an onshore location for recordkeeping purposes and to make it accessible to BSEE upon request. If real-time monitoring capability is lost during operations, the operator would be required to immediately notify the District Manager, who may require other measures until the real-time monitoring capability is restored.

The BSEE is considering expanding the requirements of this section to other operations, not only those conducted with a subsea BOP or a surface BOP on a floating facility or on any BOP operating in an HPHT environment. The BSEE is specifically soliciting comments on whether the real-time monitoring should be required for all well operations, including shallow water shelf operations. Please provide reasons for your position. If your comment addresses anticipated costs associated with such a requirement, please provide any available supporting data.

Blowout Preventer (BOP) System Requirements

What are the general requirements for BOP systems and system components? (§ 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 Drill-through Equipment;

—ANSI/API Spec. 16C,

Specification for Choke and Kill Systems;

—API Spec. 16D,

Specification for Control Systems for Drilling Well-control Equipment and Control Systems for Diverter Equipment;

and

—ANSI/API Spec. 17D,

Design and Operation of Subsea Production Systems—Subsea Wellhead and Tree Equipment

.

Sections of these industry standards apply to BOP systems. The BSEE specifically proposes to incorporate these standards into the regulations as applied to BOP systems to emphasize their significance and make clear the industry standards that must be followed. The BSEE is also requesting comments concerning whether any sections of these documents should not be incorporated by reference.

For general reference, the following table shows relevant topics from each of these industry standards. This table is not a complete list of applicable sections, but is intended to show how these sections interact with API Standard 53.

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.

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;

—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 BSEE-approved verification organization.

Paragraph (b) would be applicable to any operation that requires any type of BOP, and would require verification of shear testing, pressure integrity testing, and calculations for shearing and sealing pressures for all pipe to be used. Each of these verifications must demonstrate outlined specific requirements.

Paragraph (c) would require a special verification process for BOP and related equipment being used in HPHT environments because the design conditions required for an HPHT environment exceed the limits of existing engineering standards. The use of a BSEE-approved verification body would provide BSEE with an additional layer of review and verification at all steps in the development process. The paragraph makes it clear that the operator has the burden of clearly demonstrating the reliability of the equipment through a comprehensive review of the design, testing, and fabrication process.

Paragraph (d) would require an annual submittal of a Mechanical Integrity Assessment Report for a subsea BOP, a BOP used in HPHT environment, or a surface BOP on a floating facility. This paragraph would outline the requirements of a Mechanical Integrity Assessment report.

Paragraph (e) would require operators to make all documentation that supports the requirements of this section available to BSEE upon request.

The BSEE believes that using a third-party to verify the testing and qualification of BOP equipment would ensure consistent results and provide a reasonable assurance of the performance of this equipment. Based on previous studies available on the Web site of BSEE's Technology Assessment Program (available at:

http://www.bsee.gov/Technology-and-Research/Technology-Assessment-Programs/Index

), BSEE believes that the development of more rigorous industry testing protocols is critical to demonstrating the performance of BOP equipment.

The BSEE requests comments on the following issues associated with this section:

—On the issue of standardized test protocols and whether there are any specific procedures that should be considered for adoption.

—On the importance of applying forces in tension or compression during the actual shearing tests.

—On what criteria should be used to qualify a BSEE-approved verification organization and whether OEMs should be considered for the program.

—On the issue of updating test protocols and criteria used by verification organizations, given the likelihood of future improvements to BOP technology.

What are the requirements for a surface BOP stack? (§ 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 slick-line. If the blind-shear ram could not cut and seal electric-, wire-, or slick-line under MASP, an alternative cutting device would be required on the rig floor during operations that require their use, to cut the wire before closing the BOP. This requirement would be necessary to ensure that there are means to cut the wire in the hole, even if it is an external cutting device.

Paragraph (b) would codify BSEE policy and would:

—Clarify that when using a surface BOP on a floating production facility:

—the same BOP requirements apply as in § 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;

—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 fail-safe design, and each step in the logic would have to be independent of the previous step being completed. These revisions to the emergency functions would help provide the best means to carry out the intended functions. In the past, some BOP systems have only included one shear ram in the emergency functions, and these additions would ensure including both shear rams in those functions.

Proposed paragraph (a)(7) would add acoustic system requirements similar to current § 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.

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

—Positioning the entire pipe, including connection, completely within the area of the shearing blade necessary to ensure shearing would occur any time the shear rams are activated. This mechanism could not be another ram BOP or annular preventer;

—Mitigating compression of the pipe stub between the shearing rams. (This provision was added based upon multiple

Deepwater Horizon

investigation recommendations; the blind shear ram (BSR) could not fully close and seal because the drill pipe was forced to the side of the wellbore and outside of the BSR cutting surface); and

—Monitoring the subsea electronic module batteries in the BOP control pods.

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

—Submit a revised permit with a report from a BSEE-approved verification organization documenting the repairs and that the BOP is fit for service;

—Perform a new BOP test upon relatch; and

—Receive approval from the District Manager.

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

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

The BSEE is also soliciting specific comments on the following possible additional requirements:

—Under proposed paragraph (a)(1)(ii) of this section, requiring that both shear rams be able to shear the appropriate area for the casing landing string. Also please comment on whether there would be utility in installing the non-sealing shear ram above the sealing shear ram, and how it would affect the sequence of ram closure;

—Under proposed paragraph (a)(16) of this section, requiring a position indicator for each ram BOP, wellhead connector, and LMRP connector. The position indicator would have to be viewable by the ROV during operations and in the event of a disconnect of the LMRP; and

—Under proposed paragraph (a)(16) of this section, requiring sensing and displaying pressure within the BOP. This mechanism would have to be viewable by the ROV during operations and in the event of a disconnect of the LMRP.

These proposed requirements are in part based on various

Deepwater Horizon

investigation recommendations.

3

These proposed requirements would help identify the status of various BOP components under emergency situations to assist in emergency well control. If your comment addresses anticipated costs associated with any of the above requirements, please provide any available supporting data.

3

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

The BSEE is also soliciting comments on whether there are other options besides the use of shear rams to provide redundant shearing capability while ensuring the same level of safety and environmental protection.

What associated systems and related equipment must all BOP systems include? (§ 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 shut-in when necessary. The BSEE requests comments on whether this increase in equipment reliability justifies expanding the workover and decommissioning BOP testing frequency.

Proposed paragraph (b) would add a table to organize pressure testing requirements. Paragraph (b)(1) would be for a low-pressure test, and the required test pressure range would increase 50 psi to be between 250 to 350 psi. Paragraph (b)(2) would add high-pressure test requirements for BSR-type

BOPs, outside of all choke and kill side-outlet valves (and annular gas-bleed valves for subsea BOP), and inside of all choke and kill side-outlet valves below the uppermost ram. Paragraph (b)(3) would add high-pressure test requirements for inside of choke or kill valves (and annular gas bleed valves for subsea BOP) above the uppermost ram BOP and would clarify test pressure procedures.

Proposed paragraph (c) would require that each test must hold pressure for 5 minutes, which must be recorded on a 4-hour chart. This would allow the chart to display enough line curvature length to detect a leak during the test.

Proposed paragraph (d) would be reorganized into a table and additional testing requirements would be added. Revisions to the existing testing requirements would be:

Proposed paragraph (d)(1) would add a reference to the testing requirements in API Standard 53. Operators would be required to follow all testing requirements covered in API Standard 53, unless testing requirements conflict with BSEE regulations, in which case operators would be required to follow BSEE regulations.

Proposed paragraph (d)(2) would add requirements to use water to test a surface BOP system. This paragraph would also require that operators submit test procedures in their APD or APM for District Manager approval and contact the District Manager at least 72 hours prior to beginning the test to allow a BSEE representative to witness testing.

Proposed paragraph (d)(3) would require that operators submit stump test procedures for a subsea BOP system in their APD or APM for District Manager approval and require that stump tests follow the pressure test procedures set forth in paragraphs (b) and (c).

Proposed paragraph (d)(4) would outline the requirements for performing the initial subsea BOP test on the seafloor.

Proposed paragraph (d)(5) would expand testing requirements for two BOP control stations. The operator would be required to designate the control stations as primary and secondary and function-test each station weekly. The control station used to perform the pressure test would be required to be alternated between each pressure test. For a subsea BOP, the operator would be required to rotate the pods between each control station during the weekly function tests and alternate the pod used for pressure testing between each pressure test. If additional control stations are installed, they would have to be tested every 14 days.

Proposed paragraph (d)(7) would be a new requirement to pressure test annular type BOPs against the smallest pipe in use.

Proposed paragraph (d)(10) would be a new requirement to function test BSR BOPs every 14 days. This requirement would align the timing of the function and pressure tests.

Proposed paragraph (d)(12) would expand criteria for ROV testing to include testing and verifying closure capability of all intervention functions of the subsea BOP. These new provisions include requirements that:

—Each ROV must be fully compatible with the BOP stack ROV intervention panels;

—Operators must submit test procedures, including how they will test each ROV intervention function; and

—Operators must document all test results and make them available to BSEE upon request.

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

—Schematics of the circuitry of the system that would be used during an autoshear or deadman event;

—The approved schematics of the BOP control system with the actions and sequence of events that would take place; and

—How the ROV would be used during the well-control operations.

Prior to conducting the test, the well is to be in a secure configuration with appropriate barriers. The testing of the deadman system on the seafloor would have to indicate the discharge pressure of the subsea accumulator system throughout the test. During the initial test of the deadman system, the operator would need to have the ability to quickly disconnect the LMRP. The operators would also have to submit the quick-disconnect procedures with the deadman test procedures in the APD or APM. The BSR(s) would need to be pressure tested according to paragraphs (b) and (c) of this section. The operator would have to include in its procedure a description of how it plans to verify closure of a casing shear ram if installed. All test results would have to be documented and submitted to BSEE upon request.

Proposed paragraph (e) would require that operators notify BSEE at least 72 hours in advance of any shear ram tests in which the operators will shear pipe. This would allow better scheduling for BSEE personnel to witness these tests.

What must I do in certain situations involving BOP equipment or systems? (§ 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

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 re-establishing power, the operator would have to examine the system to determine if the possibility exists for the BSR opening immediately upon re-establishing power to the BOP stack. If this is a possibility, the opening function would have to be placed in the block position before power is re-established to the stack. The operator would have to contact the District Manager to receive approval of procedures for re-establishing power and functions prior to latching up the BOP stack or re-establishing power to the stack.

Proposed paragraph (l) would establish requirements for test rams. The initial BOP test after latch-up would have to be done with a test tool, and the wellhead/BOP connection would have to be tested to the maximum ram-test pressure approved for the well in the APD or APM. All hydraulically operated BOP components would have to function as designed during the well connection test.

Proposed paragraph (m) would add requirements for additional well-control equipment that operators may use, but which are not required in this subpart. The operator would have to request approval from the appropriate District Manager, submit a report from a BSEE-approved verification organization on the design and suitability of the equipment for its intended use, and submit any other information required by the District Manager. The District Manager may impose requirements concerning the equipment's capabilities, operation, and testing.

Proposed paragraph (n) would clarify that pipe and variable bore rams that have no current utility and would not be used for well-control purposes would not have to be pressure and function tested, until they are intended to be used during operations. Operators would have to indicate which pipe and variable bore rams meet this criteria in their APD or APM and label those rams on all BOP control panels.

Proposed paragraph (o) would include new requirements applicable to redundant well-control components in BOP systems that are in addition to components required in Subpart G. If any redundant component fails a test, you must submit a report from a BSEE-approved verification organization that describes the failure and confirms that there is no impact on the BOP that will make it unfit for well-control purposes. This report would have to be submitted to the District Manager, and operators may not resume operations until they receive the District Manager's approval. The District Manager may require operators to submit additional information before approving continued operations.

Proposed paragraph (p) would add new requirements that operators would have to meet if they need to position the bottom hole assembly across the BOP for tripping or any other operations, including:

—Ensuring that the well is stable at least 30 minutes before positioning the bottom hole assembly across the BOP, and

—Including in the well-control plan (required by proposed § 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 BSEE-approved verification organization would have to be present documenting the inspection and any problems encountered and produce a detailed report. This independent third-party report would have to be available to BSEE upon request. The BSEE is aware that, in the past, various components of BOP stacks have not had this type of inspection for more than 10 years. However, BSEE feels it is essential to ensure that every component on the BOP stack has a complete breakdown and detailed inspection every 5 years.

Proposed paragraph (c) would revise the subsea BOP inspection requirement to include visual inspection of the wellhead and remove the word “television.”

Proposed paragraph (d) would require that the personnel who maintain, inspect, or repair BOPs or other critical components meet the qualifications and training criteria specified by the OEM and that such maintenance, inspection, and repair be undertaken in accordance with recognized engineering practices. This provision is necessary to ensure that any personnel working on BOPs are properly qualified to perform any maintenance, inspections, or repairs.

Proposed paragraph (e) would require that all records be made available to BSEE upon request. This provision would also require operators to ensure, by contract or otherwise, that a rig owner maintains BOP records on the rig for 2 years from the date the records are created or longer if directed by BSEE. Also, all design, maintenance, inspection, and repair records must be maintained at an onshore location for the service life of the equipment.

Records and Reporting

What records must I keep? (§ 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.

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, wh

This text is long and has been trimmed here. Open the source document for the complete record.