# Oil and Gas and Sulfur Operations in the Outer Continental Shelf-Blowout Preventer Systems and Well Control > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3A2016-08921 ## Record - **Collection:** Federal Register - **Document type:** Rule - **Published:** April 29, 2016 - **Citation:** 81 FR 25888 ## Text DEPARTMENT OF THE INTERIOR Bureau of Safety and Environmental Enforcement 30 CFR Part 250 [Docket ID: BSEE-2015-0002; 15XE1700DX EEEE500000 EX1SF0000.DAQ000] RIN 1014-AA11 Oil and Gas and Sulfur Operations in the Outer Continental Shelf—Blowout Preventer Systems and Well Control AGENCY: Bureau of Safety and Environmental Enforcement, Interior. ACTION: Final rule. SUMMARY: Bureau of Safety and Environmental Enforcement (BSEE) is finalizing new regulations to consolidate into one part the equipment and operational requirements that are found in various subparts of BSEE's regulations pertaining to offshore oil and gas drilling, completions, workovers, and decommissioning. This final rule focuses on blowout preventer (BOP) and well-control requirements, including incorporation of industry standards and revision of existing regulations, and adopts reforms in the areas of well design, well control, casing, cementing, real-time well monitoring, and subsea containment. The final rule also addresses and implements multiple recommendations resulting from various investigations of the Deepwater Horizon incident. This final rule will also incorporate guidance from several Notices to Lessees and Operators (NTLs) and revise provisions related to drilling, workover, completion, and decommissioning operations to enhance safety and environmental protection. DATES: This final rule becomes effective on July 28, 2016. Compliance with certain provisions of the final rule, however, will be deferred until the times specified in those provisions and as described in Part III of the preamble. The incorporation by reference of certain publications listed in the rule is approved by the Director of the Federal Register as of July 28, 2016. FOR FURTHER INFORMATION CONTACT: Kirk Malstrom, Regulations and Standards Branch, (202) 258-1518, or by email: regs@bsee.gov. SUPPLEMENTARY INFORMATION: List of Acronyms and References ANSI American National Standards Institute APA Administrative Procedure Act APD Application for Permit to Drill API American Petroleum Institute APM Application for Permit to Modify BAST Best Available and Safest Technologies BAVO BSEE-Approved Verification Organization BOP Blowout Preventer BOEM Bureau of Ocean Energy Management BSEE Bureau of Safety and Environmental Enforcement BSR Blind Shear Ram CFR Code of Federal Regulations CVA Certified Verification Agent DHS Department of Homeland Security DOCD Development Operations Coordination Document DOI Department of the Interior DPP Development and Production Plan DWOPs Deepwater Operations Plans ECD Equivalent Circulating Density EDS Emergency Disconnect Sequence E.O. Executive Order EOR End of Operations Report EP Exploration Plan F Fahrenheit FOIA Freedom of Information Act FPSs Floating Production Systems FPSO Floating Production, Storage, and Offloading Unit FSHR Free Standing Hybrid Risers GOM Gulf of Mexico GOMR Gulf of Mexico region GPS Global Positioning Systems HPHT High Pressure High Temperature IC Information Collection IEC International Electrotechnical Commission ISO International Organization for Standardization JIT Joint Investigation Team LMRP Lower Marine Riser Package LWC Loss of Well Control MASP Maximum Anticipated Surface Pressure MAWHP Maximum Anticipated Wellhead Pressure MIA Mechanical Integrity Assessment MMS Minerals Management Service MODUs Mobile Offshore Drilling Units NAE National Academy of Engineering NAICS North American Industry Classification System NARA National Archives and Records Administration NAS National Academy of Sciences National Commission National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling NIST National Institute of Standards and Technology NTLs Notices to Lessees and Operators NTTAA National Technology Transfer and Advancement Act OCS Outer Continental Shelf OCSLA Outer Continental Shelf Lands Act OEM Original Equipment Manufacturer OFR Office of Federal Register OIRA Office of Information and Regulatory Affairs OMB Office of Management and Budget PEs Professional Engineers ppg Pounds per gallon psi Pounds per square inch QA/QC Quality Assurance/Quality Control RCD Regional Containment Demonstration RFA Regulatory Flexibility Act RIA Regulatory Impact Analysis RIN Regulation Identifier Number ROT Remotely Operated Tools ROV Remotely-Operated Vehicle RP Recommended Practice RTM Real-Time Monitoring SBA Small Business Administration SBREFA Small Business Regulatory Enforcement Fairness Act of 1996 SCCE Source Control and Containment Equipment Secretary Secretary of the Interior SEM Subsea Electronic Module SEMS Safety and Environmental Management Systems SIMOPS Simultaneous Operations Spec. Specification TAR Technical Assessment and Research TBT Agreement Technical Barriers to Trade Agreement TIA Takings Implication Analysis TLPs Tension Leg Platforms TVD True Vertical Depth USCG United States Coast Guard VBR Variable Bore Ram VSL Value of a Statistical Life WAR Well Activity Report WTO World Trade Organization Executive Summary Following the devastating impacts of the April 20, 2010, Deepwater Horizon incident on the Gulf of Mexico (GOM) and the surrounding states and local communities, multiple investigations were conducted to determine the causes of the incident and to make recommendations to reduce the likelihood of a similar incident in the future. The investigative groups included: —Department of the Interior (DOI)/Department of Homeland Security (DHS) Joint Investigation Team; —National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling; —Chief Counsel for the National Commission; and —National Academy of Engineering. Each investigation outlined several recommendations to improve offshore safety. BSEE evaluated the recommendations and acted on a number of them quickly to improve offshore operations, while BSEE's decision making with respect to other recommendations followed additional input from industry and other stakeholders. In April 2015, BSEE proposed regulations to, among other things, incorporate industry standards and NTL guidance; consolidate into one part the existing equipment and operational requirements that are found in various parts of BSEE's regulations; to revise and improve existing requirements for well design and control, casing and cementing; and to add new requirements for real-time monitoring (RTM) and subsea containment. The proposed regulations also addressed many of the recommendations made by the previously listed investigative bodies, which found a need to incorporate well-control best practices to advance safety and protection of the environment. BSEE received over 176 public comments on the proposed rule, and considered those comments in developing these final regulations. The requirements in this final rule, including the revisions made to the proposed regulations, reflect BSEE's consideration of the comments and BSEE's commitment to address the recommendations made in the Deepwater Horizon reports. This final rulemaking: (1) Incorporates all or designated portions of the following industry standards: —American Petroleum Institute (API) Standard 53, Blowout Prevention Equipment Systems for Drilling Wells, Fourth Edition, November 2012; —API Recommended Practice (RP) 2RD—Design of Risers for Floating Production Systems and Tension-Leg Platforms, First Edition, June 1998; Reaffirmed May 2006, Errata June 2009; —API Specification (Spec.) Q1—Specification for Quality Management System Requirements for Manufacturing Organizations for the Petroleum and Natural Gas Industry, Eighth Edition, December 2007, Effective Date: June 15, 2008; —American National Standards Institute (ANSI)/API Specification (Spec.) 11D1, Packers and Bridge Plugs Second Edition, Effective Date: January 1, 2010; —API RP 17H, Remotely Operated Tools and Interfaces on Subsea Production Systems, First Edition, July 2004, Reaffirmed: January 2009; —ANSI/API Spec. 6A, Specification for Wellhead and Christmas Tree Equipment, Nineteenth Edition, July 2004; Effective Date: February 1, 2005; —ANSI/API Spec. 16A, Specification for Drill-through Equipment, Third Edition, June 2004; —API Spec. 16C, Specification for Choke and Kill Systems First Edition, January 1993; —API Spec. 16D, Specification for Control Systems for Drilling Well Control Equipment and Control Systems for Diverter Equipment, Second Edition, July 2004; and —ANSI/API Spec. 17D, Design and Operation of Subsea Production Systems—Subsea Wellhead and Tree Equipment, Second Edition; May 2011. (2) Revises the requirements for Deepwater Operations Plans (DWOPs), which are required to be submitted to BSEE under specific circumstances, to add requirements on free standing hybrid risers (FSHR) for use with floating production, storage, and offloading units (FPSO). (3) Revises 30 CFR part 250, subpart D, Oil and Gas Drilling Operations, to include requirements for: —Safe drilling margins; —Wellhead descriptions; —Casing or liner centralization during cementing; and —Source control and containment. (4) Revises subparts E, Oil and Gas Well-Completion Operations, and F, Oil and Gas Well-Workover Operations, to include requirements for: —Packer and bridge plug design; and —Production packer setting depth. (5) Revises Subpart Q, Decommissioning Activities, to include requirements for: —Packer and bridge plug design; —Casing bridge plugs; and —Decommissioning applications and reports. (6) Adds new subpart G, Well Operations and Equipment, and moves existing requirements that were duplicated in subparts D, E, F, and Q into new subpart G including: —Rig and equipment movement reports; —RTM; and —Revised BOP requirements; including: —Design and manufacture/quality assurance; —Accumulator system capabilities and calculations; —BOP and remotely operated vehicle (ROV) capabilities; —BOP functions ( e.g. , shearing); —Improved and consistent testing frequencies; —Maintenance; —Inspections; —Failure reporting; —Third-party verification; and —Additional submittals to BSEE, including up-to-date schematics. (7) Incorporates the guidance from several NTLs into subpart G for: —Global Positioning Systems (GPS) for Mobile Offshore Drilling Units (MODUs); —Ocean Current Monitoring; —Using Alternate Compliance in Safety Systems for Subsea Production Operations; —Standard Reporting Period for the Well Activity Report (WAR); and —Information to include in the WARs and End of Operations Reports (EOR). Based on BSEE's economic analysis of available data, this final rule will be cost-beneficial. The estimated overall cost of the rule (outside those costs that are part of the economic baseline) over 10 years will be exceeded by the time-savings benefits to the industry resulting from the revisions to the former requirements for BOP pressure testing frequency for workovers and decommissionings. In addition, the final rule will also produce benefits to society, both quantifiable and unquantifiable, by reducing the probability of well control incidents involving oil spills. Table of Contents I. Background A. BSEE B. BSEE Statutory and Regulatory Authority and Responsibilities C. Purpose and Summary of the Rulemaking D. Availability of Incorporated Documents for Public Viewing E. Summary of Documents Incorporated by Reference II. Organization of Subpart G III. Discussion of Compliance Dates for the Final Rule IV. Issues Not Considered in this Rulemaking V. Discussion of Final Rule Requirements A. Summary of Key Regulatory Provisions B. Summary of Significant Differences Between the Proposed and Final Rules 1. Safe drilling margin 2. Accumulator systems 3. BOP 5-year major inspection 4. Real-time monitoring (RTM) 5. Potential increased severing capability 6. BOP pressure testing interval C. Other Differences Between the Proposed and Final Rules VI. Discussion of Public Comments on the Proposed Rule A. Requests for Extension of the Proposed Rule Comment Period B. Summary of General Comments on the Proposed Rule 1. Comments supporting the proposed rule 2. Legal comments 3. Arctic-related comments 4. General comments 5. Contractor/Operator/Manufacturer responsibilities 6. Economic analysis comments 7. Clarification of maximum anticipated surface pressure (MASP) C. Section-By-Section Summary and Responses to Significant Comments on the Proposed Rule VII. Derivation Tables VIII. Procedural Matters Regulatory Planning and Review (Executive Orders (E.O.) 12866 and 13563)) Regulatory Flexibility Act Small Business Regulatory Enforcement Fairness Act Unfunded Mandates Reform Act of 1995 Takings Implication Assessment (E.O. 12630) Federalism (E.O. 13132) Civil Justice Reform (E.O. 12988) Consultation With Indian Tribes (E.O. 13175) Paperwork Reduction Act (PRA) of 1995 National Environmental Policy Act of 1969 (NEPA) Data Quality Act Effects on the Nation's Energy Supply (E.O. 13211) I. Background A. BSEE BSEE was established on October 1, 2011, as part of a major restructuring of DOI's offshore oil and gas regulatory programs to improve the management and oversight of, and accountability for, activities on the Outer Continental Shelf (OCS). The Secretary of the Interior (Secretary) announced the division of responsibilities of the former Minerals Management Service (MMS) among two new bureaus and one office within DOI in Secretarial Order No. 3299, issued on May 19, 2010. BSEE, one of the two new bureaus, assumed responsibility for “safety and environmental enforcement functions including, but not limited to, the authority to permit activities, inspect, investigate, summon witnesses and [require production of] evidence[;] levy penalties; cancel or suspend activities; and oversee safety, response and removal preparedness.” (See 76 FR 64431, October 18, 2011). B. BSEE Statutory and Regulatory Authority and Responsibilities BSEE derives its authority primarily from the Outer Continental Shelf Lands Act (OCSLA), 43 U.S.C. 1331-1356a. Congress enacted OCSLA in 1953, authorizing the Secretary of Interior to lease the OCS for mineral development, and to regulate oil and gas exploration, development, and production operations on the OCS. The Secretary has delegated authority to perform certain of these functions to BSEE. To carry out its responsibilities, BSEE regulates offshore oil and gas operations to enhance the safety of offshore exploration and development of oil and gas on the OCS and to ensure that those operations protect the environment and implement advancements in technology. BSEE also conducts onsite inspections to assure compliance with regulations, lease terms, and approved plans. Detailed information concerning BSEE's regulations and guidance to the offshore oil and gas industry may be found on BSEE's website at: http://www.bsee.gov/Regulations-and-Guidance/index. BSEE's regulatory program covers a wide range of facilities and activities, including drilling, completion, workover, production, pipeline, and decommissioning operations. Drilling, completion, workover, and decommissioning operations are types of well operations that offshore operators 1 perform throughout the OCS. These well operations are the primary focus of this rulemaking. 1 BSEE's regulations at 30 CFR part 20 generally apply to “a lessee, the owner or holder of operating rights, a designated operator or agent of the lessee(s) . . .” covered by the definition of “you” in § 250.105. For convenience, this preamble will refer to all of the regulated entities as “operators” unless otherwise indicated. C. Purpose and Summary of the Rulemaking A primary purpose of this rulemaking is to prevent future well-control incidents, including major incidents like the 2010 Deepwater Horizon catastrophe. In addition to the loss of 11 lives, that single event resulted in the release of 134 million gallons of oil, which spread over 43,300 square miles of the GOM and 1,300 miles of shoreline in several states. The environmental and other damages caused by the Deepwater Horizon incident were immense and have had long-lasting and widespread impacts on the Gulf and the affected states. For example, as part of a settlement agreement between BP and Federal and state governments, BP has agreed to pay over $8 billion for natural resources damages caused by the spill and for the restoration of natural resources in the Gulf of Mexico region (GOMR). 2 Those damages include severe adverse effects on wildlife, wetlands and other wildlife habitat, recreation and tourism, and commercial fishing. The Deepwater Horizon Natural Resource Damage Assessment (NRDA) Trustees have determined that “the ecological scope of impacts from the Deepwater Horizon incident was unprecedented, with injuries affecting a wide array of linked resources across the northern Gulf ecosystem.” The released oil “was toxic to a wide range of organisms, including fish, invertebrates, plankton, birds, turtles, and mammals . . . [and] caused a wide array of toxic effects, including death, disease, reduced growth, impaired reproduction, and physiological impairments that made it more difficult for organisms to survive and reproduce.” 3 In addition, state and local government economic damage claims arising from the Deepwater Horizon incident were significant and have been settled for another $5.9 billion. 4 2 A summary and details of the recently approved natural resources damages settlement between BP and Federal and state governments are available at www.doi.gov/deepwaterhorizon and at http://www.justice.gov/enrd/deepwater-horizon. 3 Deepwater Horizon NRDA Trustees, Final Programmatic Damage Assessment and Restoration Plan and Final Programmatic Environmental Impact Statement, at p. 1-14-1-15. On March 22, 2016, the NRDA Trustees issued a Record of Decision setting forth the basis for the Trustees' decision to select the comprehensive, integrated ecosystem restoration alternative (described in Final PDARP/PEIS Sections 5.5 and 5.10). More details regarding the findings of the Federal and state Deepwater Horizon NRDA Trustees as to natural resources impacts from the Deepwater Horizon incident may be found at: http://www.gulfspillrestoration.noaa.gov/restoration-planning/gulf-plan/. 4 https://www.justice.gov/enrd/deepwater-horizon. In addition, despite new regulations and improvements in industry standards and practices since the Deepwater Horizon incident, which have resulted in progress in certain areas of safety and environmental protection, loss of well control (LWC) incidents are happening at about the same rate five years after that incident as they were before. In 2013 and 2014, there were 8 and 7 LWC incidents per year, respectively—a rate on par with pre- Deepwater Horizon LWCs. 5 Some of these LWC incidents have resulted in blowouts, such as the 2013 Walter Oil and Gas incident that resulted in an explosion and fire on the rig. All 44 workers were safely evacuated, but the fire lasted over 72 hours and the rig was completely destroyed, resulting in a financial loss approaching $60 million. This incident occurred in part due to the crew's inability to identify critical well control indicators and to the failure of critical well control equipment. 6 Blowouts such as these can lead to much larger incidents that pose a significant risk to human life and can cause serious environmental damage. 5 See http://www.bsee.gov/uploadedFiles/BSEE/BSEE_Newsroom/Publications_Library/Annual_Report/BSEE%202014%20Annual%20Report.pdf. 6 See BSEE, DOI, Investigation of Loss of Well Control and Fire South Timbalier Area Block 220, Well. No. A-3 OCS-G24980—23 July 2013 (July 2015), at http://www.bsee.gov/uploadedFiles/BSEE/Enforcement/Accidents_and_Incidents/Panel_Investigation_Reports/ST%20220%20Panel%20Report9_8_2015.pdf. Ensuring the integrity of the wellbore and maintaining control over the pressure and fluids during well operations are critical aspects of protecting worker safety and the environment. The investigations that followed the Deepwater Horizon incident, in particular, documented gaps or deficiencies in the OCS regulatory programs and made numerous recommendations for improvements. Accordingly, on April 17, 2015, BSEE proposed to consolidate its existing well-control rules into one subpart of the regulations, and to adopt new and revised regulatory requirements that address many of those recommendations, including those related to BOP system design, performance, and reliability. ( See 80 FR 21504.) Because BOP equipment and systems are critical components of many well operations, BSEE recognized that it was important to collect the best ideas on the prevention of well-control incidents and blowouts to assist in the development of the proposed rule. This included the knowledge, skillset, and experience possessed by the offshore oil and gas industry. Accordingly, BSEE participated in meetings, training, and workshops with industry, standards setting organizations, and other stakeholders in developing the proposed rule. ( See 80 FR 21508-21509.) The proposed rule discussed in detail topics such as: • Implementing many of the recommendations related to well-control equipment. • Increasing the performance and reliability of well-control equipment, especially BOPs. • Improving regulatory oversight over the design, fabrication, maintenance, inspection, and repair of critical equipment. • Gaining information on leading and lagging indicators of BOP component failures, identifying trends in those failures, and using that information to help prevent incidents. • Ensuring that the industry uses recognized engineering practices, as well as innovative technology and techniques to increase overall safety. To help ensure the development of effective regulations, the proposed rule used a hybrid regulatory approach incorporating prescriptive requirements, where necessary, as well as many performance-based requirements. BSEE recognizes the advantages and disadvantages of both approaches and understands that each approach could be effective and appropriate for specific circumstances. A full discussion of these topics, along with other background and regulatory history, is contained in the notice of proposed rulemaking ( see 80 FR 21504), which may be found on BSEE's website at http://www.bsee.gov/Regulations-and-Guidance/Regulations-In-Development/, and in the public docket for this rulemaking at: http://www.regulations.gov (in the Search box, enter BSEE-2015-0002, then click “search”). D. Availability of Incorporated Documents for Public Viewing BSEE frequently uses standards ( e.g., codes, specifications, RPs) developed through a consensus process, facilitated by standards development organizations and with input from the oil and gas industry, as a means of establishing requirements for activities on the OCS. BSEE may incorporate these standards into its regulations without republishing the standards in their entirety in the Code of Federal Regulations (CFR), a practice known as incorporation by reference. The legal effect of incorporation by reference is that the incorporated standards become regulatory requirements. This incorporated material, like any other properly issued regulation, has the force and effect of law, and BSEE holds operators, lessees and other regulated parties accountable for complying with the documents incorporated by reference in our regulations. We currently incorporate by reference over 100 consensus standards in BSEE's regulations governing offshore oil and gas operations ( see 30 CFR 250.198). Federal regulations, at 1 CFR part 51, govern how BSEE and other Federal agencies incorporate various documents by reference. Agencies may only incorporate a document by reference by publishing in the Federal Register the document title, edition, date, author, publisher, identification number, and other specified information. The Director of the Federal Register must approve each publication incorporated by reference in a final rule. Incorporation by reference of a document or publication is limited to the specific edition cited by the agency in the final rule and approved by the Director of the Federal Register . BSEE incorporates by reference in its regulations many oil and gas industry standards in order to require compliance with those standards in offshore operations. When a copyrighted publication is incorporated by reference into BSEE regulations, BSEE is obligated to observe and protect that copyright. BSEE provides members of the public with website addresses where these standards may be accessed for viewing—sometimes for free and sometimes for a fee. Standards development organizations decide whether to charge a fee. One such organization, API, provides free online public access to review its key industry standards, including a broad range of technical standards. These standards represent almost one-third of all API standards and include all that are safety-related or are incorporated into Federal regulations. Several of those standards are incorporated by reference in this final rule. In addition to the free online availability of these standards for viewing on API's website, hardcopies and printable versions are available for purchase from API. The API website address is: http://www.api.org/publications-standards-and-statistics/publications/government-cited-safety-documents. 7 7 To review these standards online, go to the API publications website at: http://publications.api.org. You must then log-in or create a new account, accept API's “Terms and Conditions,” click on the “Browse Documents” button, and then select the applicable category ( e.g., “Exploration and Production”) for the standard(s) you wish to review. For the convenience of members of the viewing public who may not wish to purchase or view these incorporated documents online, they may be inspected at BSEE's offices, 45600 Woodland Road, Sterling, Virginia 20166; phone: 703-787-1665; or at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202-741-6030, or go to: http://www.archives.gov/federal-register/cfr/ibr-locations.html. E. Summary of Documents Incorporated by Reference This rulemaking is substantive in terms of the content that is explicitly stated in the rule text itself, and it also incorporates by reference certain technical standards and specifications concerning BOPs and well control. A brief summary of each standard or specification follows. API Standard 53—Blowout Prevention Equipment Systems for Drilling Wells This standard provides requirements for the installation and testing of blowout prevention equipment systems whose primary functions are to confine well fluids to the wellbore, provide means to add fluid to the wellbore, and allow controlled volumes to be removed from the wellbore. BOP equipment systems are comprised of a combination of various components that are covered by this document. Equipment arrangements are also addressed. The components covered include: BOPs including installations for surface and subsea BOPs; choke and kill lines; choke manifolds; control systems; and auxiliary equipment. This standard also provides new industry best practices related to the use of dual shear rams, maintenance and testing requirements, and failure reporting. Diverters, shut-in devices, and rotating head systems (rotating control devices) whose primary purpose is to safely divert or direct flow rather than to confine fluids to the wellbore are not addressed. Procedures and techniques for well control and extreme temperature operations are also not included in this standard. API RP 2RD—Design of Risers for Floating Production Systems and Tension-Leg Platforms This standard addresses structural analysis procedures, design guidelines, component selection criteria, and typical designs for all new riser systems used on Floating Production Systems (FPSs) and Tension-Leg Platforms (TLPs). The presence of riser systems within an FPS has a direct and often significant effect on the design of all other major equipment subsystems. This RP includes recommendations on: (1) Configurations and components; (2) general design considerations based on environmental and functional requirements; and (3) materials considerations in riser design. API Spec. Q1—Specification for Quality Management System Requirements for Manufacturing Organizations for the Petroleum and Natural Gas Industry This specification establishes the minimum quality management system requirements for organizations that manufacture products or provide manufacturing-related processes under a product specification for use in the petroleum and natural gas industry. This standard requires that equipment be fabricated under a quality management system that provides for continual improvement, emphasizing defect prevention and the reduction of variation and waste in the supply chain and from service providers. The goal of this specification is to increase equipment reliability through better manufacturing controls. API Spec. 6A—Specification for Wellhead and Christmas Tree Equipment This specification defines minimal requirements for the design of valves, wellheads and Christmas tree equipment that is used during drilling and production operations. This specification includes requirements related to dimensional and functional interchangeability, design, materials, testing, inspection, welding, marking, handling, storing, shipment, purchasing, repair and remanufacture. ANSI/API Spec. 11D1—Packers and Bridge Plugs This specification provides minimum requirements and guidelines for packers and bridge plugs used downhole in oil and gas operations. The performance of this equipment is often critical to maintaining control of a well during drilling or production operations. This specification provides requirements for the functional specification and technical specification, including design, design verification and validation, materials, documentation and data control, repair, shipment, and storage. ANSI/API Spec. 16A—Specification for Drill-through Equipment This specification defines requirements for performance, design, materials, testing and inspection, welding, marking, handling, storing and shipping of BOPs and drill-through equipment used for drilling for oil and gas. It also defines service conditions in terms of pressure, temperature and wellbore fluids for which the equipment will be designed. This standard is applicable to, and establishes requirements for, the following specific equipment: Ram BOPs; ram blocks, packers and top seals; annular BOPs; annular packing units; hydraulic connectors; drilling spools; adapters; loose connections; and clamps. Conformance to this standard is necessary to ensure that this critical safety equipment has been designed and fabricated in a manner that ensures reliable performance. API Spec. 16C—Specification for Choke and Kill Systems This specification was formulated to provide for safe and functionally interchangeable surface and subsea choke and kill systems equipment utilized for drilling oil and gas wells. This equipment is used during emergencies to circulate out a “kick” and, therefore, the design and fabrication of the components is extremely important. This document provides the minimum requirements for performance, design, materials, welding, testing, inspection, storing and shipping. Equipment specific to and covered by this specification includes: Actuated valve control lines; articulated choke and kill lines; drilling choke actuators; drilling choke control lines, exclusive of BOP control lines; subsurface safety valve control lines; drilling choke controls; drilling chokes; flexible choke and kill lines; union connections; rigid choke and kill lines; and swivel unions. API Spec. 16D—Specification for Control Systems for Drilling Well Control Equipment and Control Systems for Diverter Equipment This specification establishes design standards for systems that are used to control BOPs and associated valves that control well pressure during drilling operations. Although diverters are not considered well-control devices, their controls are often incorporated as part of the BOP control system. Thus, control systems for diverter equipment are included in the specification. Control systems for drilling well-control equipment typically employ stored energy in the form of pressurized hydraulic fluid (power fluid) to operate (open and close) the BOP stack components. For deepwater operations, subsea transmission of electric/optical (rather than hydraulic) signals may be used to shorten response times. The failure of these controls to perform as designed can result in a major well-control event. As a result, conformance to this specification is critical to ensuring that the BOPs and related equipment will operate in an emergency. ANSI/API Spec. 17D—Design and Operation of Subsea Production Systems—Subsea Wellhead and Tree Equipment This standard provides specifications for subsea wellheads, mudline wellheads, drill-through mudline wellheads, and both vertical and horizontal subsea trees. These devices are located on the seafloor, and, therefore, ensuring the safe and reliable performance of this equipment is extremely important. This document specifies the associated tooling necessary to handle, test and install the equipment. It also specifies the areas of design, material, welding, quality control (including factory acceptance testing), marking, storing and shipping for both individual sub-assemblies (used to build complete subsea tree assemblies) and complete subsea tree assemblies. API RP 17H—Remotely Operated Tools and Interfaces on Subsea Production Systems This RP provides general recommendations and overall guidance for the design and operation of remotely operated tools (ROT) comprising ROT and ROV tooling used on offshore subsea systems. ROT and ROV performance is critical to ensuring safe and reliable deepwater operations and this document provides general performance guidelines for the equipment. II. Organization of Subpart G BSEE's former regulations repeated similar BOP requirements in multiple locations throughout 30 CFR part 250. In this final rule, BSEE is consolidating these requirements into subpart G (which previously had been reserved). The final rule will structure subpart G—Well Operations and Equipment, under the following undesignated headings: —GENERAL REQUIREMENTS —RIG REQUIREMENTS —WELL OPERATIONS —BLOWOUT PREVENTER (BOP) SYSTEM REQUIREMENTS —RECORDS AND REPORTING The sections contained within this new subpart will apply to all drilling, completion, workover, and decommissioning activities on the OCS, unless explicitly stated otherwise. III. Discussion of Compliance Dates for the Final Rule BSEE understands that operators may need time to comply with certain new requirements in this final rule. Based on information provided by industry, drilling rigs are now being built, or were built, pursuant to the same industry standards BSEE is now incorporating by reference (including API Standard 53), and many have already been retrofitted to comply with these industry standards. Furthermore, most drilling rigs already comply with recognized engineering practices and original equipment manufacturer (OEM) requirements related to repair and training. BSEE has considered the public comments on the proposed compliance dates, as well as relevant information gained during, among other activities, BSEE's interactions with stakeholders, involvement in development of industry standards, and evaluation of current technology. Accordingly, BSEE is setting an effective date of 90 days following publication of the final rule, by which time operators will be required to demonstrate compliance with most of the final rule's provisions. BSEE has determined, however, that it is appropriate to extend the compliance dates for the following new requirements. Detailed explanations for these extended compliance dates are provided in parts V and VI of this document. —As required in § 250.734(a)(15), operators must install a gas bleed line with two valves for the annular preventer no later than 2 years from publication of the final rule. BSEE is extending the timeframe for this requirement based on the current level of availability of the required equipment and the time needed to install the equipment. This timeframe was selected to avoid any rig downtime. —As required by §§ 250.733(a)(1) and 250.734(a)(1), operators must have the capability to shear and seal tubing with exterior control lines no later than 2 years from the publication of the final rule. BSEE is aware that some current technology is available to shear tubing with exterior control lines; however, the effective date has been extended to allow operators to acquire and install (and, if necessary, to develop new or alternative) equipment to meet the requirements. —As required by §§ 250.731, 250.732, 250.734, 250.738, and 250.739, operators must begin using a BSEE-approved verification organization (BAVO) for certain submittals, certifications, and verifications. 8 BSEE will develop and make available on its public website a list of BAVOs, consisting of qualified third-party organizations that BSEE determines are capable of performing the functions specified in this final rule, and that will help BSEE ensure that BOP systems are designed and maintained during their service life to minimize risk. Industry currently uses independent third-parties to perform verifications similar to the certifications and verifications that a BAVO will be required to perform under this final rule. BSEE is extending the compliance date for the use of BAVOs to no later than 1 year from the date when BSEE publishes the list of BAVOs. BSEE anticipates that most of the independent third-parties currently used by industry under the former regulations will become BAVOs, significantly facilitating compliance with the requirements to use BAVOs within the one-year timeframe. 8 For example, § 250.731(c)(2) requires certification and verifacation that all BOPs are designed and tested to maximun anticipated condictions. In the interim, however, final § 250.732(a) requires that operators use independent third-parties to perform the certifications, verifications and reports that BAVOs must perform no later than 1 year after BSEE publishes a BAVO list. This transitional measure is necessary to ensure that there is no diminution of the safety and environmental protection currently afforded by the use of independent third-parties under the existing regulations or of the safety and environmental improvements anticipated under the new BAVO requirements, during the time required for BSEE to identify and for operators to use the BAVOs. —As required in § 250.724, operators must comply with the RTM requirements no later than 3 years from the publication of the final rule. —As required in § 250.734(a)(3), operators are required to have dedicated subsea accumulator capacity for autoshear and deadman functions on subsea BOPs within 5 years from the publication of the final rule. As explained in more detail in part VI.C, changing the compliance date for these new accumulator requirements—from the proposed 3 months to the final 5 years from the date of publication—will allow sufficient lead time for industry to acquire and install additional accumulator equipment as necessary and will correspond with the timeframe for compliance with the final dual shear ram requirements, which is when the additional accumulator capacity will most likely be needed. —As required in § 250.734(a)(1), operators must install dual shear rams on subsea BOPs no later than 5 years from the publication of the final rule. —As required in § 250.733(b)(1), surface BOPs installed on floating facilities 3 years after publication of the final rule must comply with the BOP requirements of § 250.734(a)(1). —As required in § 250.734(a)(16), operators must install shear rams that center drill pipe during shearing operations no later than 7 years from the publication of the final rule. —As required in § 250.735(g), operators must install remotely-controlled locks on surface BOP sealing rams no later than 3 years from publication of the final rule. —As required in § 250.733(b)(2), for any risers installed 90 days after the date of the publication of the final rule or later, operators must use dual bore risers for surface BOPs on floating production facilities. The final rule does not require that operators change the riser configuration for risers that were installed on floating facilities before 90 days after the publication date of the final rule. —As required in §§ 250.732(b)(1)(i) and 250.734(a)(1)(ii), the BOP must be able to shear electric-, wire-, and slick-line no later than 2 years after publication of the final rule. IV. Issues Not Considered in This Rulemaking BSEE is continuing to review and evaluate additional operational and equipment issues that are not included in this final rulemaking, such as: —Well-control planning, procedures, training, and certification; —Major rig equipment; —Certification requirements for personnel servicing critical equipment; —Choke and kill systems; —Mud gas separators; —Wellbore fluid safety practices, testing, and monitoring; —Diverter systems with subsea BOPs; and —Additional severing requirements. V. Discussion of Final Rule Requirements Part V.A, which follows, summarizes and highlights some important requirements of the final rule that were described in more detail in the proposed rule. Some of these provisions received no comments during the public comment period, while other provisions were supported or criticized by certain commenters. Part V.B addresses significant relevant comments on certain proposed provisions and summarizes changes to those provisions that BSEE has made in the final rule based on consideration of those comments. Part V.C summarizes other changes to the proposed rule that BSEE has made in the final rule to avoid ambiguity or confusion, eliminate redundancies, correct minor drafting errors, or otherwise clarify the meaning of the new requirements. A. Summary of Key Regulatory Provisions After review of all the relevant public comments received on the proposed rule, BSEE determined that the following proposed revisions will be included in this final rule. Most of the proposed provisions are included without change, while several of the proposed provisions have been revised in the final rule in response to comments, as explained in parts V.B and VI of this document. Shearing Requirements— • Requires BOP shearing performance testing and results reporting to a BAVO. This will ensure that shearing capability for existing equipment complies with BSEE requirements. • Requires compliance with the latest industry standards contained in API Standard 53. • Requires that operators use two shear rams in subsea BOP stacks. • Requires the use of BOP technology that provides for better shearing performance through the centering of the drill pipe in the shear rams. Equipment Reliability and Performance— • Requires compliance with industry standards, such as relevant provisions of API Standard 53, ANSI/API Spec. 6A, ANSI/API Spec. 16A, API Spec. 16C, API Spec. 16D, ANSI/API Spec. 17D, and API Spec. Q1. BOP operability will be improved by establishing minimum design, manufacture, and performance baselines that are essential to ensure the reliability and performance of this equipment. • Requires inspection, maintenance, and repair of BOP-related equipment by appropriately trained personnel; this will also increase the reliability of BOP-related equipment. Equipment Failure Reporting/Near-Miss Reporting— • Requires that operators share information with Original Equipment Manufacturers (OEMs) related to the performance of their BOP system equipment. This sharing of information makes it possible for the OEMs to notify all users of any safety issues that arise with BOP system equipment. • Requires that operators report any significant problems with BOP or well-control equipment to BSEE, so BSEE can determine whether information should be provided, in a timely manner, to OCS operators and, if appropriate, to international offshore regulators and operators. Safe Drilling Practices— • Requires maintaining safe drilling margins and other requirements related to liners and other downhole equipment to help reduce the likelihood of a major well-control event and ensure the overall integrity of the well design. • Requires monitoring of deepwater and High Pressure High Temperature (HPHT) drilling operations from the shore and in real-time. This will allow operators to anticipate and identify issues in a timely manner and to utilize onshore resources to assist in addressing critical issues. • Requires daily reports to BSEE concerning any leaks associated with BOP control systems. This will ensure that the bureau is made aware of any leaks so it can determine if further action is appropriate. • Requires compliance with API RP 17H to standardize ROV hot stab activities. This will allow certain functions of the BOP to be activated remotely. BOP Testing— • Requires same pressure testing frequency (at least once every 14 days) for workover and decommissioning operations as for drilling and completion operations. Pressure test results will aid in predicting future performance of a BOP, and harmonizing testing frequencies for all well operations will also help streamline the BOP function-testing criteria and reduce the unnecessary repetition every 7 days of testing in workover and decommissioning operations that could pose operational safety issues. • Requires additional measures ( e.g., RTM and increased maintenance) to help ensure the functionality and operability of the BOP system that will help reduce the safety and environmental risks. B. Summary of Significant Differences Between the Proposed and Final Rules After consideration of all relevant and significant comments, BSEE made a number of revisions from the proposed rule in the final rule. We are highlighting several of these changes here because they are significant, and because numerous comments addressed these topics. A discussion of the relevant and significant comments and BSEE's responses are found in part VI of this document. The significant revisions made in response to comments include: 1. Safe Drilling Margin—§ 250.414(c) In response to one of the Deepwater Horizon investigation recommendations— i.e., to better define safe drilling margins—BSEE proposed to revise the safe drilling margin portion of the drilling prognosis ( i.e., well drilling procedures) required in an Application for Permit to Drill (APD). Among other things, BSEE proposed that the “static downhole mud weight must be a minimum of 0.5 pound per gallon (ppg) below the lesser of the casing shoe pressure integrity test or the lowest estimated fracture gradient” (“the 0.5 ppg drilling margin”). This proposed requirement was typically part of BSEE's approval parameters during the permitting process. However, many commenters expressed concerns that strict enforcement of a 0.5 ppg drilling margin in all circumstances could cause adverse economic consequences because it could effectively require setting additional casing strings and smaller hole sizes and thus, in some cases, could make it impossible to reach target depths. The commenters suggested various alternatives to the 0.5 ppg requirement, including allowing operators to use a risk-based approach to setting safe drilling margins on a case-by-case basis. Typically, 0.5 ppg is an appropriate safe drilling margin for normal drilling scenarios and has been approved by BSEE (and thus made a requirement) in numerous APDs. However, BSEE understands that there are some well-specific circumstances where a lower drilling margin may be acceptable to drill a well safely, and BSEE has approved appropriate alternative downhole mud weights as part of a safe drilling margin in many APDs. Accordingly, in this final rule, BSEE is keeping the 0.5 ppg drilling margin as proposed to be the default requirement, but is adding a new paragraph (c)(2) to § 250.414 that expressly allows the use of an alternative to the 0.5 ppg drilling margin if the operator submits adequate justification and documentation, including supplemental data ( e.g. , offset well data, analog data, seismic data, risk modeling), in the APD. This addition is consistent with current BSEE GOMR practice to allow alternative drilling margins when justified and documented. This change will also provide operators some assurance that an alternative drilling margin, other than the 0.5 ppg margin, may be used when appropriate, while helping BSEE ensure the use of drilling mud with properties ( e.g. , density, viscosity, additives) best suited for a specific well interval and based on well-specific drilling and geological parameters. 9 This addition to the safe drilling margin section will provide increased planning flexibility when drilling into areas that could require lower safe drilling margins, such as depleted sands or below salt (both common occurrences in the GOMR), and help avoid the potential negative consequences of requiring a 0.5 ppg margin in all cases. 9 Alternatives to compliance with the 0.5 ppg safe drilling margin requirement could also be requested under existing § 250.141, and approved by BSEE if the criteria of that section are satisfied; but such separate requests would not be necessary if an operator requests an alternative in its APD under new § 250.414(c)(2). BSEE is also making other minor changes to the proposed § 250.414(c). Specifically, as suggested by several commenters, we are replacing the term “static downhole mud weight” with “equivalent downhole mud weight,” and removing the references to Equivalent Circulating Density (ECD). Several commenters suggested replacing static downhole mud weight with a more appropriate term to better define and assess the mud weight because of the difficulty of achieving and verifying static downhole mud weight during operations. BSEE agrees with this observation. To verify a static downhole mud weight, the well would need to be placed in a static situation. This would be done by turning off the pumps and letting the well sit until it is static; however, that process can result in complications, such as cuttings and debris settling out in the bottom of the well and thermal gradients affecting mud properties. Some of these complications may create additional issues, such as stuck pipe or loss of wellbore integrity. The change from “static” to “equivalent” allows the downhole mud weight to be based on the mud properties that can be tested at the surface and then calculated to downhole conditions. Thus, equivalent downhole mud weight can be verified on the rig as operations are being conducted. BSEE also removed the references to ECD from this section based on comments. For the reasons discussed elsewhere in this preamble (with regard to § 250.413), BSEE determined that operators do not need to submit the estimated ECD in the APD permitting process; however, BSEE expects operators to continue their normal practice of considering ECD while drilling. 2. Accumulator Systems In the proposed rule, BSEE proposed a number of significant changes to existing BOP requirements as well as new requirements for BOPs and associated systems, including new requirements for subsea and surface BOP accumulator systems. (See proposed §§ 250.734 and 250.735.) The purpose of the accumulator system and these new requirements is to ensure that there is sufficient volume and pressure in the accumulator bottles to properly operate BOP components in a specified timeframe regardless of the location of the accumulator bottles. Among other things, we proposed increasing accumulator capacity to operate all BOP functions; i.e., requiring all surface accumulator systems, whether associated with surface or subsea BOPs, to meet the requirements for accumulators servicing surface BOPS under the prior regulations (including the requirement that the accumulator system provide 1.5 times the volume of fluid capacity necessary to hold closed all BOP components). We also proposed requiring surface accumulator systems to operate under MASP conditions, with the blind shear ram being last in the BOP sequence, and still have enough accumulated pressure to allow the BOP to shear pipe and seal the well. In addition, we proposed defining critical functions for BOP operation, and requiring dedicated, independent accumulator bottles for emergency functions (autoshear/deadman/emergency disconnect sequence (EDS)). BSEE received multiple comments on these proposed provisions. Industry stakeholders raised concerns with (and in some cases suggested revisions to) the proposed requirements, including the following concerns: • That the proposed surface and subsea accumulator capacity requirements are in conflict with API Standard 53 and API Spec. 16D; • That the terminology in the proposed rule and the current industry standard (API Standard 53) are inconsistent, and that the different terminology could cause ambiguity and confusion in efforts to comply with a final rule. Industry commenters recommended using the terminology used in the API standard; and • That the proposed requirement that accumulator systems be able to supply pressure to operate all BOP components and shear pipe as the last step in the BOP sequence, without assistance from a charging unit, would increase the number of accumulator bottles needed and would require upgraded accumulator system controls. The commenters also stated that costs associated with the additional bottles would be significant and that the extra weight from additional bottles, given limited deck space availability, could cause structural issues with the rig. • That the proposed requirements that the subsea accumulator system be able to supply pressure to operate all critical BOP components, and that the system have dedicated bottles for each EDS/autoshear/deadman system(s), would greatly increase the number of accumulator bottles on the subsea BOP. The commenters stated that the increased number and weight of accumulator bottles could also cause structural concerns for the BOP frame and the rig and that costs associated with the additional bottles would also be significant. BSEE reviewed all of the relevant comments and has made changes to the proposed surface and subsea accumulator requirements in the final rule. In this final rule, BSEE is deleting the “1.5 times volume capacity” requirement for all surface accumulators, and instead requiring that all accumulator systems (including those servicing subsea BOPs) meet the sizing specifications of API Standard 53. The final rule also extends the effective date to comply with the new accumulator requirements (both surface and subsea) to 5 years; removes the proposed requirement that the surface accumulator be able to operate the blind shear ram as the last function in the BOP sequence; defines “critical functions;” and requires dedicated subsea accumulator bottles for autoshear and deadman (but not EDS) functions and allows those dedicated bottles to be shared between the autoshear and deadman functions. BSEE reevaluated the relevant industry standards and determined that API Standard 53 and API Spec. 16D provide reasonable and appropriate methods to ensure proper volumes and pressures of appropriate BOP components. Changing the proposed volume requirements for surface accumulators to meet the specifications of API Standard 53 will allow for more specific assessments of the capacity necessary to address unique operating conditions, while still ensuring that there is enough capacity to operate all specified BOP components in an emergency. This will significantly reduce the additional costs identified in industry comments, since it eliminates the “1.5 times volume” requirement that the proposed rule would have extended to surface accumulators servicing a subsea BOP, and since most accumulator equipment has been designed to meet the API Standard 53 specifications since that standard was adopted in 2012. Removing the “1.5 times volume” requirement and replacing it with the volume requirements of API Standard 53 also will not decrease safety or environmental protection as compared to the proposed requirement. BSEE determined that the methods for calculating the necessary fluid volumes and pressures in the API standard provide an acceptable amount of usable fluid and pressure to operate the required components, while still ensuring the required 200 pounds per square inch (psi) above the pre-charge pressure. API Standard 53 also discusses the need to have 200 psi remaining on the bottles above the pre-charge pressure after operating the BOP components, which would provide a sufficient margin of error to promote safety and help prevent environmental harm from failure of pressure to the BOP. Removing the proposed language regarding the blind shear ram being the last in sequence will eliminate industry's misimpression that the proposed language would have mandated that the blind shear ram always be the last step in the BOP sequence. In addition, BSEE agrees with the commenters that the proposed language regarding sequencing of the blind shear ram is not necessary, as long as the accumulator is able to provide sufficient volume of fluid to operate all the required BOP functions under MASP. BSEE is also making changes in the final rule to the subsea accumulator requirements in response to comments. BSEE is requiring subsea accumulators to have enough capacity to provide pressure for critical functions, as defined in API Standard 53, and to have accumulator bottles that are dedicated to autoshear and deadman functions (but not EDS), and that may be shared between those functions. Subsea accumulator charge normally comes from the surface, but in an emergency the connections to the surface may be lost and/or the accumulator may have already operated multiple BOP components, which may have reduced the accumulator fluid pressure needed to successfully shear and seal. Dedicated bottles for autoshear and deadman functions would ensure that the subsea accumulator has enough pressure available to operate those emergency systems even if all surface connections are lost or the volume or pressure in the accumulator system are depleted. BSEE determined, however, that permitting those functions to share the dedicated accumulator bottles would not result in a reduction to safety or environmental protection so long as the shared bottles are capable of providing enough pressure to operate the emergency functions. By contrast, dedicated capacity in a subsea accumulator for the EDS is not necessary, since the EDS is serviced through the main (surface) accumulator system by rig personnel. 3. BOP 5-Year Major Inspection In the proposed rule, BSEE included a provision to require a complete breakdown and inspection of the BOP and every associated component every 5 years, as documented by a BAVO, which, as proposed, could not be performed in phased intervals. BSEE received multiple comments on the 5-year inspection interval. Most industry commenters did not object to a 5-year inspection requirement for each BOP component, provided that the inspections could be staggered, or phased, over time. Commenters expressed concern that requiring all components to be inspected at one time would put too many rigs out of service, potentially for long periods of time, with substantial economic impacts. Based on consideration of the issues raised in the comments, BSEE has revised the final rule in order to allow a phased approach for 5-year inspections ( e.g., staggered inspection for each component), as long as there is proper documentation and tracking to ensure that BSEE can verify that each applicable BOP component has had the major inspection within 5 years. BSEE is also adding, for clarification, the applicable dates for the starting point of the 5-year cycle. BSEE is confident that these inspection requirements maintain the necessary level of safety and environmental protection without resulting in unnecessary interference with scheduling or complications for operations. Requiring operator documentation of the component inspection dates, and requiring those records to be available on the rig, will help BSEE to verify that the components were inspected within the required timeframe and will also assist BSEE's review of the documentation, when requested. The final rule requires that all of the appropriate components be inspected during the 5-year cycle. Proper documentation of phased inspections will improve BSEE oversight, as compared to current practice, while a phased approach will avoid the possibility of long rig shut downs. 4. Real-Time Monitoring In § 250.724 of the proposed rule, BSEE proposed to require RTM of certain data for well operations that use either a subsea BOP or a BOP on a floating facility, or are conducted in an HPHT environment. Under the proposed rule, the RTM system would have been required to gather and “immediately transmit” data on the BOP control system, the well's fluid handling systems on the rig, and the well's downhole conditions with the bottom hole assembly tools (if any) to an onshore facility to be monitored by qualified personnel in “continuous contact” with rig personnel during operations. In addition, BSEE proposed that, after transmission, the RTM data must be preserved and stored at a designated location, identified in an APD or APM, and that the location and RTM data be made available to BSEE upon request. Finally, the proposed rule would have required immediate notification to the appropriate BSEE District Manager of any loss of RTM capability during operations and would have authorized the District Manager to require other measures pending restoration of RTM capabilities. BSEE intends for industry to use RTM as a tool ( i.e., as an “additional pair of eyes”) to improve safety and environmental protection during ongoing well operations, as recommended by several reports on the Deepwater Horizon incident. See 80 FR 21520. BSEE does not intend that onshore personnel monitoring the RTM data would have operational control over the rig based on the data; rather, BSEE intends that onshore personnel could use RTM data to help rig personnel conduct their operations safely and to assist rig personnel in identifying and evaluating abnormalities and unusual conditions before they become critical issues. In addition, BSEE expects operators to review stored RTM data after operations are complete in order to improve well-control efficiency, training, and incident investigation. Reviewing past data can help improve operations ( e.g., understanding well conditions in certain geological formations assists in the collection and use of offset well data to make drilling in similar formations more efficient). There are many other aspects of RTM that were not addressed in the proposed rule, and that are not addressed in this final rule. In this rulemaking, BSEE is laying the groundwork for further development and use of RTM to help industry to continue improving offshore safety and environmental protection. Industry, academia, BSEE and others are studying and developing new RTM technology and processes, which continues to evolve. BSEE may consider additional guidance or regulatory requirements for use of RTM, as appropriate, in later rulemakings. BSEE received multiple comments on these issues, expressing concerns with these proposed provisions and suggesting alternatives. A more detailed discussion of the RTM comments is found in section part VI.C of this document. However, some of the industry concerns with the proposed requirements include: • The meaning of proposed requirements to “immediately transmit” these RTM data and to maintain “continuous contact” between onshore personnel and rig personnel; • The proposed requirement that loss of “any real-time monitoring capability during operations” requires immediate notification of, and possible action by, the District Manager; and • The potential for an increase in rig personnel response time and a decrease in the accountability of the offshore personnel. In addition, several commenters suggested that BSEE require operators to develop specific RTM plans in lieu of some or all of the proposed requirements, or that the existence of such plans would justify BSEE eliminating some or all of the proposed RTM requirements, even if an RTM plan were not expressly required. BSEE considered all of the relevant comments and made several revisions and clarifications to the proposed RTM requirements in final § 250.724. The final rule removes or replaces several provisions that were perceived by commenters as overly prescriptive with more flexible, performance-based measures that better reflect BSEE's intention that operators use RTM as a tool to improve their own ability to prevent well control incidents while providing BSEE with sufficient access to RTM information to evaluate system improvements. For example, instead of requiring an operator to notify the District Manager immediately of any loss of RTM capabilities, as proposed, the final rule requires an operator to have an RTM plan that specifies how the operator will notify BSEE of any significant interruption in monitoring or RTM communications. The revisions to the final rule also clarify that BSEE did not intend to require that direct operational responsibility for well control be shifted from rig personnel to onshore RTM personnel. Specifically, the revisions to the proposed requirements, as reflected in the final rule include the following: • The phrase “all aspects of” was deleted from paragraphs (a)(1), (2), and (3). The deletion of that phrase provides for a more performance-based rule, pursuant to which the operator, based upon the particular rig configuration and situation, would determine the data to be collected. Further, the deletion of “all aspects of” provides more operator flexibility so as to reduce the probability of an increase in response time while maintaining the accountability of the offshore personnel. This revision also clarifies that RTM is intended to be used as a support tool for the existing rig-based chain of command and is not a substitute for the competency or well-control responsibilities of the rig personnel. • The word “data” was added to clarify the systems and tools from which real-time data must be gathered and monitored. BSEE also made the following revisions and clarifications in final § 250.724(b): • The phrase “barring unforeseeable or unpreventable interruptions in transmission” was added to address concerns about the interruption of the transmission of the data. • The word “immediately” was deleted with respect to transferring data to shore, and the phrase “during operations where they must be monitored [by qualified personnel] who must be in continuous contact with rig personnel during operations” was deleted. These revisions were made to address concern that mandatory onshore monitoring would result in an erosion of authority of, or shifting operational decision making away from, the rig-site personnel. These revisions also address concerns that mandatory onshore monitoring and continuous rig-to-shore contact might result in an increase in response time and a decrease in the accountability of the offshore personnel. They also clarify BSEE's intent that RTM involving onshore personnel serve as a support tool for the existing rig-based chain of command. BSEE also revised and clarified final § 250.724(c) by deleting the sentences that proposed that operators who lose any RTM capability during operations covered by the section, you must immediately notify the District Manager, and that the District Manager may require other measures until RTM capability is restored. BSEE replaced the deleted sentences with a performance-based requirement for operators to have an RTM plan, as suggested by several industry commenters, that addresses several of the issues that the proposed rule would have addressed through prescriptive language. For example, most of the commenters' concerns with proposed paragraph (c) appear to be based on the assumption that the proposed language would have required every interruption in RTM capabilities—no matter how brief or inconsequential—to be reported to the District Manager, and would have resulted in orders to suspend operations in every case. However, BSEE did not intend that proposed requirement to apply to minor or routine interruptions in RTM capabilities that pose no significant risk to safety or of a LWC. Accordingly, the final rule now requires operators to have RTM plans that include procedures for responding to and notifying BSEE of “significant and/or prolonged interruptions.” Thus, BSEE anticipates that the final rule will result in essentially the same results regarding interruptions that the proposed rule was intended to achieve, with no loss of safety or environmental protection as compared to the proposal. Specifically, the final rule requires that the RTM plan be made available to BSEE upon request and that the plan include descriptions of: • RTM technical and operational capabilities; • How the RTM data will be transmitted onshore, how the data will be labeled and monitored by qualified onshore personnel, and how the data will be stored onshore; • A description of procedures for providing BSEE access, upon request, to the RTM data including, if applicable, the location of any onshore data monitoring or data storage facilities; • Onshore monitoring personnel qualifications; • Methods and procedures for communications between rig and onshore personnel; • Actions that will be taken in case of loss of RTM capabilities or rig-to-shore communications; and • A protocol for responding to significant or prolonged interruptions of RTM capabilities or communications, including procedures for notifying the District Manager of such interruptions. 5. Potential Increased Severing Capability As discussed in the notice of proposed rulemaking, BSEE proposed a variety of requirements that would increase the likelihood that a BOP would be able to sever a drill string in an emergency situation in order to shut-in the well and prevent a catastrophic blowout. ( See 80 FR 21509-21510, 21529.) However, there are a variety of components in the drill string ( e.g., drill collars) that cannot be severed using currently available technology. ( See id. at 21509.) Accordingly, the notice of proposed rulemaking expressly stated that BSEE was considering including an additional provision in the final rule that would require operators to “install technology that is capable of severing any components of the drill string (excluding drill bits) . . . within 10 years from publication of the final rule.” ( See id. at 21529.) BSEE explained that this performance-based requirement would provide additional protection against potential LWC in an emergency by requiring installation of new technology that could sever components of a drill string ( e.g., drill collars) that cannot be severed using current shear rams. BSEE also explained that it was considering a 10-year timeframe for compliance with this potential requirement in order to provide time for manufacturers or operators to develop or select innovative or improved technologies or equipment to meet the requirement. BSEE then invited public comments and supporting data on a variety of key technical and economic questions and issues that would help BSEE decide whether to include such a requirement in the final rule. ( See id. at 21529-21530.) Only a small number of comments addressed this severing issue. Several industry commenters opposed the idea or stated that it would be extremely difficult and expensive to meet, and that even 10 years might not be long enough to come into compliance. One commenter suggested that BSEE require that shearable sections be designed into the drill string (instead of requiring that everything be shearable), and that a shearable section of the drill string must be across one of the shearing rams at all times. The same commenter asserted that shearable drill collars currently exist, but did not provide any additional technical or economic information supporting that assertion. Another commenter supported the requirement in general, but suggested that it should be implemented in less than 10 years. None of the comments, however, provided adequate relevant technical or economic data or other information to help BSEE determine whether to include the requirement in the final rule. Accordingly, although BSEE still believes that such a severing requirement could provide important additional controls to prevent future well-control events and catastrophic blowouts, such as the Deepwater Horizon incident, BSEE has decided that it needs more time and more information to make a final decision about whether to adopt such a severing requirement. Therefore, BSEE will review severing technology on a periodic basis, with the intention of concluding the review no later than seven years from the publication of this final rule. BSEE will conduct a retrospective review of this rule under E.O. 13563, according to DOI's regulatory review plan. If, after obtaining and considering additional information, BSEE decides to proceed with adoption of such a regulation, BSEE will propose to do so in a separate rulemaking document. 6. BOP Pressure Testing Interval BSEE received a number of comments on proposed § 250.737(a)(2), which proposed to harmonize the pressure testing interval for BOPs used in workovers and decommissioning operations (currently 7 days) with the existing 14-day interval for pressure testing BOPs used in drilling and completion operations. In the proposed rule, BSEE explained that increasing the test interval for workover and decommissioning BOPs from 7 days to 14 days could decrease wear and tear on those BOPs, and thus increase their durability and reliability in the long-term and otherwise potentially improve safety. ( See 80 FR 21511.) BSEE also explained that it expected that BOP equipment meeting the other proposed new requirements would perform more reliably than previous equipment, thus making 7-day testing for workover and decommissioning BOPs less crucial. ( See id . at 21524.) In addition, BSEE requested comments on whether the pressure testing interval for BOPs used in all types of operations should be 7 days, 14 days (as proposed), or 21 days. BSEE also requested comments on the potential cost implications of each of those intervals. ( See id . at 21511.) In its initial economic analysis for the proposed rule, BSEE estimated the potential savings from increasing the pressure testing interval from 7 to 14 days for workover and decommissioning BOPs to be about $150 million per year, and the potential cost savings that would result from increasing the testing interval for all BOPs from 14 to 21 days to be approximately $400 million per year. In response, one commenter suggested that BSEE require more frequent BOP pressure tests ( i.e., every 7 days for all BOPs used in Arctic OCS operations), and claimed that BSEE had not justified changing the 7-day testing requirement for workover and decommissioning BOPs to 14 days. However, most commenters, primarily from industry, supported increasing the pressure testing interval for workovers and decommissioning and recommended increasing the testing interval for all BOPs to 21 days. Commenters cited API Standard 53, which recommends a 21-day BOP test cycle for shear ram BOPs, as well as international industry best practices, in support of longer pressure test intervals. Multiple commenters also pointed out that less frequent testing would mitigate wear and tear on the equipment from the testing itself, and that wear and tear adversely affects long-term reliability of the equipment and thus increases the risks of equipment failure. Some commenters also referred to past joint industry research projects and studies, which they suggested support test intervals longer than 14 days. BSEE has long been involved with joint industry projects and studies on BOP reliability and, after reviewing the comments on the proposed rule, has concluded that increasing the test interval for workover and decommissioning BOPs from 7 to 14 days is appropriate in terms of decreasing wear and tear and increasing long-term reliability of those BOPs. BSEE and the industry now have substantial experience with the efficacy of the longstanding 14-day testing requirement for BOPs used in drilling and completion operations, and BSEE believes that testing decommissioning and workover BOPs every 14 days will avoid the extra wear and tear and safety risks inherent in 7-day testing and will not result in any diminution of safety and environmental protection as compared to 7-day testing. BSEE is not aware, however, of any new data that justifies increasing the BOP pressure testing interval for all BOPs from 14 days to 21 days. The previous studies and data on BOP testing frequency that were submitted to MMS prior to the Deepwater Horizon incident, as mentioned by some commenters, were not deemed by MMS sufficient to justify increasing the pressure testing interval from 14 to 21 days. In the proposed rule, BSEE explained that it was reevaluating this issue and requested additional data and technical analysis regarding the proposed pressure testing frequency requirements to determine if a uniform 21-day testing interval should be included in the final rule. Given the operational issues that had previously been brought to BSEE's attention by the industry, and the potential costs savings ($400 million dollars per year) that BSEE estimated could result from moving from 14-day to 21-day testing, BSEE anticipated that significant technical and economic comments would be submitted on this issue. Comments in support of such a change were submitted; however, these comments did not provide adequate data and information to reasonably support a 21-day testing interval at this time. BSEE is aware of concerns that the more frequently BOPs are tested, the more likely the equipment is to wear out prematurely; however, it does not automatically follow that every extension of test intervals always increases reliability, and thus safety and environmental protection, in the long-term. The industry commenters do not dispute that testing must occur at appropriate intervals to provide assurance that BOPs will function as intended when needed to prevent a blowout. BSEE's experience with 14-day pressure testing for drilling and completion BOPs indicates that it is effective for its purpose and that, in the absence of significant new information on longer test intervals, it is appropriate to retain that interval for such BOPs and to apply the same requirement to workover and decommissioning BOPs. BSEE believes that the provisions in the final rule that increase the exchange of data on equipment reliability, that improve the design, manufacturing, maintenance and repair of BOP equipment, and that require the use of BAVOs or other independent third-parties to verify and document BOP testing, repairs and maintenance will result in improved performance and reliability of BOPs in the future. However, in the absence of new data demonstrating that 21-day testing would be as protective as 14-day testing, BSEE has decided to finalize the proposed 14-day pressure testing requirement for BOPs used in all types of operations. In response to the Deepwater Horizon incident, industry attempted to voluntarily improve the overall reliability of well control equipment through better designs, improved manufacturing processes, better maintenance and repair procedures, and increased data sharing. BSEE will consider the possibility of adopting 21-day BOP testing when it receives adequate new (post- Deepwater Horizon ) data and analyses demonstrating that BOP reliability and capability, and personnel safety, are not adversely affected (or are actually improved) by pressure testing at 21-day intervals. This could include, for example, data from BOP testing and usage in OCS or other waters. BSEE will consider relevant data, along with any data indicating that the other requirements contained in this rule (such as BAVO verification), have increased overall BOP performance and reliability and decreased the risk of failure of the systems and components. In the meantime, any operator that believes its specific circumstances warrant a longer pressure test interval may seek approval from the District Manager to use alternate procedures or equipment under § 250.141. C. Other Differences Between the Proposed and Final Rules In addition to the significant changes discussed in the preceding section, BSEE has also made changes to the rule in response to comments suggesting that BSEE eliminate redundancy, clarify some potentially confusing language, streamline the regulatory text, and align certain provisions in the proposed regulatory text more closely with relevant terminology in API Standard 53 (where BSEE intended the proposed provisions to be consistent with that standard). In some cases, we agreed with and accepted specific wording changes suggested by the commenters, and in some cases we made changes based on our agreement with the commenters' basic suggestion, even though the commenter provided no specific alternative language or we did not agree with the specific wording suggested by the commenter. In still other cases, we made minor revisions to proposed provisions in order to correct grammatical errors, eliminate potential ambiguity, or to avoid confusion by further clarifying the intent of the proposed language. The revisions include the following: • In final § 250.292, we clarified the proposed language about pipeline free standing hybrid risers “on a permanent installation.” • In final § 250.421, we clarified the proposed language regarding cementing the liner lap and what actions are necessary when an operator is unable to meet the cementing requirements of the liner lap section. • In final § 250.462, we revised the language from “pressure holding” to “pressure containing” critical components. We also clarified language on excluding downhole safety valves. And we clarified the equipment that operators must make available to BSEE for inspection. We revised this section to clarify the differences between collocated equipment and SCCE ( e.g., collocated equipment includes dispersant injection equipment.) • In final §§ 250.518, 250.619, and 250.1703, we clarified that, for the purposes of those sections, permanently installed packers and bridge plugs must comply with the referenced industry standard. • In final § 250.703, we replaced “the most extreme service conditions” with “the maximum environmental and operational conditions” to which equipment may be exposed at a given well. • In final § 250.711, we clarified that the same well-control drill cannot be repeated consecutively with the same crew, in order to avoid overly narrow training for certain personnel and to improve proficiency in well-control procedures by a broader set of rig personnel without unduly limiting the operator's discretion to schedule important drills. • In final § 250.712, we changed the timeframe for informing BSEE of the rig movement from 72 hours to 24 hours' notice before movement. BSEE agreed with commenters that requiring 72 hour notice may have necessitated additional revisions to the submitted form due to the constant changes of operations affecting rig movements. Requiring a 24 hour notification provides a better indication of when a rig will move. • In final § 250.713, we deleted the reference to “lift boats” and made other minor changes to improve consistency in rig-related terminology. • In final § 250.715, we also revised the language to provide more consistency in rig-related terminology and to clarify the requirements for access to GPS data. • In final § 250.721, we clarified that operators must test the liner-top, instead of the liner-lap, and that the pressure testing of the entire well should not exceed 70 percent of the burst rating limit of the weakest component. • In final § 250.722, we clarified that calculations must be included if an imaging tool or caliper is used. • In final § 250.730, we: ○ Clarified that the lessee or operator must ensure that the BOP systems are designed, installed, maintained, inspected, tested and used properly (instead of the lessee or operator actually performing these actions themselves), since these actions are usually performed by contractors. ○ Clarified that the working pressure rating for annulars does not need to exceed MASP. ○ Clarified that the BOP system (instead of each ram) must be capable of closing and sealing the wellbore at all times and provide reliable means to handle well-control events. ○ Clarified paragraph (a)(2) to provide that the BOP systems must meet the provisions of the specified industry standards that apply to BOP systems. ○ Revised the failure reporting procedures in paragraph (c) to include submitting such reports to BSEE. ○ Clarified paragraph (d)(1) to remove the reference to the alternative compliance regulations at § 250.141. • In final § 250.732, we: ○ Revised paragraph (a) by extending the compliance date for BAVO-related requirements to 1 year from the date BSEE publishes a BAVO list and adding new paragraphs (a)(1) and (2). Final paragraph (a)(1) provides that, until the requirements to use BAVOs become effective, operators must use an independent third-party to provide the certifications, verifications, and reports that a BAVO must provide after the BAVO requirements become effective. Final paragraph (a)(2) clarifies the criteria for independent third-parties, based on the longstanding criteria in use under current regulations. ○ Revised paragraph (b)(1)(vi), by replacing “all testing results” with “relevant testing results.” ○ Revised paragraph (d)(6) to clarify that training for personnel who service, repair or maintain BOPs must cover “any applicable” OEM requirements. • In final § 250.733, we removed redundant requirements that are covered in other sections. • In final § 250.734, we: ○ Revised the ROV provisions to require opening and closing of ram locks, one pipe ram, and the Lower Marine Riser Package (LMRP) disconnect. ○ Clarified that the ROV crew must be capable of carrying out appropriate tasks during emergency operations. ○ Simplified paragraph (a)(6)(vi) by deleting a phrase that would have required a failsafe system to use “logic” that makes every step independent from the previous step, and inserting instead the words “once activated.” ○ Clarified in paragraph (a)(7), that if an operator chooses to “use” an acoustic control system there are applicable requirements to demonstrate that it will function in the proposed environment and conditions. ○ Clarified that control panels must have “enable” buttons or similar features to ensure two-handed operation. ○ Clarified that there must be a side outlet installed below the lowest sealing shear ram. ○ Clarified that, if there are dual annulars, a gas bleed line must be installed below the upper annular. ○ Revised the language regarding testing of the equipment after making repairs, and clarified the testing requirements under certain circumstances. • In final § 250.735, we revised paragraph (e), to clarify the required location of the kill line, and paragraph (g) to eliminate the proposed requirement for hydraulically operated locks for pipe rams on surface BOPs and to replace the proposed requirement for hydraulic locks on surface BOP blind shear rams with a requirement for remotely-operated locks. • In final § 250.736, we revised the kelly valve requirements to better reflect current practice and technology. • In final § 250.737, we: ○ Clarified, in paragraph (d)(2), that water must be used to do the initial test for surface BOP systems, but that drilling/completion/workover fluids may be used to conduct subsequent tests. ○ Clarified the requirements for testing pods between control stations. ○ Removed redundant provisions covered under other sections. • In final § 250.738, we: ○ Revised paragraph (a) by removing the requirement to notify the District Manager of problems or irregularities “including leaks”; however, these problems or irregularities must be recorded on the daily report, which must be made available to BSEE upon request. ○ Revised paragraph (e) to clarify that one set of pipe rams (instead of two) must be capable of sealing around the smaller size pipe. ○ Revised paragraph (f) to clarify the required testing of the connections if casing rams or casing shear rams are installed in a surface BOP stack. ○ Revised paragraph (l) to clarify the required testing of the wellhead/BOP connection if a test ram is to be used. ○ Revised paragraph (p) to clarify the requirements that apply if the bottom hole assembly needs to be positioned across the BOP. • In final § 250.739, we clarified personnel training and records requirements. • In final § 250.746, we added a reference to digital recorders, clarified the actions required when there are leaks associated with a BOP control system, and made minor changes to provide consistency in rig-related terminology. • In final §§ 250.414(k), 250.713(e), 250.714(e), 250.721(d) and (g)(3), 250.722(a)(1), 250.734(a)(7), 250.738(o), 250.740(g), 250.743(c), and 250.744(a), we clarified the purposes for which District Managers may require additional information, testing, or other procedures consistent with the purposes of those sections. VI. Discussion of Public Comments on the Proposed Rule In response to the proposed rule, BSEE received over 172 sets of comments from individual entities ( e.g., companies, industry organizations, non-governmental organizations, and private citizens). Some entities submitted comments multiple times. All relevant comments are posted at the Federal eRulemaking portal: http://www.regulations.gov . (To access the comments at that website, enter BSEE-2012-0002 in the Search box.) BSEE reviewed all comments submitted. Each of the following sections contains a brief summary of the relevant and significant comments as well as BSEE's responses. A. Requests for Extension of the Proposed Rule Comment Period Summary of comments: BSEE received requests from various stakeholders asking BSEE to extend the comment period on the proposed rule. The majority of those requests sought extensions of 120 days, which would have tripled the length of the original 60-day comment period. BSEE also received a written comment from another stakeholder urging BSEE not to extend the comment period because the proposed rule has been in development since the Deepwater Horizon incident, is based on recommendations resulting from that incident, and represents a critical regulatory improvement that should be finalized without delay. • Response: BSEE considered those requests and determined that extending the original 60-day comment period by an additional 30 days provided sufficient additional time for review of and comment on the proposal without unduly delaying a final rulemaking decision. The comment extension to the notice of proposed rulemaking was published in the Federal Register on June 3, 2015. ( See 80 FR 31560.) Summary of comments: Various commenters asserted that even the 90-day public comment period was inadequate for a rule of this technical complexity, and that additional time ( e.g., 120 days) was needed to properly address the substantial amount of technical content and complexity in this draft. They suggested that the comment period should be reopened and/or that BSEE publish a revised proposed rule for comment. • Response: BSEE believes that the 90-day comment period, which includes the 30-day extension granted by BSEE, was reasonable and sufficient under the Administrative Procedure Act (APA). The APA requires that agencies give “interested persons an opportunity to participate” in the rule making process through submission of written data, views or arguments. ( See 5 U.S.C. 553(c).) The APA does not prescribe the number of days that an agency must allow for written comments, and an agency's decision on comment period length is generally deferred to unless it is arbitrary and capricious. ( See 5 U.S.C. 706(2).) B. Summary of General Comments on the Proposed Rule 1. Comments Supporting the Proposed Rule Summary of comments: Multiple commenters commended the efforts by BSEE to improve safety and environmental protection and expressed their support for many of the changes in the proposed rule. • Response: It is BSEE's continued mission to promote safety, protect the environment, and conserve resources offshore through vigorous regulatory oversight and enforcement. This final rule is an important step toward better well control and improved safety and environmental protection. 2. Legal Comments Summary of comments: Several commenters claimed that BSEE failed to incorporate the principles of best available and safest technologies (BAST) reflected in OCSLA, resulting in requirements that are arbitrary, not reasonable or practicable, not economically or technically feasible, less safe, and more obstructive to OCS oil and gas development, in violation of the OCSLA-mandated balance between safety and environmental protection and expeditious and orderly development of OCS resources. • Response: BAST requirements, as set out in OCSLA and its implementing regulations ( see 30 CFR 250.107) are the product of specific BSEE analyses and determinations. Existing BSEE regulations and this final rule contain numerous technology requirements, all of which were adopted through notice and comment rulemaking. The proposed rule explained the justifications for codifying the technological requirements in the final rule, many of which were derived from recommendations based on exhaustive investigations and reports on the Deepwater Horizon incident, and on input from experts representing equipment manufacturers, the offshore oil and gas industry, government, academia, and environmental organizations focused on identifying appropriate technological standards. BSEE believes that the requirements in this regulation provide an appropriate level of safety. BSEE may make a separate determination in the future related to the use of BAST, pursuant to OCSLA, if supplemental requirements are necessary. Summary of comments: Several industry commenters claimed that certain provisions in the rule could render leases uneconomical to operate, thereby requiring a Takings Implication Analysis (TIA) by BSEE under Executive Order (E.O) 12360, and potentially amounting to a breach of contract by DOI. • Response: By their own terms, OCS oil and gas leases expressly state that they are subject to regulations promulgated after lease issuance, including the types of regulatory action reflected in this final rule. Accordingly, the adoption of this final rule is consistent with lessees' rights to conduct operations on the OCS—which are derived entirely from their lease interests—and thus do not amount to a breach of contract or a taking under the Fifth Amendment. As a result, a TIA is not necessary. E.O. 12630 requires executive agencies to review agency actions, including rulemakings, that have takings implications ( i.e., actions that, if implemented, could effect a taking) to prevent unnecessary takings and to identify and discuss any significant takings implications and the agency's conclusions on the takings issues. In this case, the terms of all OCS oil and gas leases allow BSEE to promulgate new rules, pursuant to OCSLA, without violating the rights created by the lease contracts. Specifically, leases issued prior to 2010 state: This lease is issued pursuant to the Outer Continental Shelf Lands Act. . . . The lease is issued subject to the Act; all regulations issued pursuant to the Act and in existence upon the Effective Date of this lease; all regulations issued pursuant to the statute in the future which provide for the prevention of waste and conservation of the natural resources of the Outer Continental Shelf and the protection of correlative rights therein, and all other applicable statutes and regulations. Leases issued since 2010 likewise provide that: This lease is subject to [OCSLA], regulations promulgated pursuant thereto, . . . and those . . . regulations promulgated thereafter, except to the extent they explicitly conflict with an express provision of this lease. It is expressly understood that amendments to existing . . . regulations . . . as well as the . . . promulgation of new regulations, which do not explicitly conflict with an express provision of this lease may be made and that the Lessee bears the risk that such may increase or decrease the Lessee's obligations under the Lease. None of the provisions of this rule explicitly conflict with any express provisions of OCS oil and gas leases. The Supreme Court and other Federal courts have interpreted the relevant lease language to mean that “[a] change to an OCSLA regulation does not breach the express terms of the lease language.” Century Exploration New Orleans, LLC v. United States, 745 F.3d 1168, 1178 (Fed. Cir. 2014), citing Mobil Oil Exploration & Production Southeast, Inc. v. United States, 530 U.S. 604, 616 (2000); Century Exploration New Orleans, LLC v. United States, 110 Fed. Cl. 148, 164-66 (2013) (the lease language “allocates the risk of certain legal changes—future regulations issued pursuant to OCSLA—to [lessees]”). This conclusion is in no way dependent upon the impacts of such a rulemaking on the economics of lease development. The express language of the leases (in sections 10 and 12) likewise requires that the lessee comply with all applicable regulations, and OCSLA expressly provides that regulations promulgated pursuant to the statute apply to both new and existing leases as of their effective date. 43 U.S.C. 1334(a). Because all changes to the regulatory language implemented through this rule are made pursuant to OCSLA, they are expressly incorporated into the terms of the leases and thus consistent with lessees' rights thereunder. In light of the fact that the entirety of lessees' rights to conduct the impacted operations on the OCS are derived from their leases, regulation that is consistent with those lease rights likewise cannot amount to an unconstitutional taking of those lease rights. Accordingly, promulgation of this rule does not amount to a breach of any lease terms or a taking of any rights derived from OCS leases. Summary of comments: Some commenters raised issues concerning the World Trade Organization's (WTO's) Technical Barriers to Trade Agreement (TBT Agreement). In particular, the commenters asserted that purported inconsistencies between the proposed rules and API Standard 53 require compliance with notification procedures under the TBT Agreement. • Response: The TBT Agreement seeks to avoid unnecessary obstacles to international trade, in part by requiring that technical regulations and conformity assessment procedures be consistent with international standards promulgated by international standards developing organizations. The proposed rule does not create a technical barrier to trade because it is neutral as to the national origin of regulated equipment. The proposed rule did not, and this final rule will not, discriminate in favor of U.S.-fabricated equipment. The final rule is equally applicable to all relevant equipment, regardless of the equipment's country of origin. Accordingly, BSEE's proposed rule did not, and the final rule does not, create an unnecessary technical barrier to trade. 3. Arctic-Related Comments Summary of comments: Multiple commenters recommended extending certain equipment, testing and monitoring requirements in the proposed rule to all operations on the Arctic OCS, where some of those operations would not have been covered under the terms of the proposed requirements. For example, some commenters recommended that BSEE require a second set of blind shear rams to be installed in the BOP stack for all operations in the Arctic, including surface BOPs on gravel and ice islands and bottom-founded structures in the Arctic, even though the proposed requirement was only intended to apply to surface BOPs on floating facilities ( See § 250.733(b)(1)). Commenters also suggested that all BOPs used on the Arctic OCS undergo independent verification by a qualified third-party organization, and that Arctic operators submit to BSEE an annual Mechanical Integrity Assessment (MIA) Report prepared by a BAVO, even though BSEE proposed that the MIA Report requirement apply only to subsea BOPs, BOPs in HPHT environments, and surface BOPs on floating facilities. The commenters asserted that extending these requirements would ensure that each BOP used on the Arctic OCS is fit for Arctic OCS service. Commenters also suggested extending to all Arctic OCS facilities: the proposed requirements in § 250.724 for RTM for subsea BOPs, BOPs in HPHT environments, and surface BOPs on floating facilities; and the proposed Source Control and Containment requirements in proposed § 250.462 for subsea BOPs or surface BOPs on floating facilities. Some commenters also requested that BSEE revise the existing regulations to strengthen equipment and operational requirements for equipment used on the Arctic OCS. These suggestions included: Requiring Arctic operators to submit a cementing protocol and quality assurance plan, prepared by an experienced Arctic drilling engineer, as part of their APD; daily well activity reporting requirements for the Arctic OCS; and mandatory use of cement evaluation tools and temperature logs. Some of the comments were expressly related to provisions in BSEE's proposed rule, “Requirements for Exploratory Drilling on the Arctic Outer Continental Shelf.” ( See 80 FR 9916 (Feb. 24, 2015).) The commenters stated that they submitted the same comments to BSEE in response to that proposed rule. • Response: The requirements in this final rule apply to any OCS facility in any BSEE region (GOM, Pacific, Alaska), including an Arctic OCS facility, that meets the general conditions for applicability stated in the specific regulatory provisions. For example, some provisions (such as § 250.730—What are the general requirements for BOP systems and system components?) apply nationwide to all BOPs on all OCS facilities, including any facility with a BOP on the Arctic OCS. Other requirements apply only to specific types of facilities or equipment or BOP systems (such as the requirements in § 250.733, which apply only to surface BOP stacks, and the requirements in § 250.734, which apply only to subsea BOPs). And some provisions apply to any facility or BOP that meets specific conditions, such as § 250.732(d), which requires an operator to submit an annual MIA report for any subsea BOP, BOP in an HPHT environment, or surface BOP on a floating facility. In any case, all of the provisions in this final rule apply without regard to the OCS region in which the facility or BOP is operating. BSEE recognizes that the Arctic OCS presents a uniquely challenging operating environment, characterized by extreme environmental conditions, geographic remoteness, and a relative lack of fixed infrastructure and existing operations. However, many of the comments submitted on the Arctic OCS issues are outside the scope of this well-control rulemaking. BSEE has decided to address Arctic-specific issues in separate rulemakings, guidance documents, or on a case-by-case basis as needed. Most of the comments related to the Arctic that were submitted under this rulemaking were also submitted in response to the proposed Arctic OCS exploratory drilling rule proposed in February 2015 and will be considered by BSEE in that rulemaking. 4. General Comments a. “Grandfathering” of Certain Equipment Requirements Summary of comment: Multiple commenters asserted that it is not clear whether existing facilities will be “grandfathered in,” ( i.e., that the final requirements would apply only to new facilities or equipment installed after the final rule's effective date), or whether existing facilities will have to comply with all provisions of the final rule, even if that requires, for example, installing new equipment or retrofitting existing equipment, which the commenters claimed would be very expensive and burdensome. Similarly, some commenters asserted that it is not clear whether existing equipment already under construction or in fabrication will have to comply with the new regulations in the event that the new regulations are published or become effective during or after fabrication, but prior to startup of new facilities or actual installation of the equipment. The commenters asserted that, under this interpretation, compliance may not be possible to achieve without significant delay and associated costs. A commenter stressed that application of manufacturing specifications ( e.g., API Spec. 16A, Spec. 16C, and Spec. 16D), incorporated by reference in certain provisions of this rule, to existing equipment would effectively preclude the use of such equipment. The commenter also claimed that BSEE had not considered the cost of application of those standards in the initial economic analysis for the proposed rule. • Response: During the rulemaking process, BSEE makes a determination about how or whether new and revised regulations will apply to existing operations, equipment, and facilities during the rulemaking process. As a general matter, OCSLA provides that all regulations promulgated thereunder (including this rule) “shall, as of their effective date, apply to all operations conducted under a lease issued or maintained under” OCSLA. (43 U.S.C. 1334(a).) When BSEE decides to exempt existing operations, equipment, or facilities from a specific provision, BSEE makes that clear in the regulatory text or relevant preamble discussions for the rule. In this rulemaking, each of the specific requirements for equipment or facilities will apply to the equipment or facilities that are described in that provision, without regard to whether the facility or equipment already exists, unless specifically stated otherwise. For example, (as discussed elsewhere in this document), § 250.733(b)(2) of the final rule requires use of a dual bore riser configuration on facilities that plan to use surface BOPs on floating production facilities, if risers are installed 90 or more days after publication of the final rule ( e.g., at the effective date of the rule). This means that existing surface BOPS on floating facilities using single bore risers installed less than 90 days after the publication of the final rule ( e.g., before the effective date of the rule) are not required to be retrofitted with dual bore risers. BSEE notes that many of the requirements in this final rule are not new, but are the same as or very similar to longstanding requirements in the existing regulations. Thus, those requirements will simply continue to apply to existing facilities or equipment. In addition, several of the most significant new requirements in this rule do not require compliance for several years—or longer in some cases (see part III of this document)—so the impact of those requirements on existing facilities or equipment will be substantially mitigated by those extended compliance periods ( e.g., some equipment potentially affected by some new requirements may already be due for replacement or major updates by the time such new requirements take effect). If there are unique circumstances that indicate that use of some equipment or procedures, other than as specified in this final rule, may be warranted, an operator may seek approval to use alternate equipment or procedures under existing § 250.141, if the operator can demonstrate that such equipment or procedures will provide a level of safety and environmental protection that equals or surpasses these requirements. b. Requests for Additional Workshops Summary of Comments: Numerous commenters recommended that BSEE hold additional workshops related to this rulemaking. Most of those commenters recommended that BSEE postpone finalizing the proposed rule, reopen the public comment period, and hold workshops during the new comment period before adopting a final rule. Some commenters, however, suggested that BSEE hold workshops after adopting the final rule, in order to further the industry's understanding of the provisions of this rulemaking. Commenters discussed a number of issues that they asserted warranted such workshops. One commenter stated that industry concerns over perceived technical flaws in, and potentially significant impacts from, the proposed rule, and the limited time provided to comment on the proposal, warranted workshops or some other form of engagement between BSEE and industry to make sure that the regulations are technically viable, provide optimum risk management, and are in the best interest of America's economy and domestic energy security. A commenter expressed concerns that the proposed rule, as written, would not achieve BSEE's actual goals. This commenter suggested that BSEE should arrange workshops with industry to discuss the meanings of the proposed rules and revise the rules to improve safety while reducing unintended consequences. • Response: As previously discussed in this document, BSEE actively engaged—in meetings, training, workshops and other forums—with many stakeholders, including industry, for several years prior to and during development of the proposed rule. In particular, BSEE convened Federal decision-makers and stakeholders from the OCS industry, academia, and other entities at a public forum on offshore energy safety on May 22, 2012, to discuss ways to address well-control concerns arising from the Deepwater Horizon incident investigations. Those investigations and the May 2012 forum resulted in numerous recommendations to enhance safety and environmental protection of offshore operations by improving well control and BOP performance. BSEE recognized the importance of collecting the best ideas, from all perspectives, on the prevention of well-control incidents and blowouts to assist BSEE in developing this rule. This included industry's valuable knowledge and skillsets. BSEE received significant input and specific recommendations from many industry groups, operators, equipment manufacturers, academics and environmental organizations as a result of the 2012 forum. Subsequently, BSEE sought and received additional input on potential means to improve well control through BSEE attendance at industry and public conferences, industry standards committee meetings, and BSEE's own standards workshops. BSEE also invited industry assessments of BSEE-funded technology research projects related to well control. BSEE conducted at least 50 meetings with various companies, trade associations, regulators, and other stakeholders interested in well control as part of this process. BSEE considered all of this input in developing the proposed rule published in April 2015. ( See 80 FR 21508-21509.) Subsequently, at the request of several commenters, including industry commenters, BSEE extended the comment period for the proposed rule to 90 days, so commenters would have even more time to develop and present their views and relevant information. Subsequently, BSEE received over 170 comments on the proposed rule, some extremely detailed, covering almost every section of the proposed rule, and hundreds of which related to specific technical, economic and other issues. Many of the comments were submitted by members or representatives of the offshore oil and gas industry, as well as environmental groups, academics, other Federal agencies, and interested members of the public. BSEE subject matter experts (including experienced engineers and economists) carefully considered all of the relevant and significant comments in developing this final rule. As discussed elsewhere in this document, BSEE not only responded to those comments, but made a number of revisions to the final rule to address concerns or information described in the comments. In light of all of these efforts, BSEE does not agree with the commenters that urged BSEE to delay this final rule pending more workshops. BSEE intends to stay fully engaged with the affected industry and other stakeholders as this rule is implemented, and expects to participate in future meetings and workshops where the issues in this rulemaking will continue to be discussed. As experience and additional information are gained under this rule, BSEE will both provide guidance and clarification on this rule, as necessary. c. Licensed Engineers Summary of Comments: A commenter recommended that BSEE require the use of a licensed engineer at every stage during the entire life-cycle of OCS platforms, including design, development, construction, commissioning, maintenance, operations and salvage. The commenter noted that licensed professional engineers (PEs) are required by law to hold public safety paramount. • Response: BSEE does not agree that the use of PEs should be required more often than already provided for in this final rule and the existing regulations. Several provisions of the final rule require PE certifications. For example, final § 250.428(b) requires certification by a PE for changes to casing setting depth or hole interval drilling depth and changes to the well program due to an inadequate cement job. There are also several provisions in the existing regulations ( e.g., § 250.420(a)(6)(i)) that require, or allow, the use of PEs and that are unchanged by this final rule. In addition, the requirements in this final rule for verifications and certifications by a BAVO or other independent third-party will help ensure that the safety and environmental protection purposes of this rule will be achieved without the need for additional requirements for use of PEs. d. Requests for Shorter or Longer Compliance Periods Summary of Comments: Some commenters observed that the proposed rule was published more than five years after the Deepwater Horizon incident. The commenters voiced support for the proposed effective date of 3 months following publication of the final rule for most of the proposed rule's requirements, since most, but not all, operators are already using equipment and procedures consistent with a majority of the proposed requirements. The commenters expressed concern with the proposal for longer compliance periods for several key requirements, including: 3 years for RTM; 5 years for shear rams on subsea BOPs and on surface BOPs on floating facilities; and 7 years for a mechanism coupled with each shear ram that centers drill pipe during shearing operations. One of the commenters noted it could be more than sixteen years after the Deepwater Horizon incident before BSEE finalizes and the industry implements critical components of offshore drilling safety. The commenters urged BSEE to shorten these compliance periods to enhance safety and environmental protection in an expeditious manner. BSEE received other comments on the proposed rule, however, that raised concerns that the proposed compliance periods for certain provisions were too short. Those concerns included: Availability of required equipment; time needed to plan and install the equipment; and time needed to develop new or alternative equipment to meet the requirements. • Response: BSEE agrees that it is extremely important to move ahead with these final rules to implement many of the recommendations from the Deepwater Horizon investigations and to help prevent catastrophic events from occurring again. BSEE considered a number of factors in identifying appropriate compliance periods for the various provisions in this rule, including information from public commenters on those requirements and information obtained, among other activities, from prior interactions with stakeholders, involvement in development of industry standards, and evaluation of current technology. BSEE considered all of the comments regarding shortening and lengthening the compliance periods and determined that most of the proposed compliance periods were appropriate. BSEE did, however, determine that several requirements warranted longer compliance periods, as discussed in part III of this document. BSEE believes that compliance with these rules will improve well control, safety and environmental protection in a timely manner for the near and long term. 5. Contractor/Operator/Manufacturer Responsibilities Summary of comments: Several commenters expressed uncertainty regarding potential responsibilities and liabilities of contractors and individuals performing regulated activities. • Response: These final regulations do not alter BSEE's existing position and interpretations with respect to the parties responsible for complying with applicable regulations and related requirements. The lessee, operator (if one has been designated), and the person that actually performs an activity (which includes contractors) to which a particular provision of a regulation, lease, permit, or plan applies are jointly and severally responsible for complying with that provision. ( See § 250.146(c).) Regulatory compliance is a fact-specific and context-specific matter, dependent upon that contractor's actual scope of activities and responsibilities (which is typically a matter of private contract with the lessee/operator), and is therefore not susceptible to general characterization. BSEE's responses to specific issues regarding responsibilities for compliance follow. Summary of comments: Some commenters asserted that if contractors and individuals (along with lessees, operators, et al. ) are jointly and severally responsible for compliance, proposed § 250.107(a)(4)—requiring lessees, holders of operating rights, designated operators and certain others to comply with all lease, plan, and permit terms and conditions—would implicitly require contractors and other individuals to ascertain all lease, plan, and permit terms and conditions, and potentially would make the contractor and individuals responsible for compliance with all such terms and conditions. The commenters asked if that is what BSEE intended. • Response: Under existing § 250.146(c), the lessee, operator (if one has been designated), and the person actually performing an activity (including contractors or individuals) to which a particular regulation applies are jointly and severally ( i.e., equally) responsible for complying with that regulation. Therefore, actual performance of an activity is one of the triggers for the responsibility to comply with the associated requirements of lease, permit and plan terms and conditions of approvals. ( See, e.g., existing § 250.101(a).) Accordingly, under final § 250.107(a)(4), any person who actually performs an activity governed by [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A2016-08921. Public record. Not legal advice.