Vol. 81 Friday, No. 83 April 29, 2016

Part III

Department of the Interior

Bureau of Safety and Environmental Enforcement 30 CFR Part 250 Oil and Gas and Sulfur Operations in the Outer Continental Shelf—Blowout Preventer Systems and Well Control; Final Rule

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DEPARTMENT OF THE INTERIOR APM Application for Permit to Modify RIA Regulatory Impact Analysis BAST Best Available and Safest RIN Regulation Identifier Number Bureau of Safety and Environmental Technologies ROT Remotely Operated Tools Enforcement BAVO BSEE-Approved Verification ROV Remotely-Operated Vehicle Organization RP Recommended Practice BOP Blowout Preventer 30 CFR Part 250 RTM Real-Time Monitoring BOEM Bureau of Ocean Energy SBA Small Business Administration [Docket ID: BSEE–2015–0002; 15XE1700DX Management SBREFA Small Business Regulatory EEEE500000 EX1SF0000.DAQ000] BSEE Bureau of Safety and Environmental Enforcement Fairness Act of 1996 Enforcement SCCE Source Control and Containment RIN 1014–AA11 BSR Blind Shear Ram Equipment CFR Code of Federal Regulations Secretary Secretary of the Interior Oil and Gas and Sulfur Operations in CVA Certified Verification Agent SEM Subsea Electronic Module the Outer Continental Shelf—Blowout DHS Department of Homeland Security SEMS Safety and Environmental Preventer Systems and Well Control DOCD Development Operations Management Systems Coordination Document SIMOPS Simultaneous Operations AGENCY: Bureau of Safety and DOI Department of the Interior Spec. Specification Environmental Enforcement, Interior. DPP Development and Production Plan TAR Technical Assessment and Research DWOPs Deepwater Operations Plans ACTION: Final rule. TBT Agreement Technical Barriers to Trade ECD Equivalent Circulating Density Agreement EDS Emergency Disconnect Sequence SUMMARY: Bureau of Safety and TIA Takings Implication Analysis E.O. Executive Order TLPs Tension Leg Platforms Environmental Enforcement (BSEE) is EOR End of Operations Report finalizing new regulations to TVD True Vertical Depth EP Exploration Plan USCG United States Coast Guard consolidate into one part the equipment F Fahrenheit VBR Variable Bore Ram and operational requirements that are FOIA Freedom of Information Act VSL Value of a Statistical Life found in various subparts of BSEE’s FPSs Floating Production Systems WAR Well Activity Report regulations pertaining to offshore oil FPSO Floating Production, Storage, and WTO World Trade Organization and gas drilling, completions, Offloading Unit workovers, and decommissioning. This FSHR Free Standing Hybrid Risers Executive Summary final rule focuses on blowout preventer GOM Gulf of Mexico Following the devastating impacts of GOMR Gulf of Mexico region the April 20, 2010, Deepwater Horizon (BOP) and well-control requirements, GPS Global Positioning Systems including incorporation of industry HPHT High Pressure High Temperature incident on the Gulf of Mexico (GOM) standards and revision of existing IC Information Collection and the surrounding states and local regulations, and adopts reforms in the IEC International Electrotechnical communities, multiple investigations areas of well design, well control, Commission were conducted to determine the causes casing, cementing, real-time well ISO International Organization for of the incident and to make monitoring, and subsea containment. Standardization recommendations to reduce the The final rule also addresses and JIT Joint Investigation Team likelihood of a similar incident in the implements multiple recommendations LMRP Lower Marine Riser Package future. The investigative groups LWC Loss of Well Control included: resulting from various investigations of MASP Maximum Anticipated Surface the Deepwater Horizon incident. This Pressure —Department of the Interior (DOI)/ final rule will also incorporate guidance MAWHP Maximum Anticipated Wellhead Department of Homeland Security from several Notices to Lessees and Pressure (DHS) Joint Investigation Team; Operators (NTLs) and revise provisions MIA Mechanical Integrity Assessment —National Commission on the BP related to drilling, workover, MMS Minerals Management Service Deepwater Horizon Oil Spill and completion, and decommissioning MODUs Mobile Offshore Drilling Units Offshore Drilling; operations to enhance safety and NAE National Academy of Engineering —Chief Counsel for the National environmental protection. NAICS North American Industry Commission; and Classification System DATES: This final rule becomes effective NARA National Archives and Records —National Academy of Engineering. on July 28, 2016. Compliance with Administration Each investigation outlined several certain provisions of the final rule, NAS National Academy of Sciences recommendations to improve offshore however, will be deferred until the National Commission National Commission safety. BSEE evaluated the times specified in those provisions and on the BP Deepwater Horizon Oil Spill and recommendations and acted on a as described in Part III of the preamble. Offshore Drilling number of them quickly to improve The incorporation by reference of NIST National Institute of Standards and offshore operations, while BSEE’s Technology decision making with respect to other certain publications listed in the rule is NTLs Notices to Lessees and Operators approved by the Director of the Federal NTTAA National Technology Transfer and recommendations followed additional Register as of July 28, 2016. Advancement Act input from industry and other FOR FURTHER INFORMATION CONTACT: Kirk OCS Outer Continental Shelf stakeholders. Malstrom, Regulations and Standards OCSLA Outer Continental Shelf Lands Act In April 2015, BSEE proposed Branch, (202) 258–1518, or by email: OEM Original Equipment Manufacturer regulations to, among other things, [email protected]. OFR Office of Federal Register incorporate industry standards and NTL OIRA Office of Information and Regulatory guidance; consolidate into one part the SUPPLEMENTARY INFORMATION: Affairs existing equipment and operational List of Acronyms and References OMB Office of Management and Budget requirements that are found in various PEs Professional Engineers ANSI American National Standards ppg Pounds per gallon parts of BSEE’s regulations; to revise Institute psi Pounds per square inch and improve existing requirements for APA Administrative Procedure Act QA/QC Quality Assurance/Quality Control well design and control, casing and APD Application for Permit to Drill RCD Regional Containment Demonstration cementing; and to add new API American Petroleum Institute RFA Regulatory Flexibility Act requirements for real-time monitoring

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(RTM) and subsea containment. The (2) Revises the requirements for cost-beneficial. The estimated overall proposed regulations also addressed Deepwater Operations Plans (DWOPs), cost of the rule (outside those costs that many of the recommendations made by which are required to be submitted to are part of the economic baseline) over the previously listed investigative BSEE under specific circumstances, to 10 years will be exceeded by the time- bodies, which found a need to add requirements on free standing savings benefits to the industry resulting incorporate well-control best practices hybrid risers (FSHR) for use with from the revisions to the former to advance safety and protection of the floating production, storage, and requirements for BOP pressure testing environment. BSEE received over 176 offloading units (FPSO). frequency for workovers and public comments on the proposed rule, (3) Revises 30 CFR part 250, subpart decommissionings. In addition, the final and considered those comments in D, Oil and Gas Drilling Operations, to rule will also produce benefits to developing these final regulations. include requirements for: society, both quantifiable and The requirements in this final rule, —Safe drilling margins; unquantifiable, by reducing the including the revisions made to the —Wellhead descriptions; probability of well control incidents proposed regulations, reflect BSEE’s —Casing or liner centralization during involving oil spills. consideration of the comments and cementing; and Table of Contents BSEE’s commitment to address the —Source control and containment. recommendations made in the (4) Revises subparts E, Oil and Gas I. Background Deepwater Horizon reports. This final Well-Completion Operations, and F, Oil A. BSEE rulemaking: B. BSEE Statutory and Regulatory and Gas Well-Workover Operations, to Authority and Responsibilities (1) Incorporates all or designated include requirements for: C. Purpose and Summary of the portions of the following industry —Packer and bridge plug design; and Rulemaking standards: —Production packer setting depth. D. Availability of Incorporated Documents —American Petroleum Institute (API) for Public Viewing (5) Revises Subpart Q, E. Summary of Documents Incorporated by Standard 53, Blowout Prevention Decommissioning Activities, to include Equipment Systems for Drilling Wells, Reference requirements for: II. Organization of Subpart G Fourth Edition, November 2012; —Packer and bridge plug design; III. Discussion of Compliance Dates for the —API Recommended Practice (RP) —Casing bridge plugs; and Final Rule 2RD—Design of Risers for Floating —Decommissioning applications and IV. Issues Not Considered in this Rulemaking Production Systems and Tension-Leg reports. V. Discussion of Final Rule Requirements Platforms, First Edition, June 1998; A. Summary of Key Regulatory Provisions Reaffirmed May 2006, Errata June (6) Adds new subpart G, Well B. Summary of Significant Differences 2009; Operations and Equipment, and moves Between the Proposed and Final Rules 1. Safe drilling margin —API Specification (Spec.) Q1— existing requirements that were duplicated in subparts D, E, F, and Q 2. Accumulator systems Specification for Quality Management 3. BOP 5-year major inspection System Requirements for into new subpart G including: 4. Real-time monitoring (RTM) Manufacturing Organizations for the —Rig and equipment movement reports; 5. Potential increased severing capability Petroleum and Natural Gas Industry, —RTM; and 6. BOP pressure testing interval Eighth Edition, December 2007, —Revised BOP requirements; including: C. Other Differences Between the Proposed Effective Date: June 15, 2008; —Design and manufacture/quality and Final Rules —American National Standards assurance; VI. Discussion of Public Comments on the —Accumulator system capabilities and Proposed Rule Institute (ANSI)/API Specification A. Requests for Extension of the Proposed (Spec.) 11D1, Packers and Bridge calculations; Rule Comment Period Plugs Second Edition, Effective Date: —BOP and remotely operated vehicle B. Summary of General Comments on the January 1, 2010; (ROV) capabilities; Proposed Rule —API RP 17H, Remotely Operated Tools —BOP functions (e.g., shearing); 1. Comments supporting the proposed rule and Interfaces on Subsea Production —Improved and consistent testing 2. Legal comments Systems, First Edition, July 2004, frequencies; 3. Arctic-related comments Reaffirmed: January 2009; —Maintenance; 4. General comments —Inspections; 5. Contractor/Operator/Manufacturer —ANSI/API Spec. 6A, Specification for responsibilities Wellhead and Christmas Tree —Failure reporting; —Third-party verification; and 6. Economic analysis comments Equipment, Nineteenth Edition, July 7. Clarification of maximum anticipated 2004; Effective Date: February 1, 2005; —Additional submittals to BSEE, surface pressure (MASP) —ANSI/API Spec. 16A, Specification including up-to-date schematics. C. Section-By-Section Summary and for Drill-through Equipment, Third (7) Incorporates the guidance from Responses to Significant Comments on Edition, June 2004; several NTLs into subpart G for: the Proposed Rule —API Spec. 16C, Specification for —Global Positioning Systems (GPS) for VII. Derivation Tables VIII. Procedural Matters Choke and Kill Systems First Edition, Mobile Offshore Drilling Units Regulatory Planning and Review January 1993; (MODUs); (Executive Orders (E.O.) 12866 and —API Spec. 16D, Specification for —Ocean Current Monitoring; 13563)) Control Systems for Drilling Well —Using Alternate Compliance in Safety Regulatory Flexibility Act Control Equipment and Control Systems for Subsea Production Small Business Regulatory Enforcement Systems for Diverter Equipment, Operations; Fairness Act Second Edition, July 2004; and —Standard Reporting Period for the Unfunded Mandates Reform Act of 1995 —ANSI/API Spec. 17D, Design and Well Activity Report (WAR); and Takings Implication Assessment (E.O. —Information to include in the WARs 12630) Operation of Subsea Production Federalism (E.O. 13132) Systems—Subsea Wellhead and Tree and End of Operations Reports (EOR). Civil Justice Reform (E.O. 12988) Equipment, Second Edition; May Based on BSEE’s economic analysis of Consultation With Indian Tribes (E.O. 2011. available data, this final rule will be 13175)

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Paperwork Reduction Act (PRA) of 1995 operators 1 perform throughout the OCS. government economic damage claims National Environmental Policy Act of 1969 These well operations are the primary arising from the Deepwater Horizon (NEPA) focus of this rulemaking. incident were significant and have been Data Quality Act settled for another $5.9 billion.4 Effects on the Nation’s Energy Supply (E.O. C. Purpose and Summary of the 13211) In addition, despite new regulations Rulemaking and improvements in industry I. Background A primary purpose of this rulemaking standards and practices since the is to prevent future well-control A. BSEE Deepwater Horizon incident, which incidents, including major incidents have resulted in progress in certain BSEE was established on October 1, like the 2010 Deepwater Horizon areas of safety and environmental 2011, as part of a major restructuring of catastrophe. In addition to the loss of 11 protection, loss of well control (LWC) DOI’s offshore oil and gas regulatory lives, that single event resulted in the incidents are happening at about the programs to improve the management release of 134 million gallons of oil, same rate five years after that incident and oversight of, and accountability for, which spread over 43,300 square miles as they were before. In 2013 and 2014, activities on the Outer Continental Shelf of the GOM and 1,300 miles of shoreline there were 8 and 7 LWC incidents per (OCS). The Secretary of the Interior in several states. The environmental and year, respectively—a rate on par with (Secretary) announced the division of other damages caused by the Deepwater pre-Deepwater Horizon LWCs.5 Some of responsibilities of the former Minerals Horizon incident were immense and these LWC incidents have resulted in Management Service (MMS) among two have had long-lasting and widespread blowouts, such as the 2013 Walter Oil new bureaus and one office within DOI impacts on the Gulf and the affected and Gas incident that resulted in an in Secretarial Order No. 3299, issued on states. For example, as part of a explosion and fire on the rig. All 44 May 19, 2010. BSEE, one of the two new settlement agreement between BP and workers were safely evacuated, but the bureaus, assumed responsibility for Federal and state governments, BP has fire lasted over 72 hours and the rig was ‘‘safety and environmental enforcement agreed to pay over $8 billion for natural completely destroyed, resulting in a functions including, but not limited to, resources damages caused by the spill financial loss approaching $60 million. the authority to permit activities, and for the restoration of natural This incident occurred in part due to inspect, investigate, summon witnesses resources in the Gulf of Mexico region the crew’s inability to identify critical and [require production of] evidence[;] (GOMR).2 Those damages include well control indicators and to the failure levy penalties; cancel or suspend severe adverse effects on wildlife, of critical well control equipment.6 activities; and oversee safety, response wetlands and other wildlife habitat, Blowouts such as these can lead to and removal preparedness.’’ (See 76 FR recreation and tourism, and commercial much larger incidents that pose a 64431, October 18, 2011). fishing. The Deepwater Horizon Natural significant risk to human life and can Resource Damage Assessment (NRDA) B. BSEE Statutory and Regulatory cause serious environmental damage. Trustees have determined that ‘‘the Ensuring the integrity of the wellbore Authority and Responsibilities ecological scope of impacts from the and maintaining control over the BSEE derives its authority primarily Deepwater Horizon incident was pressure and fluids during well from the Outer Continental Shelf Lands unprecedented, with injuries affecting a operations are critical aspects of Act (OCSLA), 43 U.S.C. 1331–1356a. wide array of linked resources across protecting worker safety and the Congress enacted OCSLA in 1953, the northern Gulf ecosystem.’’ The environment. The investigations that authorizing the Secretary of Interior to released oil ‘‘was toxic to a wide range followed the Deepwater Horizon lease the OCS for mineral development, of organisms, including fish, incident, in particular, documented and to regulate oil and gas exploration, invertebrates, plankton, birds, turtles, gaps or deficiencies in the OCS development, and production and mammals . . . [and] caused a wide regulatory programs and made operations on the OCS. The Secretary array of toxic effects, including death, numerous recommendations for has delegated authority to perform disease, reduced growth, impaired improvements. Accordingly, on April certain of these functions to BSEE. reproduction, and physiological 17, 2015, BSEE proposed to consolidate To carry out its responsibilities, BSEE impairments that made it more difficult its existing well-control rules into one regulates offshore oil and gas operations for organisms to survive and subpart of the regulations, and to adopt to enhance the safety of offshore reproduce.’’ 3 In addition, state and local new and revised regulatory exploration and development of oil and requirements that address many of those gas on the OCS and to ensure that those 1 BSEE’s regulations at 30 CFR part 20 generally recommendations, including those operations protect the environment and apply to ‘‘a lessee, the owner or holder of operating related to BOP system design, implement advancements in technology. rights, a designated operator or agent of the lessee(s) performance, and reliability. (See 80 FR . . .’’ covered by the definition of ‘‘you’’ in BSEE also conducts onsite inspections § 250.105. For convenience, this preamble will refer 21504.) to assure compliance with regulations, to all of the regulated entities as ‘‘operators’’ unless lease terms, and approved plans. otherwise indicated. impacts from the Deepwater Horizon incident may Detailed information concerning BSEE’s 2 A summary and details of the recently approved be found at: http:// regulations and guidance to the offshore natural resources damages settlement between BP www.gulfspillrestoration.noaa.gov/restoration- and Federal and state governments are available at planning/gulf-plan/. oil and gas industry may be found on www.doi.gov/deepwaterhorizon and at http:// 4 https://www.justice.gov/enrd/deepwater- BSEE’s website at: http://www.bsee.gov/ www.justice.gov/enrd/deepwater-horizon. horizon. Regulations-and-Guidance/index. 3 Deepwater Horizon NRDA Trustees, Final 5 See http://www.bsee.gov/uploadedFiles/BSEE/ BSEE’s regulatory program covers a Programmatic Damage Assessment and Restoration BSEE_Newsroom/Publications_Library/ Plan and Final Programmatic Environmental Impact Annual_Report/ wide range of facilities and activities, Statement, at p. 1–14–1–15. On March 22, 2016, the BSEE%202014%20Annual%20Report.pdf. including drilling, completion, NRDA Trustees issued a Record of Decision setting 6 See BSEE, DOI, Investigation of Loss of Well workover, production, pipeline, and forth the basis for the Trustees’ decision to select Control and Fire South Timbalier Area Block 220, decommissioning operations. Drilling, the comprehensive, integrated ecosystem Well. No. A–3 OCS–G24980—23 July 2013 (July completion, workover, and restoration alternative (described in Final PDARP/ 2015), at http://www.bsee.gov/uploadedFiles/BSEE/ PEIS Sections 5.5 and 5.10). More details regarding Enforcement/Accidents_and_Incidents/ decommissioning operations are types the findings of the Federal and state Deepwater Panel_Investigation_Reports/ of well operations that offshore Horizon NRDA Trustees as to natural resources ST%20220%20Panel%20Report9_8_2015.pdf.

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Because BOP equipment and systems BSEE may incorporate these standards publications/government-cited-safety- are critical components of many well into its regulations without republishing documents.7 operations, BSEE recognized that it was the standards in their entirety in the For the convenience of members of important to collect the best ideas on Code of Federal Regulations (CFR), a the viewing public who may not wish the prevention of well-control incidents practice known as incorporation by to purchase or view these incorporated and blowouts to assist in the reference. The legal effect of documents online, they may be development of the proposed rule. This incorporation by reference is that the inspected at BSEE’s offices, 45600 included the knowledge, skillset, and incorporated standards become Woodland Road, Sterling, Virginia experience possessed by the offshore oil regulatory requirements. This 20166; phone: 703–787–1665; or at the and gas industry. Accordingly, BSEE incorporated material, like any other National Archives and Records participated in meetings, training, and properly issued regulation, has the force Administration (NARA). For workshops with industry, standards and effect of law, and BSEE holds information on the availability of this setting organizations, and other operators, lessees and other regulated material at NARA, call 202–741–6030, stakeholders in developing the proposed parties accountable for complying with or go to: http://www.archives.gov/ rule. (See 80 FR 21508–21509.) the documents incorporated by federal-register/cfr/ibr-locations.html. The proposed rule discussed in detail reference in our regulations. We topics such as: currently incorporate by reference over E. Summary of Documents Incorporated • Implementing many of the 100 consensus standards in BSEE’s by Reference recommendations related to well- regulations governing offshore oil and This rulemaking is substantive in control equipment. gas operations (see 30 CFR 250.198). • terms of the content that is explicitly Increasing the performance and Federal regulations, at 1 CFR part 51, stated in the rule text itself, and it also reliability of well-control equipment, govern how BSEE and other Federal incorporates by reference certain especially BOPs. agencies incorporate various documents • technical standards and specifications Improving regulatory oversight over by reference. Agencies may only concerning BOPs and well control. A the design, fabrication, maintenance, incorporate a document by reference by brief summary of each standard or inspection, and repair of critical publishing in the Federal Register the equipment. specification follows. • document title, edition, date, author, Gaining information on leading and publisher, identification number, and API Standard 53—Blowout Prevention lagging indicators of BOP component other specified information. The Equipment Systems for Drilling Wells failures, identifying trends in those Director of the Federal Register must failures, and using that information to approve each publication incorporated This standard provides requirements help prevent incidents. by reference in a final rule. for the installation and testing of • Ensuring that the industry uses Incorporation by reference of a blowout prevention equipment systems recognized engineering practices, as document or publication is limited to whose primary functions are to confine well as innovative technology and the specific edition cited by the agency well fluids to the wellbore, provide techniques to increase overall safety. in the final rule and approved by the means to add fluid to the wellbore, and To help ensure the development of allow controlled volumes to be removed effective regulations, the proposed rule Director of the Federal Register. BSEE incorporates by reference in its from the wellbore. BOP equipment used a hybrid regulatory approach systems are comprised of a combination incorporating prescriptive requirements, regulations many oil and gas industry standards in order to require of various components that are covered where necessary, as well as many by this document. Equipment performance-based requirements. BSEE compliance with those standards in offshore operations. When a copyrighted arrangements are also addressed. The recognizes the advantages and components covered include: BOPs disadvantages of both approaches and publication is incorporated by reference into BSEE regulations, BSEE is obligated including installations for surface and understands that each approach could subsea BOPs; choke and kill lines; be effective and appropriate for specific to observe and protect that copyright. BSEE provides members of the public choke manifolds; control systems; and circumstances. auxiliary equipment. A full discussion of these topics, with website addresses where these along with other background and standards may be accessed for This standard also provides new regulatory history, is contained in the viewing—sometimes for free and industry best practices related to the use notice of proposed rulemaking (see 80 sometimes for a fee. Standards of dual shear rams, maintenance and FR 21504), which may be found on development organizations decide testing requirements, and failure BSEE’s website at http://www.bsee.gov/ whether to charge a fee. One such reporting. Regulations-and-Guidance/Regulations- organization, API, provides free online Diverters, shut-in devices, and In-Development/, and in the public public access to review its key industry rotating head systems (rotating control docket for this rulemaking at: http:// standards, including a broad range of devices) whose primary purpose is to www.regulations.gov (in the Search box, technical standards. These standards safely divert or direct flow rather than enter BSEE–2015–0002, then click represent almost one-third of all API to confine fluids to the wellbore are not ‘‘search’’). standards and include all that are safety- addressed. Procedures and techniques related or are incorporated into Federal for well control and extreme D. Availability of Incorporated regulations. Several of those standards temperature operations are also not Documents for Public Viewing are incorporated by reference in this included in this standard. BSEE frequently uses standards (e.g., final rule. In addition to the free online availability of these standards for codes, specifications, RPs) developed 7 To review these standards online, go to the API through a consensus process, facilitated viewing on API’s website, hardcopies publications website at: http://publications.api.org. by standards development organizations and printable versions are available for You must then log-in or create a new account, and with input from the oil and gas purchase from API. The API website accept API’s ‘‘Terms and Conditions,’’ click on the address is: http://www.api.org/ ‘‘Browse Documents’’ button, and then select the industry, as a means of establishing applicable category (e.g., ‘‘Exploration and requirements for activities on the OCS. publications-standards-and-statistics/ Production’’) for the standard(s) you wish to review.

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API RP 2RD—Design of Risers for design, design verification and systems for diverter equipment are Floating Production Systems and validation, materials, documentation included in the specification. Control Tension-Leg Platforms and data control, repair, shipment, and systems for drilling well-control This standard addresses structural storage. equipment typically employ stored energy in the form of pressurized analysis procedures, design guidelines, ANSI/API Spec. 16A—Specification for hydraulic fluid (power fluid) to operate component selection criteria, and Drill-through Equipment typical designs for all new riser systems (open and close) the BOP stack This specification defines used on Floating Production Systems components. For deepwater operations, requirements for performance, design, (FPSs) and Tension-Leg Platforms subsea transmission of electric/optical materials, testing and inspection, (TLPs). The presence of riser systems (rather than hydraulic) signals may be welding, marking, handling, storing and within an FPS has a direct and often used to shorten response times. The shipping of BOPs and drill-through significant effect on the design of all failure of these controls to perform as equipment used for drilling for oil and other major equipment subsystems. This designed can result in a major well- gas. It also defines service conditions in RP includes recommendations on: (1) control event. As a result, conformance terms of pressure, temperature and Configurations and components; (2) to this specification is critical to wellbore fluids for which the equipment general design considerations based on ensuring that the BOPs and related will be designed. This standard is environmental and functional equipment will operate in an applicable to, and establishes requirements; and (3) materials emergency. requirements for, the following specific considerations in riser design. equipment: Ram BOPs; ram blocks, ANSI/API Spec. 17D—Design and API Spec. Q1—Specification for Quality packers and top seals; annular BOPs; Operation of Subsea Production Management System Requirements for annular packing units; hydraulic Systems—Subsea Wellhead and Tree Manufacturing Organizations for the connectors; drilling spools; adapters; Equipment Petroleum and Natural Gas Industry loose connections; and clamps. This standard provides specifications This specification establishes the Conformance to this standard is for subsea wellheads, mudline minimum quality management system necessary to ensure that this critical wellheads, drill-through mudline requirements for organizations that safety equipment has been designed and wellheads, and both vertical and manufacture products or provide fabricated in a manner that ensures horizontal subsea trees. These devices manufacturing-related processes under a reliable performance. are located on the seafloor, and, product specification for use in the therefore, ensuring the safe and reliable API Spec. 16C—Specification for Choke performance of this equipment is petroleum and natural gas industry. and Kill Systems This standard requires that equipment extremely important. This document be fabricated under a quality This specification was formulated to specifies the associated tooling management system that provides for provide for safe and functionally necessary to handle, test and install the continual improvement, emphasizing interchangeable surface and subsea equipment. It also specifies the areas of defect prevention and the reduction of choke and kill systems equipment design, material, welding, quality variation and waste in the supply chain utilized for drilling oil and gas wells. control (including factory acceptance and from service providers. The goal of This equipment is used during testing), marking, storing and shipping this specification is to increase emergencies to circulate out a ‘‘kick’’ for both individual sub-assemblies (used equipment reliability through better and, therefore, the design and to build complete subsea tree manufacturing controls. fabrication of the components is assemblies) and complete subsea tree extremely important. This document assemblies. API Spec. 6A—Specification for provides the minimum requirements for Wellhead and Christmas Tree performance, design, materials, welding, API RP 17H—Remotely Operated Tools Equipment testing, inspection, storing and and Interfaces on Subsea Production Systems This specification defines minimal shipping. Equipment specific to and requirements for the design of valves, covered by this specification includes: This RP provides general wellheads and Christmas tree Actuated valve control lines; articulated recommendations and overall guidance equipment that is used during drilling choke and kill lines; drilling choke for the design and operation of remotely and production operations. This actuators; drilling choke control lines, operated tools (ROT) comprising ROT specification includes requirements exclusive of BOP control lines; and ROV tooling used on offshore related to dimensional and functional subsurface safety valve control lines; subsea systems. ROT and ROV interchangeability, design, materials, drilling choke controls; drilling chokes; performance is critical to ensuring safe testing, inspection, welding, marking, flexible choke and kill lines; union and reliable deepwater operations and handling, storing, shipment, purchasing, connections; rigid choke and kill lines; this document provides general repair and remanufacture. and swivel unions. performance guidelines for the equipment. ANSI/API Spec. 11D1—Packers and API Spec. 16D—Specification for Bridge Plugs Control Systems for Drilling Well II. Organization of Subpart G This specification provides minimum Control Equipment and Control Systems BSEE’s former regulations repeated requirements and guidelines for packers for Diverter Equipment similar BOP requirements in multiple and bridge plugs used downhole in oil This specification establishes design locations throughout 30 CFR part 250. and gas operations. The performance of standards for systems that are used to In this final rule, BSEE is consolidating this equipment is often critical to control BOPs and associated valves that these requirements into subpart G maintaining control of a well during control well pressure during drilling (which previously had been reserved). drilling or production operations. This operations. Although diverters are not The final rule will structure subpart G— specification provides requirements for considered well-control devices, their Well Operations and Equipment, under the functional specification and controls are often incorporated as part of the following undesignated headings: technical specification, including the BOP control system. Thus, control —GENERAL REQUIREMENTS

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—RIG REQUIREMENTS to shear tubing with exterior control years from the publication of the final —WELL OPERATIONS lines; however, the effective date has rule. As explained in more detail in —BLOWOUT PREVENTER (BOP) been extended to allow operators to part VI.C, changing the compliance SYSTEM REQUIREMENTS acquire and install (and, if necessary, date for these new accumulator —RECORDS AND REPORTING to develop new or alternative) requirements—from the proposed 3 The sections contained within this equipment to meet the requirements. months to the final 5 years from the new subpart will apply to all drilling, —As required by §§ 250.731, 250.732, date of publication—will allow completion, workover, and 250.734, 250.738, and 250.739, sufficient lead time for industry to decommissioning activities on the OCS, operators must begin using a BSEE- acquire and install additional unless explicitly stated otherwise. approved verification organization accumulator equipment as necessary (BAVO) for certain submittals, and will correspond with the III. Discussion of Compliance Dates for certifications, and verifications.8 timeframe for compliance with the the Final Rule BSEE will develop and make available final dual shear ram requirements, BSEE understands that operators may on its public website a list of BAVOs, which is when the additional need time to comply with certain new consisting of qualified third-party accumulator capacity will most likely requirements in this final rule. Based on organizations that BSEE determines be needed. information provided by industry, are capable of performing the —As required in § 250.734(a)(1), drilling rigs are now being built, or were functions specified in this final rule, operators must install dual shear rams built, pursuant to the same industry and that will help BSEE ensure that on subsea BOPs no later than 5 years standards BSEE is now incorporating by BOP systems are designed and from the publication of the final rule. reference (including API Standard 53), maintained during their service life to —As required in § 250.733(b)(1), surface and many have already been retrofitted minimize risk. Industry currently uses BOPs installed on floating facilities 3 to comply with these industry independent third-parties to perform years after publication of the final rule standards. Furthermore, most drilling verifications similar to the must comply with the BOP rigs already comply with recognized certifications and verifications that a requirements of § 250.734(a)(1). engineering practices and original BAVO will be required to perform —As required in § 250.734(a)(16), equipment manufacturer (OEM) under this final rule. BSEE is operators must install shear rams that requirements related to repair and extending the compliance date for the center drill pipe during shearing training. use of BAVOs to no later than 1 year operations no later than 7 years from BSEE has considered the public from the date when BSEE publishes the publication of the final rule. comments on the proposed compliance the list of BAVOs. BSEE anticipates —As required in § 250.735(g), operators dates, as well as relevant information that most of the independent third- must install remotely-controlled locks gained during, among other activities, parties currently used by industry on surface BOP sealing rams no later BSEE’s interactions with stakeholders, under the former regulations will than 3 years from publication of the involvement in development of industry become BAVOs, significantly final rule. standards, and evaluation of current facilitating compliance with the —As required in § 250.733(b)(2), for any technology. Accordingly, BSEE is requirements to use BAVOs within risers installed 90 days after the date setting an effective date of 90 days the one-year timeframe. of the publication of the final rule or following publication of the final rule, In the interim, however, final later, operators must use dual bore by which time operators will be § 250.732(a) requires that operators use risers for surface BOPs on floating required to demonstrate compliance independent third-parties to perform the production facilities. The final rule with most of the final rule’s provisions. certifications, verifications and reports does not require that operators change BSEE has determined, however, that it that BAVOs must perform no later than the riser configuration for risers that is appropriate to extend the compliance 1 year after BSEE publishes a BAVO list. were installed on floating facilities dates for the following new This transitional measure is necessary to before 90 days after the publication requirements. Detailed explanations for ensure that there is no diminution of the date of the final rule. these extended compliance dates are safety and environmental protection —As required in §§ 250.732(b)(1)(i) and provided in parts V and VI of this currently afforded by the use of 250.734(a)(1)(ii), the BOP must be document. independent third-parties under the able to shear electric-, wire-, and —As required in § 250.734(a)(15), existing regulations or of the safety and slick-line no later than 2 years after operators must install a gas bleed line environmental improvements publication of the final rule. with two valves for the annular anticipated under the new BAVO requirements, during the time required IV. Issues Not Considered in This preventer no later than 2 years from Rulemaking publication of the final rule. BSEE is for BSEE to identify and for operators to extending the timeframe for this use the BAVOs. BSEE is continuing to review and requirement based on the current —As required in § 250.724, operators evaluate additional operational and level of availability of the required must comply with the RTM equipment issues that are not included equipment and the time needed to requirements no later than 3 years in this final rulemaking, such as: install the equipment. This timeframe from the publication of the final rule. —Well-control planning, procedures, was selected to avoid any rig —As required in § 250.734(a)(3), training, and certification; downtime. operators are required to have —Major rig equipment; —As required by §§ 250.733(a)(1) and dedicated subsea accumulator —Certification requirements for 250.734(a)(1), operators must have the capacity for autoshear and deadman personnel servicing critical capability to shear and seal tubing functions on subsea BOPs within 5 equipment; with exterior control lines no later —Choke and kill systems; 8 For example, § 250.731(c)(2) requires —Mud gas separators; than 2 years from the publication of certification and verifacation that all BOPs are the final rule. BSEE is aware that designed and tested to maximun anticipated —Wellbore fluid safety practices, some current technology is available condictions. testing, and monitoring;

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—Diverter systems with subsea BOPs; reliability and performance of this • Requires additional measures (e.g., and equipment. RTM and increased maintenance) to —Additional severing requirements. • Requires inspection, maintenance, help ensure the functionality and and repair of BOP-related equipment by operability of the BOP system that will V. Discussion of Final Rule appropriately trained personnel; this help reduce the safety and Requirements will also increase the reliability of BOP- environmental risks. Part V.A, which follows, summarizes related equipment. B. Summary of Significant Differences and highlights some important Equipment Failure Reporting/Near-Miss Between the Proposed and Final Rules requirements of the final rule that were Reporting— described in more detail in the proposed After consideration of all relevant and rule. Some of these provisions received • Requires that operators share significant comments, BSEE made a no comments during the public information with Original Equipment number of revisions from the proposed comment period, while other provisions Manufacturers (OEMs) related to the rule in the final rule. We are were supported or criticized by certain performance of their BOP system highlighting several of these changes commenters. Part V.B addresses equipment. This sharing of information here because they are significant, and significant relevant comments on makes it possible for the OEMs to notify because numerous comments addressed certain proposed provisions and all users of any safety issues that arise these topics. A discussion of the summarizes changes to those provisions with BOP system equipment. relevant and significant comments and • that BSEE has made in the final rule Requires that operators report any BSEE’s responses are found in part VI of based on consideration of those significant problems with BOP or well- this document. The significant revisions comments. Part V.C summarizes other control equipment to BSEE, so BSEE can made in response to comments include: changes to the proposed rule that BSEE determine whether information should 1. Safe Drilling Margin—§ 250.414(c) has made in the final rule to avoid be provided, in a timely manner, to OCS In response to one of the Deepwater ambiguity or confusion, eliminate operators and, if appropriate, to Horizon investigation redundancies, correct minor drafting international offshore regulators and recommendations—i.e., to better define errors, or otherwise clarify the meaning operators. safe drilling margins—BSEE proposed to of the new requirements. Safe Drilling Practices— revise the safe drilling margin portion of A. Summary of Key Regulatory • Requires maintaining safe drilling the drilling prognosis (i.e., well drilling Provisions margins and other requirements related procedures) required in an Application After review of all the relevant public to liners and other downhole equipment for Permit to Drill (APD). Among other comments received on the proposed to help reduce the likelihood of a major things, BSEE proposed that the ‘‘static rule, BSEE determined that the well-control event and ensure the downhole mud weight must be a following proposed revisions will be overall integrity of the well design. minimum of 0.5 pound per gallon (ppg) • included in this final rule. Most of the Requires monitoring of deepwater below the lesser of the casing shoe pressure integrity test or the lowest proposed provisions are included and High Pressure High Temperature estimated fracture gradient’’ (‘‘the 0.5 without change, while several of the (HPHT) drilling operations from the ppg drilling margin’’). This proposed proposed provisions have been revised shore and in real-time. This will allow requirement was typically part of in the final rule in response to operators to anticipate and identify BSEE’s approval parameters during the comments, as explained in parts V.B issues in a timely manner and to utilize permitting process. However, many and VI of this document. onshore resources to assist in addressing critical issues. commenters expressed concerns that Shearing Requirements— • Requires daily reports to BSEE strict enforcement of a 0.5 ppg drilling • Requires BOP shearing performance concerning any leaks associated with margin in all circumstances could cause testing and results reporting to a BAVO. BOP control systems. This will ensure adverse economic consequences This will ensure that shearing capability that the bureau is made aware of any because it could effectively require for existing equipment complies with leaks so it can determine if further setting additional casing strings and BSEE requirements. action is appropriate. smaller hole sizes and thus, in some • Requires compliance with the latest • Requires compliance with API RP cases, could make it impossible to reach industry standards contained in API 17H to standardize ROV hot stab target depths. The commenters Standard 53. activities. This will allow certain suggested various alternatives to the 0.5 • Requires that operators use two functions of the BOP to be activated ppg requirement, including allowing shear rams in subsea BOP stacks. remotely. operators to use a risk-based approach • Requires the use of BOP technology to setting safe drilling margins on a BOP Testing— that provides for better shearing case-by-case basis. performance through the centering of • Requires same pressure testing Typically, 0.5 ppg is an appropriate the drill pipe in the shear rams. frequency (at least once every 14 days) safe drilling margin for normal drilling for workover and decommissioning scenarios and has been approved by Equipment Reliability and operations as for drilling and BSEE (and thus made a requirement) in Performance— completion operations. Pressure test numerous APDs. However, BSEE • Requires compliance with industry results will aid in predicting future understands that there are some well- standards, such as relevant provisions of performance of a BOP, and harmonizing specific circumstances where a lower API Standard 53, ANSI/API Spec. 6A, testing frequencies for all well drilling margin may be acceptable to ANSI/API Spec. 16A, API Spec. 16C, operations will also help streamline the drill a well safely, and BSEE has API Spec. 16D, ANSI/API Spec. 17D, BOP function-testing criteria and reduce approved appropriate alternative and API Spec. Q1. BOP operability will the unnecessary repetition every 7 days downhole mud weights as part of a safe be improved by establishing minimum of testing in workover and drilling margin in many APDs. design, manufacture, and performance decommissioning operations that could Accordingly, in this final rule, BSEE is baselines that are essential to ensure the pose operational safety issues. keeping the 0.5 ppg drilling margin as

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proposed to be the default requirement, the surface and then calculated to standard (API Standard 53) are but is adding a new paragraph (c)(2) to downhole conditions. Thus, equivalent inconsistent, and that the different § 250.414 that expressly allows the use downhole mud weight can be verified terminology could cause ambiguity and of an alternative to the 0.5 ppg drilling on the rig as operations are being confusion in efforts to comply with a margin if the operator submits adequate conducted. final rule. Industry commenters justification and documentation, BSEE also removed the references to recommended using the terminology including supplemental data (e.g., offset ECD from this section based on used in the API standard; and well data, analog data, seismic data, risk comments. For the reasons discussed • That the proposed requirement that modeling), in the APD. This addition is elsewhere in this preamble (with regard accumulator systems be able to supply consistent with current BSEE GOMR to § 250.413), BSEE determined that pressure to operate all BOP components practice to allow alternative drilling operators do not need to submit the and shear pipe as the last step in the margins when justified and estimated ECD in the APD permitting BOP sequence, without assistance from documented. This change will also process; however, BSEE expects a charging unit, would increase the provide operators some assurance that operators to continue their normal number of accumulator bottles needed an alternative drilling margin, other practice of considering ECD while and would require upgraded than the 0.5 ppg margin, may be used drilling. accumulator system controls. The commenters also stated that costs when appropriate, while helping BSEE 2. Accumulator Systems ensure the use of drilling mud with associated with the additional bottles properties (e.g., density, viscosity, In the proposed rule, BSEE proposed would be significant and that the extra additives) best suited for a specific well a number of significant changes to weight from additional bottles, given interval and based on well-specific existing BOP requirements as well as limited deck space availability, could drilling and geological parameters.9 new requirements for BOPs and cause structural issues with the rig. This addition to the safe drilling margin associated systems, including new • That the proposed requirements section will provide increased planning requirements for subsea and surface that the subsea accumulator system be flexibility when drilling into areas that BOP accumulator systems. (See able to supply pressure to operate all could require lower safe drilling proposed §§ 250.734 and 250.735.) The critical BOP components, and that the margins, such as depleted sands or purpose of the accumulator system and system have dedicated bottles for each below salt (both common occurrences in these new requirements is to ensure that EDS/autoshear/deadman system(s), the GOMR), and help avoid the there is sufficient volume and pressure would greatly increase the number of potential negative consequences of in the accumulator bottles to properly accumulator bottles on the subsea BOP. requiring a 0.5 ppg margin in all cases. operate BOP components in a specified The commenters stated that the BSEE is also making other minor timeframe regardless of the location of increased number and weight of changes to the proposed § 250.414(c). the accumulator bottles. Among other accumulator bottles could also cause Specifically, as suggested by several things, we proposed increasing structural concerns for the BOP frame commenters, we are replacing the term accumulator capacity to operate all BOP and the rig and that costs associated ‘‘static downhole mud weight’’ with functions; i.e., requiring all surface with the additional bottles would also ‘‘equivalent downhole mud weight,’’ accumulator systems, whether be significant. and removing the references to associated with surface or subsea BOPs, BSEE reviewed all of the relevant Equivalent Circulating Density (ECD). to meet the requirements for comments and has made changes to the Several commenters suggested replacing accumulators servicing surface BOPS proposed surface and subsea static downhole mud weight with a under the prior regulations (including accumulator requirements in the final more appropriate term to better define the requirement that the accumulator rule. In this final rule, BSEE is deleting and assess the mud weight because of system provide 1.5 times the volume of the ‘‘1.5 times volume capacity’’ the difficulty of achieving and verifying fluid capacity necessary to hold closed requirement for all surface static downhole mud weight during all BOP components). We also proposed accumulators, and instead requiring that operations. BSEE agrees with this requiring surface accumulator systems all accumulator systems (including observation. To verify a static downhole to operate under MASP conditions, with those servicing subsea BOPs) meet the mud weight, the well would need to be the blind shear ram being last in the sizing specifications of API Standard 53. placed in a static situation. This would BOP sequence, and still have enough The final rule also extends the effective be done by turning off the pumps and accumulated pressure to allow the BOP date to comply with the new letting the well sit until it is static; to shear pipe and seal the well. In accumulator requirements (both surface however, that process can result in addition, we proposed defining critical and subsea) to 5 years; removes the complications, such as cuttings and functions for BOP operation, and proposed requirement that the surface debris settling out in the bottom of the requiring dedicated, independent accumulator be able to operate the blind well and thermal gradients affecting accumulator bottles for emergency shear ram as the last function in the mud properties. Some of these functions (autoshear/deadman/ BOP sequence; defines ‘‘critical complications may create additional emergency disconnect sequence (EDS)). functions;’’ and requires dedicated issues, such as stuck pipe or loss of BSEE received multiple comments on subsea accumulator bottles for autoshear wellbore integrity. The change from these proposed provisions. Industry and deadman (but not EDS) functions ‘‘static’’ to ‘‘equivalent’’ allows the stakeholders raised concerns with (and and allows those dedicated bottles to be downhole mud weight to be based on in some cases suggested revisions to) the shared between the autoshear and the mud properties that can be tested at proposed requirements, including the deadman functions. following concerns: BSEE reevaluated the relevant 9 Alternatives to compliance with the 0.5 ppg safe • That the proposed surface and industry standards and determined that drilling margin requirement could also be requested subsea accumulator capacity API Standard 53 and API Spec. 16D under existing § 250.141, and approved by BSEE if requirements are in conflict with API provide reasonable and appropriate the criteria of that section are satisfied; but such Standard 53 and API Spec. 16D; methods to ensure proper volumes and separate requests would not be necessary if an • operator requests an alternative in its APD under That the terminology in the pressures of appropriate BOP new § 250.414(c)(2). proposed rule and the current industry components. Changing the proposed

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

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

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

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commenters, were not deemed by MMS through better designs, improved • In final § 250.462, we revised the sufficient to justify increasing the manufacturing processes, better language from ‘‘pressure holding’’ to pressure testing interval from 14 to 21 maintenance and repair procedures, and ‘‘pressure containing’’ critical days. In the proposed rule, BSEE increased data sharing. BSEE will components. We also clarified language explained that it was reevaluating this consider the possibility of adopting 21- on excluding downhole safety valves. issue and requested additional data and day BOP testing when it receives And we clarified the equipment that technical analysis regarding the adequate new (post-Deepwater Horizon) operators must make available to BSEE proposed pressure testing frequency data and analyses demonstrating that for inspection. We revised this section requirements to determine if a uniform BOP reliability and capability, and to clarify the differences between 21-day testing interval should be personnel safety, are not adversely collocated equipment and SCCE (e.g., included in the final rule. Given the affected (or are actually improved) by collocated equipment includes operational issues that had previously pressure testing at 21-day intervals. This dispersant injection equipment.) been brought to BSEE’s attention by the could include, for example, data from • In final §§ 250.518, 250.619, and industry, and the potential costs savings BOP testing and usage in OCS or other 250.1703, we clarified that, for the ($400 million dollars per year) that waters. BSEE will consider relevant purposes of those sections, permanently BSEE estimated could result from data, along with any data indicating that installed packers and bridge plugs must moving from 14-day to 21-day testing, the other requirements contained in this comply with the referenced industry BSEE anticipated that significant rule (such as BAVO verification), have standard. technical and economic comments increased overall BOP performance and • In final § 250.703, we replaced ‘‘the would be submitted on this issue. reliability and decreased the risk of most extreme service conditions’’ with Comments in support of such a change failure of the systems and components. ‘‘the maximum environmental and were submitted; however, these In the meantime, any operator that operational conditions’’ to which comments did not provide adequate believes its specific circumstances equipment may be exposed at a given data and information to reasonably warrant a longer pressure test interval well. support a 21-day testing interval at this may seek approval from the District • In final § 250.711, we clarified that time. Manager to use alternate procedures or the same well-control drill cannot be BSEE is aware of concerns that the equipment under § 250.141. repeated consecutively with the same more frequently BOPs are tested, the crew, in order to avoid overly narrow C. Other Differences Between the more likely the equipment is to wear out training for certain personnel and to Proposed and Final Rules prematurely; however, it does not improve proficiency in well-control automatically follow that every In addition to the significant changes procedures by a broader set of rig extension of test intervals always discussed in the preceding section, personnel without unduly limiting the increases reliability, and thus safety and BSEE has also made changes to the rule operator’s discretion to schedule environmental protection, in the long- in response to comments suggesting that important drills. term. The industry commenters do not BSEE eliminate redundancy, clarify • In final § 250.712, we changed the dispute that testing must occur at some potentially confusing language, timeframe for informing BSEE of the rig appropriate intervals to provide streamline the regulatory text, and align movement from 72 hours to 24 hours’ assurance that BOPs will function as certain provisions in the proposed notice before movement. BSEE agreed intended when needed to prevent a regulatory text more closely with with commenters that requiring 72 hour blowout. BSEE’s experience with 14-day relevant terminology in API Standard 53 notice may have necessitated additional pressure testing for drilling and (where BSEE intended the proposed revisions to the submitted form due to completion BOPs indicates that it is provisions to be consistent with that the constant changes of operations effective for its purpose and that, in the standard). In some cases, we agreed affecting rig movements. Requiring a 24 absence of significant new information with and accepted specific wording hour notification provides a better on longer test intervals, it is appropriate changes suggested by the commenters, indication of when a rig will move. to retain that interval for such BOPs and and in some cases we made changes • In final § 250.713, we deleted the to apply the same requirement to based on our agreement with the reference to ‘‘lift boats’’ and made other workover and decommissioning BOPs. commenters’ basic suggestion, even minor changes to improve consistency BSEE believes that the provisions in though the commenter provided no in rig-related terminology. the final rule that increase the exchange specific alternative language or we did • In final § 250.715, we also revised of data on equipment reliability, that not agree with the specific wording the language to provide more improve the design, manufacturing, suggested by the commenter. In still consistency in rig-related terminology maintenance and repair of BOP other cases, we made minor revisions to and to clarify the requirements for equipment, and that require the use of proposed provisions in order to correct access to GPS data. BAVOs or other independent third- grammatical errors, eliminate potential • In final § 250.721, we clarified that parties to verify and document BOP ambiguity, or to avoid confusion by operators must test the liner-top, instead testing, repairs and maintenance will further clarifying the intent of the of the liner-lap, and that the pressure result in improved performance and proposed language. The revisions testing of the entire well should not reliability of BOPs in the future. include the following: exceed 70 percent of the burst rating However, in the absence of new data • In final § 250.292, we clarified the limit of the weakest component. demonstrating that 21-day testing would proposed language about pipeline free • In final § 250.722, we clarified that be as protective as 14-day testing, BSEE standing hybrid risers ‘‘on a permanent calculations must be included if an has decided to finalize the proposed 14- installation.’’ imaging tool or caliper is used. day pressure testing requirement for • In final § 250.421, we clarified the • In final § 250.730, we: BOPs used in all types of operations. In proposed language regarding cementing Æ Clarified that the lessee or operator response to the Deepwater Horizon the liner lap and what actions are must ensure that the BOP systems are incident, industry attempted to necessary when an operator is unable to designed, installed, maintained, voluntarily improve the overall meet the cementing requirements of the inspected, tested and used properly reliability of well control equipment liner lap section. (instead of the lessee or operator

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actually performing these actions Æ Clarified that control panels must leaks associated with a BOP control themselves), since these actions are have ‘‘enable’’ buttons or similar system, and made minor changes to usually performed by contractors. features to ensure two-handed provide consistency in rig-related Æ Clarified that the working pressure operation. terminology. rating for annulars does not need to Æ Clarified that there must be a side • In final §§ 250.414(k), 250.713(e), exceed MASP. outlet installed below the lowest sealing 250.714(e), 250.721(d) and (g)(3), Æ Clarified that the BOP system shear ram. 250.722(a)(1), 250.734(a)(7), 250.738(o), (instead of each ram) must be capable of Æ Clarified that, if there are dual 250.740(g), 250.743(c), and 250.744(a), closing and sealing the wellbore at all annulars, a gas bleed line must be we clarified the purposes for which times and provide reliable means to installed below the upper annular. District Managers may require handle well-control events. Æ Revised the language regarding additional information, testing, or other Æ Clarified paragraph (a)(2) to provide testing of the equipment after making procedures consistent with the purposes that the BOP systems must meet the repairs, and clarified the testing of those sections. provisions of the specified industry requirements under certain VI. Discussion of Public Comments on standards that apply to BOP systems. circumstances. the Proposed Rule Æ Revised the failure reporting • In final § 250.735, we revised procedures in paragraph (c) to include paragraph (e), to clarify the required In response to the proposed rule, submitting such reports to BSEE. location of the kill line, and paragraph BSEE received over 172 sets of Æ Clarified paragraph (d)(1) to remove (g) to eliminate the proposed comments from individual entities (e.g., the reference to the alternative requirement for hydraulically operated companies, industry organizations, non- compliance regulations at § 250.141. locks for pipe rams on surface BOPs and governmental organizations, and private • In final § 250.732, we: to replace the proposed requirement for citizens). Some entities submitted Æ Revised paragraph (a) by extending hydraulic locks on surface BOP blind comments multiple times. All relevant the compliance date for BAVO-related shear rams with a requirement for comments are posted at the Federal requirements to 1 year from the date remotely-operated locks. eRulemaking portal: http:// BSEE publishes a BAVO list and adding • In final § 250.736, we revised the www.regulations.gov. (To access the new paragraphs (a)(1) and (2). Final kelly valve requirements to better reflect comments at that website, enter BSEE– paragraph (a)(1) provides that, until the current practice and technology. 2012–0002 in the Search box.) BSEE requirements to use BAVOs become • In final § 250.737, we: reviewed all comments submitted. Each effective, operators must use an Æ Clarified, in paragraph (d)(2), that of the following sections contains a brief independent third-party to provide the water must be used to do the initial test summary of the relevant and significant certifications, verifications, and reports for surface BOP systems, but that comments as well as BSEE’s responses. that a BAVO must provide after the drilling/completion/workover fluids A. Requests for Extension of the BAVO requirements become effective. may be used to conduct subsequent Proposed Rule Comment Period Final paragraph (a)(2) clarifies the tests. criteria for independent third-parties, Æ Clarified the requirements for Summary of comments: BSEE based on the longstanding criteria in use testing pods between control stations. received requests from various under current regulations. Æ Removed redundant provisions stakeholders asking BSEE to extend the Æ Revised paragraph (b)(1)(vi), by covered under other sections. comment period on the proposed rule. replacing ‘‘all testing results’’ with • In final § 250.738, we: The majority of those requests sought ‘‘relevant testing results.’’ Æ Revised paragraph (a) by removing extensions of 120 days, which would Æ Revised paragraph (d)(6) to clarify the requirement to notify the District have tripled the length of the original that training for personnel who service, Manager of problems or irregularities 60-day comment period. BSEE also repair or maintain BOPs must cover ‘‘including leaks’’; however, these received a written comment from ‘‘any applicable’’ OEM requirements. problems or irregularities must be another stakeholder urging BSEE not to • In final § 250.733, we removed recorded on the daily report, which extend the comment period because the redundant requirements that are must be made available to BSEE upon proposed rule has been in development covered in other sections. request. since the Deepwater Horizon incident, is • In final § 250.734, we: Æ Revised paragraph (e) to clarify that based on recommendations resulting Æ Revised the ROV provisions to one set of pipe rams (instead of two) from that incident, and represents a require opening and closing of ram must be capable of sealing around the critical regulatory improvement that locks, one pipe ram, and the Lower smaller size pipe. should be finalized without delay. Marine Riser Package (LMRP) Æ Revised paragraph (f) to clarify the • Response: BSEE considered those disconnect. required testing of the connections if requests and determined that extending Æ Clarified that the ROV crew must casing rams or casing shear rams are the original 60-day comment period by be capable of carrying out appropriate installed in a surface BOP stack. an additional 30 days provided tasks during emergency operations. Æ Revised paragraph (l) to clarify the sufficient additional time for review of Æ Simplified paragraph (a)(6)(vi) by required testing of the wellhead/BOP and comment on the proposal without deleting a phrase that would have connection if a test ram is to be used. unduly delaying a final rulemaking required a failsafe system to use ‘‘logic’’ Æ Revised paragraph (p) to clarify the decision. The comment extension to the that makes every step independent from requirements that apply if the bottom notice of proposed rulemaking was the previous step, and inserting instead hole assembly needs to be positioned published in the Federal Register on the words ‘‘once activated.’’ across the BOP. June 3, 2015. (See 80 FR 31560.) Æ Clarified in paragraph (a)(7), that if • In final § 250.739, we clarified Summary of comments: Various an operator chooses to ‘‘use’’ an acoustic personnel training and records commenters asserted that even the 90- control system there are applicable requirements. day public comment period was requirements to demonstrate that it will • In final § 250.746, we added a inadequate for a rule of this technical function in the proposed environment reference to digital recorders, clarified complexity, and that additional time and conditions. the actions required when there are (e.g., 120 days) was needed to properly

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address the substantial amount of codifying the technological Leases issued since 2010 likewise technical content and complexity in this requirements in the final rule, many of provide that: draft. They suggested that the comment which were derived from This lease is subject to [OCSLA], period should be reopened and/or that recommendations based on exhaustive regulations promulgated pursuant thereto, BSEE publish a revised proposed rule investigations and reports on the . . . and those . . . regulations promulgated for comment. Deepwater Horizon incident, and on thereafter, except to the extent they explicitly • Response: BSEE believes that the input from experts representing conflict with an express provision of this 90-day comment period, which includes equipment manufacturers, the offshore lease. It is expressly understood that the 30-day extension granted by BSEE, oil and gas industry, government, amendments to existing . . . regulations . . . was reasonable and sufficient under the academia, and environmental as well as the . . . promulgation of new regulations, which do not explicitly conflict Administrative Procedure Act (APA). organizations focused on identifying with an express provision of this lease may The APA requires that agencies give appropriate technological standards. be made and that the Lessee bears the risk ‘‘interested persons an opportunity to BSEE believes that the requirements in that such may increase or decrease the participate’’ in the rule making process this regulation provide an appropriate Lessee’s obligations under the Lease. through submission of written data, level of safety. BSEE may make a None of the provisions of this rule views or arguments. (See 5 U.S.C. separate determination in the future explicitly conflict with any express 553(c).) The APA does not prescribe the related to the use of BAST, pursuant to provisions of OCS oil and gas leases. number of days that an agency must OCSLA, if supplemental requirements The Supreme Court and other Federal allow for written comments, and an are necessary. courts have interpreted the relevant agency’s decision on comment period Summary of comments: Several lease language to mean that ‘‘[a] change length is generally deferred to unless it industry commenters claimed that to an OCSLA regulation does not breach is arbitrary and capricious. (See 5 U.S.C. certain provisions in the rule could the express terms of the lease language.’’ 706(2).) render leases uneconomical to operate, Century Exploration New Orleans, LLC thereby requiring a Takings Implication B. Summary of General Comments on v. United States, 745 F.3d 1168, 1178 Analysis (TIA) by BSEE under Executive the Proposed Rule (Fed. Cir. 2014), citing Mobil Oil Order (E.O) 12360, and potentially Exploration & Production Southeast, 1. Comments Supporting the Proposed amounting to a breach of contract by Inc. v. United States, 530 U.S. 604, 616 Rule DOI. • (2000); Century Exploration New Summary of comments: Multiple Response: By their own terms, OCS Orleans, LLC v. United States, 110 Fed. commenters commended the efforts by oil and gas leases expressly state that Cl. 148, 164–66 (2013) (the lease BSEE to improve safety and they are subject to regulations language ‘‘allocates the risk of certain environmental protection and expressed promulgated after lease issuance, legal changes—future regulations issued their support for many of the changes in including the types of regulatory action pursuant to OCSLA—to [lessees]’’). This the proposed rule. reflected in this final rule. Accordingly, conclusion is in no way dependent • Response: It is BSEE’s continued the adoption of this final rule is upon the impacts of such a rulemaking mission to promote safety, protect the consistent with lessees’ rights to on the economics of lease development. environment, and conserve resources conduct operations on the OCS—which The express language of the leases (in offshore through vigorous regulatory are derived entirely from their lease sections 10 and 12) likewise requires oversight and enforcement. This final interests—and thus do not amount to a that the lessee comply with all rule is an important step toward better breach of contract or a taking under the applicable regulations, and OCSLA well control and improved safety and Fifth Amendment. As a result, a TIA is expressly provides that regulations environmental protection. not necessary. promulgated pursuant to the statute E.O. 12630 requires executive apply to both new and existing leases as 2. Legal Comments agencies to review agency actions, of their effective date. 43 U.S.C. 1334(a). Summary of comments: Several including rulemakings, that have Because all changes to the regulatory commenters claimed that BSEE failed to takings implications (i.e., actions that, if language implemented through this rule incorporate the principles of best implemented, could effect a taking) to are made pursuant to OCSLA, they are available and safest technologies (BAST) prevent unnecessary takings and to expressly incorporated into the terms of reflected in OCSLA, resulting in identify and discuss any significant the leases and thus consistent with requirements that are arbitrary, not takings implications and the agency’s lessees’ rights thereunder. In light of the reasonable or practicable, not conclusions on the takings issues. In fact that the entirety of lessees’ rights to economically or technically feasible, this case, the terms of all OCS oil and conduct the impacted operations on the less safe, and more obstructive to OCS gas leases allow BSEE to promulgate OCS are derived from their leases, oil and gas development, in violation of new rules, pursuant to OCSLA, without regulation that is consistent with those the OCSLA-mandated balance between violating the rights created by the lease lease rights likewise cannot amount to safety and environmental protection and contracts. Specifically, leases issued an unconstitutional taking of those lease expeditious and orderly development of prior to 2010 state: rights. Accordingly, promulgation of OCS resources. This lease is issued pursuant to the Outer this rule does not amount to a breach of • Response: BAST requirements, as Continental Shelf Lands Act.... The lease any lease terms or a taking of any rights set out in OCSLA and its implementing is issued subject to the Act; all regulations derived from OCS leases. regulations (see 30 CFR 250.107) are the issued pursuant to the Act and in existence Summary of comments: Some product of specific BSEE analyses and upon the Effective Date of this lease; all commenters raised issues concerning determinations. Existing BSEE regulations issued pursuant to the statute in the World Trade Organization’s (WTO’s) the future which provide for the prevention regulations and this final rule contain of waste and conservation of the natural Technical Barriers to Trade Agreement numerous technology requirements, all resources of the Outer Continental Shelf and (TBT Agreement). In particular, the of which were adopted through notice the protection of correlative rights therein, commenters asserted that purported and comment rulemaking. The proposed and all other applicable statutes and inconsistencies between the proposed rule explained the justifications for regulations. rules and API Standard 53 require

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

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

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

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

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contractor performs any of the reporting initial RIA insufficient for estimating the baseline scenario can be found in or notification required by § 250.730(c), the costs and benefits of the rule. Section 4 and in Appendix A of the the contractor is responsible, along with • Response: BSEE determined that final RIA for this rule, which is the lessee and designated operator, for that the 10-year analysis period used in available in the regulatory docket at complying with the terms of the the initial RIA is appropriate to www.regulations.gov (enter BSEE–2015– applicable requirement(s). If the maintain reasonable certainty of the 0002). contractor (or any other person) is not estimates, given the uncertainties that c. Costs Related to Equivalent actually performing a required activity, exist beyond 10 years with regard to Circulating Density Information but believes that a lessee, operator or industry activities, technological other person may have failed to comply change, and energy markets. Summary of comments: One comment on the initial RIA asserted that the with any applicable requirement under b. Issues Associated With the Economic requirement to include information on BSEE’s regulations, the contractor may Baseline report such noncompliance to BSEE in the ECD under proposed § 250.413 accordance with § 250.193. Summary of comments: BSEE would take additional time by the Section 250.730(c) does not impose received several comments on the initial drilling engineer and additional staff any requirements on OEMs. RIA indicating that some of the costs time to interface with BSEE personnel. Summary of comments: With regard assumed to be part of the baseline (and, • Response: BSEE notes that this to the proposed recordkeeping therefore, not considered costs of the information is already included in the requirements in proposed §§ 250.740, rule) are actually related to activities driller’s report, which is an existing 250.741, and 250.746, one commenter that either are not covered by current requirement, and thus there is no stated that, while a prudent drilling industry standards or are not in additional cost as a result of this contractor presumably would maintain accordance with existing regulations. requirement. Specifically, commenters referred to relevant records, such prudence differs costs related to requirements for activity d. Costs Related to Wellhead Systems from a regulatory obligation to do so. reporting and recordkeeping, BOP Information The commenter also asked whether system testing, autoshear/deadman/EDS BSEE’s intends that these provisions Summary of comments: One comment systems, casing and cementing, create a regulatory requirement for stated that the additional information to maintenance and inspection, and contractors or individuals to maintain be provided on wellhead systems under redundant components for well control, records duplicating those maintained by proposed § 250.414(j) would require among others, as examples of costs the the operator. operators to include wellhead and liner analysis purportedly failed to consider • Response: To the degree that a hanger specifications in the APD, because they were assumed to be part of contractor or any other person actually resulting in an additional cost to the baseline. operators. performs any of the recordkeeping • Response: BSEE established the • Response: This information is activities required by §§ 250.740, baseline used in the initial (and the 250.741, and 250.746, that person is readily available from the OEM, once final) RIA in accordance with the the operator purchases the wellheads, so jointly and severally responsible, with guidance provided by Office of the lessee and designated operator (if the additional cost to operators due to Management and Budget (OMB) these requirements should be minimal. any), for complying with the applicable Circular A–4 (‘‘Regulatory Analysis’’). requirements, including record This guidance states that the ‘‘baseline e. Tubing and Wellhead Equipment retention, imposed by those sections. should be a best assessment of the way Costs Those provisions of the final rule do the world would look absent the Summary of comments: Some not, however, require that the lessee, proposed action[,]’’ i.e., without the comments asserted that BSEE failed to designated operator, or the person implementation this final rule. (OMB adequately consider costs associated performing the recordkeeping Circular A–4 sec. E. 2. ‘‘Developing a with the requirements in proposed requirements maintain duplicate copies Baseline.’’) Without this rule, BSEE’s §§ 250.518 and 250.619 for complying of the records kept by other jointly best assessment of the way the world with industry standards for tubing and responsible parties. would look includes compliance costs wellhead equipment. 6. Economic Analysis Comments associated with current industry • Response: BSEE notes that these practices, existing regulations, DWOPs, costs are included in the baseline since a. Analysis Period Used in the Initial NTLs, and industry standards. the only requirements in these sections Regulatory Impact Analysis (RIA) Therefore, based on the Circular A–4 that impose any costs are those Summary of comments: BSEE guidance, BSEE has reasonably associated with meeting the existing received several comments suggesting determined that the costs listed by the industry standard (i.e., API spec. 11D1) that the analysis period used in the commenters are appropriately included for tubing and wellhead equipment that initial RIA 10 for the proposed rule was in the baseline. industry already follows. insufficient to fully assess the impacts In contrast, many of the comments of the rule on OCS operations. appeared to assume that any cost f. Installation of Locking Devices Commenters noted, in particular, that associated with requirements of this Summary of comments: Some offshore developments and equipment regulation is a cost of the rule regardless comments suggested that BSEE had not have lifecycles of 20 to 30 years, making of whether that cost is already incurred included the cost of requiring the the 10-year analysis period used in the based on current standard industry installation of hydraulically operated practice, existing regulations, or other locks on surface BOP systems, under 10 This document uses the terms ‘‘initial RIA’’ and indicators of state of the world in the proposed § 250.733 (now covered under ‘‘initial economic analysis’’ interchangeably. Both absence of this rule. This assumption is final § 250.735(g).) terms refer to the initial regulatory impact analysis inconsistent with both OMB guidance • Response: Although the revised performed for the proposed rule, as required by E.O. 12866, which is available in the regulatory docket and with the general principles upon final rule will not require installation of for this rule at: www.regulations.gov (Enter BSEE– which an RIA is based. Additional hydraulically operated locks on surface 2015–0002). discussion of BSEE’s development of BOP systems (as discussed in part VI.C),

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

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n. Costs of Accumulator System exploratory drilling activities) that further analysis under OMB Circular A– Requirements commenters asserted may occur as a 4, their absence from the commenters’ Summary of comments: BSEE result of the rule. One of these estimates means that their estimates do received comments on the proposed comments also provided an economic not present a complete picture of all of accumulator system requirements in the analysis of the broad effects of the rule the potential indirect effects. on the national economy. Summary of comments: Costs to proposed rule at § 250.735, including • estimates of industry costs to comply Response: BSEE does not agree that Contractors—Several commenters with these requirements. Many of the what the commenter has described as asserted that BSEE did not adequately estimated costs in these comments ‘‘indirect costs’’ of the rule are within account for the additional costs to exceeded the costs estimated by BSEE in the scope of the RIA as required by E.O. contractors that would result from the 12866. OMB Circular A–4 characterizes proposed rule. the initial RIA. • • Response: The final regulatory text the indirect effects of a rulemaking as Response: BSEE disagrees with this for this requirement has been changed ‘‘ancillary benefits and countervailing comment because, in estimating costs, to better align with API Standard 53, risks,’’ but also states that these types of BSEE considered the costs of all of the thereby reducing its cost to industry. forecasted consequences, if highly equipment and labor services that The remaining costs to comply with this speculative, may not be worth further would be needed to meet new final requirement are now minimal, as formal analysis. Because there are a requirements, regardless of how that described in the final RIA. number of important and variable equipment or labor is provided (whether factors (unrelated to the implementation by lessees, operators, or contractors). o. Costs Related To Testing of ROV of the new regulations), such as the Summary of comments: Offshore Intervention Functions future price of oil, that will impact both support industries—Commenters also Summary of comments: BSEE the offshore oil and gas labor market stated that BSEE overlooked potential received a comment that the testing of and the marketplace for offshore oil and negative impacts to industries that ROV intervention functions under gas equipment and products, BSEE support offshore oil and gas exploration believes it is too speculative to predict and development. proposed § 250.737 would require • additional operational time per well, whether this rulemaking will have the Response: BSEE disagrees with this thereby imposing an additional cost. types of broad and indirect effects comment. The economic analysis • Response: BSEE does not estimate discussed by the comments. In addition, included in the initial RIA considered that there will be any additional costs to the indirect impacts expressed by the the costs of all of the equipment and operators in this regard since such comments appear to be overstated or labor services that would be needed to testing is consistent with industry based upon certain assumptions for meet the new requirements. Many of the standards, and is thus within the which there is no clear foundation.11 negative impacts projected by the baseline of the analysis. Moreover, many of those estimated costs commenters are speculative and outside appear to be associated with the scope of the type of analysis p. Costs Related To Breakdown and requirements that are part of the required to support this rulemaking. Inspection of BOP System and economic baseline (e.g., compliance (For example, one comment stated that Components with relevant provisions of API the rule was ‘‘unworkable as written Summary of comments: Several Standard 53); while others are and could effectively shut-down drilling commenters asserted that the associated with requirements discussed operations . . . similar to another requirement in proposed § 250.739 that in the proposed rule that are not drilling moratorium.’’) In addition, some operators break down the entire BOP included in the final rule (e.g., the commenters projected additional costs system every 5 years for inspection, proposed 1.5 times volume capacity to industries that support offshore oil without the option to phase or stagger accumulator requirement). and gas exploration and development, inspection, would cause rigs to be out In addition, the commenters did not but did not address whether there are of service for extended periods of time, take into account the potential benefits potential benefits to other types of at substantial opportunity costs to to industry in terms of reduced costs of industries resulting from the new industry. operation associated with requirements. Thus, even assuming they • Response: As described in detail in implementation of the new regulations. were within the scope of this analysis, parts V.B.3 and VI.C of this document, For example, the reduction in costs these comments do not present a BSEE has revised the requirement in attributable to the change in the BOP complete picture of the potential § 250.739 of the final rule to allow for pressure testing frequency for workovers impacts on other industries. phased inspections over the course of 5 and decommissioning will exceed the years. This change should eliminate the costs that will result from the final rule. r. Impacts of the Regulation on National need for rigs to be brought out of service The commenters also did not account Energy Security for extended periods of time, and thus for the indirect benefits from the Summary of comments: BSEE reduces if not eliminates the rulemaking that may accrue to entities received comments that the initial RIA opportunity costs of such inspections. other than offshore operators. For did not account for the impacts of the example, the requirements for new proposed regulation on national energy q. Indirect Economic Impacts of the equipment and for use of BAVOs may security. These comments suggested Rule result in an increase in the offshore that the rule would weaken national Summary of comments: Claimed labor force, which should result in energy security by reducing domestic oil indirect costs—Some comments overall economic benefits. Although production and increasing reliance on suggested that BSEE should consider such indirect benefits may also be foreign oil. additional impacts of the rule. For speculative, and thus do not warrant • Response: BSEE does not agree with example, several comments asserted this comment. The commenters’ that the analysis did not appropriately 11 For example, one comment assumed that the prediction about the weakening of account for broader ‘‘indirect’’ economic costs of the rule would lead to a 20 percent decrease national energy security is highly in the number of floating units and over 30 percent costs (such as costs arising out of job decrease in fixed platforms, but provided no speculative and thus outside of the losses associated with reduced explanation for those assumptions. scope of the regulatory impact analysis

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required by E.O. 12866 and OMB rule, some of which have been included suggested that these standards, which Circular A–4. For example, these in this final rule without revision and are for developing safety instrument comments apparently assume that this some of which have been revised in the systems, including programmable rulemaking will cause a reduction in final rule. Those sections, and the systems (i.e., software), to a target level domestic oil production over some relevant comments on those sections as of reliability, could be adapted to period of time. As previously discussed, well as BSEE’s responses are support the rule. The commenter the net economic effect of the final rule summarized here. suggested that the methodology in IEC on the oil and gas industry should be 61508 and 61511 could be used to positive (i.e., the potential benefits Subpart A—General manage components and materials to exceed the potential costs), which does What does this part do? (§ 250.102) ensure quality, so that reliability is not not support the assumption of a degraded and can be controlled via this This section of the existing regulation reduction in domestic oil production. process even if original parts are provides information on where to find Rather, future technological replaced by less expensive versions that information about various OCS advancements and variable market have the same specification. operations in 30 CFR part 250. BSEE factors (e.g., the price of oil) unrelated • Response: The international proposed to add new information to this to the requirements of this final rule, are electrical standards referred to by the more likely to affect the future domestic section so the public will know where commenter (which apply broadly to oil production. they can find requirements for well electrical and electronic systems used to operations and equipment in new carry out safety functions and are not 7. Clarification of Maximum subpart G. BSEE received no substantive specifically related to well control Anticipated Surface Pressure (MASP) comments on this provision of the systems) were not proposed for Summary of comments: Some proposed rule and has included the incorporation in the proposed rule and commenters recommended that BSEE proposed language in the final rule are outside the scope of this rulemaking. change the reference to MASP in without change. However, BSEE may evaluate those specific sections throughout the rule What must I do to protect health, safety, standards at a later date and, if BSEE (e.g., proposed § 250.734(a), requiring property, and the environment? determines that it is reasonable and that the working pressure rating of each (§ 250.107) appropriate to incorporate some parts or BOP component exceed the applicable all of those standards, BSEE may MASP) to ‘‘maximum anticipated This section of the existing regulation propose to do so in another rulemaking. wellhead pressure’’ (MAWHP). They lays out performance-based and other asserted that there is no industry agreed- requirement that operators must meet to Comments Related to Proposed upon definition of MASP, but that protect safety, health, property and the § 250.107(a)—Definition of ‘‘You’’ MAWHP is defined in API Standard 53. environment and requires the use of Summary of comments: Some • Response: BSEE does not agree that BAST whenever practical. BSEE commenters asserted that proposed the recommended change is necessary. proposed several revisions to this § 250.107(a)(4)—requiring lessees, The MASP must be identified for the existing regulation. BSEE proposed to designated operators, and other persons specific operation, and for a subsea revise paragraph (a) of this section to specified in the existing definition of BOP, the MASP must be taken at the include performance-based ‘‘you’’ in § 250.105, to comply with all mudline, as explained in § 250.730(a). requirements that operators utilize lease, plan and permit terms and As a practical matter, for surface BOPs, recognized engineering practices that conditions—creates an implicit the MASP is the same as the MAWHP; reduce risks to the lowest level requirement for contractors or and for subsea BOPs, the MASP, when practicable during activities covered by individuals performing specific taken at the mudline, as required by the regulations and conduct all activities subject to the regulations to § 250.730(a), is also the same as the activities pursuant to the applicable ascertain all lease, plan, and permit MAWHP. BSEE does not agree that use lease, plan, or permit terms or terms and conditions. of MASP will cause any confusion. conditions of approval. BSEE also • Response: As discussed in part BSEE’s existing regulations (e.g., former proposed adding new paragraph (e) to VI.B.5 of this document, compliance § 250.448(b)), have long used the term clarify BSEE’s authority to issue orders with § 250.107(a)(4) does not require a MASP, and BSEE does not believe that when necessary to protect health, safety, contractor or other individual the industry will have any difficulty property, or the environment. BSEE performing specific activities required understanding the meaning and use of received several comments on the by the part 250 regulations to be that term in this rule. proposed changes and additions to this knowledgeable about every term in a section but, for the following reasons, lease, permit or plan if those terms are C. Section-By-Section Summary and has included the proposed language in unrelated to the specific activities Responses to Significant Comments on the final rule without change. performed by the contractor. However, the Proposed Rule Comments Related to Proposed because existing § 250.146(c) makes any This summary discusses every section person who actually performs an of 30 CFR part 250 covered by the § 250.107—Suggested Standards for Incorporation activity jointly and severally responsible proposed rule and this final rulemaking; for compliance with the applicable sections of the existing regulations that Summary of comments: Commenters regulatory provision, such persons were not addressed in the proposed or expressed several concerns about this should be familiar with the terms and final rule are not included in this section. One commenter focused on the conditions of the lease, permit or plan summary. BSEE did not receive any performance-based intent of this that are relevant to that activity. substantive comments on numerous section. The commenter recommended sections covered by the proposed rule; that BSEE incorporate by reference Comments Related to Proposed those sections are included in this final established and well known standards § 250.107(a)(3)—Concerns Related to rule and are summarized here. BSEE (International Electrotechnical BAST received substantive comments on many Commission (IEC) 61508 and 61511)) to Summary of comments: Multiple other sections covered by the proposed support the provisions. The commenter commenters asserted that the new

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language in proposed § 250.107(a)(3) levels. The commenter noted that § 250.107(e) are reactive methods for would implicitly change the BAST regulators can play a role in defining enforcing performance requirements, provisions in former § 250.107(c). In and challenging companies’ risk control and that reactive methods are not particular, multiple comments focused measures, and that this active enough to reduce risks to the lowest on the requirement in proposed engagement with industry drives down level. § 250.107(a)(3) that lessees, operators, risk. The commenter also asserted that • Response: Regarding the entities to and others defined as ‘‘you’’ by many of the other requirements in the whom BSEE may issue orders under § 250.105 use ‘‘recognized engineering proposed rule are overly prescriptive. new § 250.107(e), it would be premature practices’’ to reduce risks to the lowest The commenter suggested that and speculative for BSEE to identify in practicable level. These commenters prescriptive requirements can lead to advance all of the parties to whom any noted that the term ‘‘recognized safety plateaus, instead of continual specific order may be issued. Orders engineering practices’’ is not defined in improvements, and that some of the will be issued on a case-by-case basis as the regulations and questioned what standards referenced in the proposed appropriate under the particular practices would be considered as rule may not always reflect current circumstances of each case. BSEE has ‘‘recognized’’ and where the recognized industry best practices and, thus, would legal authority to issue shut-in orders to practices would be referenced. not encourage innovation. The lessees, operators (if designated) and Commenters also questioned what commenter stated that it would be better any person (including contractors) who would happen if arguably better for BSEE’s regulations to include actually performs any activity to which engineering methods and practices are provisions that adapt in real-time to a regulation or lease, plan or permit developed in the future, but are not yet industry best practices and innovations. term applies. Whether or not BSEE generally ‘‘recognized’’ by industry. • Response: BSEE agrees with the orders a contractor to shut-in operations • Response: It is unclear why the commenter’s suggestion that it is often (suspension), BSEE typically also issues commenter believed the new appropriate to use performance-based a corresponding order to the lessee or requirements proposed in requirements that set safety and designated operator in these cases. § 250.107(a)(3) would change the BAST environmental protection goals and BSEE agrees with the comment stating provisions in § 250.107(c). The encourage innovation and continual that orders issued under this section commenter may have assumed that the improvement in meeting those goals, could, at least in some cases, be new requirement would supersede or be and that new § 250.107(a)(3) is such a ‘reactive’’ in nature, and that reactive inconsistent with the requirement to use requirement. In addition, numerous measures alone may not be enough to BAST whenever practical. However, other provisions in this final rule are reduce risks to the lowest level. § 250.107(a)(3) does not change the also performance-based. As to the However, any orders issued under BAST requirement; in fact, the new commenter’s suggestion that there may § 250.107(e) would be only one of many requirement is intended to complement be additional opportunities to include measures established by this final rule, the BAST provision by establishing a more performance-based measures most of which set performance goals or risk-based goal (to reduce risks to the (presumably in lieu of prescriptive prescribe specific measures to be taken lowest practicable level), and a requirements) in this rule, the in advance of any harm, to improve performance-based requirement that commenter provided no specific safety and environmental protection. lessees/operators meet that goal by alternatives for BSEE to consider. In any BSEE has determined that orders using recognized engineering practices, event, as explained elsewhere in this authorized by paragraph (e) are an when conducting certain regulated document, the final rule revises several appropriate complement to those other activities (i.e., design, fabrication, provisions of the proposed rule, as measures to ensure that the regulations, installation, operation, inspection, suggested by other commenters, to make as a whole, achieve their protective repair, and maintenance). Such risk them less prescriptive and more purpose. reduction and performance-based performance-based (e.g., the revised safe approaches are used in other provisions drilling margin provision in final Service Fees (§ 250.125) of this final rule and other BSEE § 250.414(c)). On the whole, BSEE The table in this section of the regulations. believes that this final rule effectively existing regulation lists fees that Regarding the specific comments on combines prescriptive and performance- operators must pay to BSEE for certain ‘‘recognized engineering practices,’’ based measures, as appropriate, to services. BSEE proposed to revise this BSEE expects that those practices may ensure and improve well control and to section to reflect the current citation for be drawn, for example, from established prevent harm to persons and the payment of the service fee relating to codes, industry standards, published environment. DWOPs. BSEE received no substantive peer-reviewed technical reports or comments on this provision of the Comments Related to Proposed industry recommended practices, and proposed rule and has included the § 250.107(e)—Concerns About BSEE- similar documents applicable to proposed language in the final rule Issued Orders relevant engineering activities. BSEE without change. may issue additional guidance on such Summary of comments: A commenter Documents Incorporated by Reference issues in the future, when and if specific asked whether orders issued by BSEE (§ 250.198) circumstances warrant such guidance. under proposed § 250.107(e) (e.g., to ensure compliance with 30 CFR part This section of the existing regulation Comments Related to Proposed 250 regulations, or to prevent serious, includes citations and other information § 250.107(a)(3)—Suggestions for irreparable or immediate harm, or to regarding all documents (e.g., industry Alternative Approaches To Reducing stop violations of the law) would be standards) incorporated by reference in Risks issued to both the ‘‘lessee, the owner or 30 CFR part 250, including where to Summary of comments: One holder of operating rights, a designated find references to the incorporated commenter commended BSEE for operator or agent of the lessee(s)’’ and to documents in specific sections of the proposing the general performance- any person actually performing the regulations. This section also discusses based requirement in § 250.107(a)(3) to activity. Another commenter stated that BSEE’s process for incorporating reduce risks to their lowest practicable the orders described in proposed documents by reference, the regulatory

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effects of incorporation, and procedures Comments Related to Proposed other than those incorporated by that operators may follow to seek § 250.198—Concerns About the reference, if they can demonstrate an BSEE’s approval to comply with Incorporation of Earlier Editions of equivalent level of safety and alternatives to an incorporated Standards environmental protection, pursuant to document. BSEE proposed revising this Summary of comments: A number of § 250.141. section to add references to the commenters noted that some of the Comments Related to Proposed standards to be incorporated by standards proposed for incorporation by § 250.198—Effective Dates of Standards reference in subpart G. BSEE received reference in this rule do not reflect the Summary of comments: Other several comments on the proposed current editions of those standards. additions to § 250.198. BSEE considered commenters requested that, for Commenters requested that BSEE standards applicable to equipment those comments and, for the following update those standards to the current reasons, has retained the proposed requirements under this rule, BSEE add editions when incorporated in the final provisions that allow the operator to use language, without change, in the final rule. Commenters stated that the rule. the standard that was in effect at the updated standards reflect the latest date the specific equipment was Comments Related to Proposed knowledge and experience of industry manufactured. This would prevent § 250.198—Technical Support experts resulting from a collaborative existing equipment and facilities that Documents review of the standards. They also were manufactured and accepted under stated that older editions of some Summary of comments: A commenter previous standards from being rendered standards are no longer available, and obsolete by regulations incorporating requested that BSEE publish ‘‘technical that incorporation of older editions may support documents’’ summarizing its newer standards. One commenter noted create confusion. Commenters suggested that BSEE is taking that approach with work in reviewing each standard that it that, to resolve the issue of keeping proposed to incorporate by reference in another rulemaking; i.e., proposed incorporated standards up to date, BSEE updating of the edition of API Spec. 2C this rule, including a determination that should remove references to specific each standard is BAST. for offshore pedestal-mounted cranes editions of the standards and add currently incorporated in § 250.108 (see • Response: All of the documents language to the regulations that refers to 80 FR 34113 (June 15, 2015)). proposed to be incorporated by the ‘‘most current edition’’ of a Commenters specifically cited the need reference in this rulemaking were and standard. to apply this approach to four standards • are available for public review. The Response: BSEE recognizes the proposed for incorporation in this rule: National Technology Transfer and concern related to incorporating the ANSI/API Spec. 16A, ANSI/API Spec. Advancement Act (NTTAA) of 1995 most current edition of each standard. 16C, API Spec. 16D, and API RP 17H. (Pub. L. 104–113) requires that BSEE BSEE reviews all standards incorporated However, another commenter rely on voluntary consensus standards by reference to ensure they are recommended that BSEE require where practical, Public Law 104–113, appropriate and technically sound. operators with existing equipment to section 12(d). BSEE reliance on these BSEE can choose to keep a certain comply with the latest industry standards is principally achieved edition in the regulations even if there standards contained in API Standard 53. through incorporation by reference of is an updated edition (e.g., if BSEE does • Response: BSEE has addressed industry standards into the bureau’s not agree with the technical changes or comments regarding the applicability of regulations. It is unclear what options allowed in a newer edition of an this rule’s equipment requirements to ‘‘technical support documents’’ the industry standard). This is done on a existing equipment and facilities (e.g., commenter is referring to, but the case-by-case basis for each standard. requests to ‘‘grandfather’’ in existing NTTAA does not require an agency to The change to a new edition, or removal equipment and facilities) in part VI.B of publish its underlying deliberations on of a discontinued standard, is not this document. With respect to the why it is appropriate to incorporate by automatic and requires rulemaking. (In suggestion that BSEE require reference a specific standard. BSEE has some cases, BSEE may use a direct final compliance with the ‘‘latest . . . explained its reasons for incorporating rule to incorporate new editions of standards’’ referenced in API Standard the standards referenced in this standards already incorporated, if the 53, BSEE must follow the provisions of rulemaking in both the proposed rule new edition meets the requirements of the NTTAA and the guidelines issued and this preamble. § 250.198(a)(2)). BSEE is actively by the OMB in Circular No. A–119 for In addition, BSEE does not make a reviewing new editions of many incorporation of voluntary consensus BAST determination in connection with standards, although newer editions are standards. Under Circular No. A–119, the incorporation of industry standards. constantly in development. the date of issuance of the standard BSEE’s authority under the NTTAA to Moreover, BSEE is prohibited, under being incorporated must be included in incorporate industry standards into applicable rules governing the regulation. Similarly, existing BSEE regulations is separate from the incorporation by reference, from § 250.198(a)(1) requires that an authority to require BAST under automatically incorporating future incorporation by reference is limited to OCSLA. The NTTAA mandates that amendments to or editions of a a specific edition of the incorporated Federal agencies use technical standards standard. (See 1 CFR 51.2(f); 30 CFR document and does not include future developed or adopted by voluntary 250.198(a)(1).) However, operators may revisions to that document. Thus, BSEE consensus standards bodies, as opposed comply with a later edition of a may not simply incorporate ‘‘the latest to using government-unique standards, standard incorporated in BSEE edition’’ of any standard, as suggested when practical. BSEE follows the regulations if the operator demonstrates by the commenter. However, as requirements of the NTTAA and of that compliance with the newer edition previously explained, BSEE may OMB Circular A–119 when is at least as protective as the approve compliance with a later (or an incorporating standards into the incorporated edition, and if BSEE earlier) edition of an incorporated regulations. These are not tied to the approves the alternative compliance. standard if an operator requests and BAST concepts derived from OCSLA or (See 30 CFR 250.198(c).) Operators can justifies such an alternative under its implementing regulations. also continue to use older standards, § 250.198(c) or § 250.141.

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For the same reason, BSEE does not Spec. 16A, API Spec. 16C, API Spec. unrestricted, and online access to the agree with the commenters’ suggestion 16D, and API Spec. 17D), in the standards incorporated by reference in that the rules allow an operator to use regulations (see final § 250.732(a)(2)) so the proposed rulemaking. The equipment that meets whatever that it is clear when compliance with commenters asserted that BSEE had ‘‘standard was in effect at the date the those documents is required. This is failed to make the incorporated specific equipment was manufactured.’’ also consistent with guidance from the materials reasonably available to the Under the NTTAA and implementing Office of the Federal Register (OFR) public, to discuss in the proposed rule regulations, any equipment standard related to the incorporation of second- preamble how it worked to make those that BSEE incorporates by reference tier documents. (See 78FR 60,784, materials reasonably available to must be identified by date and edition 60,794–95 (Oct. 2, 2013).) interested parties, and to summarize in number. However, BSEE has addressed the preamble the material it proposed to Comments Related to Proposed the ‘‘grandfathering’’ issue for existing incorporate, and thus that BSEE had equipment in part VI.B.4 of this § 250.198—Additional Standards violated the OFR regulations at 1 CFR document. And, where applicable, BSEE Documents Suggested for Incorporation 51.5(a). The commenters further may approve compliance with an earlier Summary of comments: Commenters asserted that, by failing to provide edition of an incorporated standard if an suggested that in addition to updating access to the incorporated standards, the operator requests and justifies such an the incorporation of API Spec. 6A, BSEE proposed rule violated the APA because alternative under § 250.198(c) or should also incorporate API Standard the proposed rule did not include § 250.141. 6ACRA, First Edition, (June 2015) and ‘‘either the terms or substance of the API Spec 6A718, First Edition (March proposed rule or a description of the Comments Related to Proposed 2004), for completeness. subjects or issues involved.’’ (See 5 § 250.198—Normative References • Response: BSEE agrees that certain U.S.C. 553(a).) The commenters Summary of comments: Several documents are more effective if recommended that BSEE re-publish the commenters suggested that BSEE should incorporated with other associated proposed rule, with the standards not directly incorporate normative documents. However, we did not available freely online. references (second-tier documents) used include the suggested documents in the The commenters also asserted various in an incorporated standard (first-tier proposed rule, and BSEE has not yet technical obstacles to purchasing the document), in particular, API Standard determined whether those standards standards (both for print and online) 53.12 Those commenters supported the should be incorporated in the from API and to viewing them in person incorporation of API Standard 53 in its regulations. We may consider these at BSEE’s offices. The commenters also entirety, and asserted that the normative documents for incorporation in the raised numerous objections to the references contained in that standard future using the evaluation process manner in which API presents the would also implicitly apply. One previously described. If BSEE decides to documents online, including technical commenter also stated that separately incorporate these documents, we will hurdles for visually impaired people to incorporating the normative references do so through a separate rulemaking. view the standards online. The within API Standard 53 would confuse commenters also asserted that BSEE is the operators. However, other Comments Related to Proposed in violation of the Rehabilitation Act of commenters suggested that concerns § 250.198—Effective Dates of 1973 because visually impaired related to applying the edition of an Documents individuals are not able to view the equipment standard in existence at the Summary of Comments: A commenter standards properly on API’s Web site. time the equipment was manufactured requested that we remove the effective They also asserted that there is no (as previously discussed) would be dates from the citations of standards in guarantee by BSEE that the currently minimized if the normative references § 250.198. The commenter suggested free online access for viewing the in those standards were not that the effective dates are of the standards on API’s Web site will last. incorporated by reference in BSEE’s monogram licenses, not for general Another commenter requested that, if regulations. industry use of the documents, and BSEE cannot make the documents Commenters asked if it was BSEE’s including the effective dates in the available to the general public, BSEE intent to require the application of the regulations could cause confusion. A should, at a minimum, grant access to normative references in API Standard 53 commenter recommended that BSEE use certain types of organizations (e.g., local for purposes other than their relation to the descriptions shown in the API governments). the provisions of API Standard 53 to be Publications Catalog, which only • Response: These comments do not incorporated in the final rule. If so, they include the standard number, title, address the substantive merits of the requested that BSEE should specifically publication date, and any errata/ proposed rule. Rather, the comments state those other purposes in the final addenda. principally focus on legal criteria rule. • Response: BSEE disagrees. As relevant to BSEE’s incorporation by • Response: BSEE recognizes that previously stated, BSEE is required to reference of various industry standards. compliance with a normative reference include certain information from the Many of the detailed assertions in the in an incorporated standard is implicitly standard, including the dates and comments (e.g., complaints about API’s necessary at times to ensure actual editions of the incorporated documents, Web site advertisements) are outside the compliance with an incorporated when incorporating documents by scope of this rulemaking as well as standard. However, BSEE has decided to reference. (See § 250.198(a)(1); 1 CFR unrelated to BSEE’s compliance with expressly incorporate the normative 51.9(b)(2).) applicable regulations for incorporating references within API Standard 53 (i.e., documents by reference, and thus do relevant provisions of API Spec. 6A, API Comments Related to Proposed not require any further response. § 250.198—Availability of Incorporated In determining which industry 12 ‘‘Normative references’’ are typically other Standards standards to incorporate by reference documents incorporated by reference within a standard that are considered necessary for Summary of comments: Two into its regulations, BSEE has carefully compliance with specific parts of the ‘‘first-tier’’ commenters asserted that BSEE acted evaluated potentially relevant standard. illegally by not providing free, standards, considered input from

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various interested stakeholders, and in person at BSEE’s offices in Sterling, Under the OFR regulations, BSEE is proposed for incorporation those VA, or at NARA’s offices in Washington, permitted to incorporate copyrighted standards that BSEE determined, in its DC. These actions are consistent with materials into its regulations. Implicit judgment, would reasonably serve the BSEE’s prior rulemakings incorporating within that permission is the fact that safety and environmental protection many other standards in the part 250 access to and presentation of certain purposes of its regulations. In regulations. Moreover, BSEE received incorporated standards is controlled developing this final rule, BSEE also informal approval from OFR for the principally by the third-party copyright considered public comments on the proposed incorporations by reference in holder. While BSEE works diligently to proposed rule regarding which the proposed rule, and formal approval maximize the accessibility of standards would best serve those for the final incorporations in this final incorporated documents, and offers purposes, as discussed elsewhere in this rule, in accordance with OFR’s direction to where the materials are document. In doing so, BSEE has also regulations (1 CFR 51.3 and 51.5), reasonably available, it also must complied with the mandate of the which include the requirement for ultimately respect the publisher’s NTTAA (previously discussed) to make making the documents reasonably copyright. Accordingly, issues related to use, where appropriate and practical, of available. how API structures its Web site or existing consensus standards in lieu of Similarly, we disagree with the formats its copyrighted materials offered developing new government regulatory commenters’ claim that the proposed for free access are outside of BSEE’s standards. rule violated the APA by failing to control and beyond the scope of this Moreover, BSEE disagrees with the adequately describe the materials rulemaking. commenters’ claims that BSEE failed to proposed for incorporation. To the discuss the actions it took to ensure that contrary, the proposed rule adequately Paperwork Reduction Act Statements— the materials incorporated in these rules described the referenced standards (see Information Collection (§ 250.199) were, and will be, reasonably available 80 FR 21506–21508), as does this This section of the existing regulation or to actually make the materials document. In addition, OFR’s informal provides the OMB control numbers reasonably available. In proposing approval of the proposed associated with information collections certain standards for incorporation in incorporations, and its formal approval under each subpart of part 250, and the final rule, and finalizing such of the incorporations in this final rule, generally provides BSEE’s reasons for incorporations in this final rule, BSEE means that OFR agrees that BSEE has collecting the information and explains has followed the requirements and met the requirement in the OFR how the information is used. BSEE procedures for incorporation by regulations for describing the proposed to revise this section by reference set out in OFR’s regulations. incorporated materials. (See 1 CFR updating the OMB control numbers, by (See 1 CFR part 51.) 51.5(a)(2) and (b)(3).) rewording some of the explanations for In order to be eligible for In addition, contrary to commenters’ BSEE’s information collections, and by incorporation by reference, a document claims that BSEE must provide free, adding references to proposed new must be ‘‘reasonably available’’ to downloadable copies of the standards information collections. After affected persons (1 CFR 51.5, 51.7(a)(3)) on its Web site, notwithstanding API’s considering comments submitted on and the notice of proposed rulemaking copyright claims to those standards, this section, BSEE has included the must discuss how the incorporated OFR has expressly concluded that an proposed language in the final rule document is reasonably available to agency’s incorporation by reference of without significant revisions. However, interested parties or how the agency copyrighted material does not result in in response to certain comments, BSEE worked to make those documents the loss of that copyright.13 OFR has revised the estimated burden hours reasonably available. (See id. at reached this conclusion based in part on for compliance with some of the § 51.5(a)(1).) The notice of final its analysis of the decision in Veeck v. information collections in the final rule, rulemaking must also discuss the ways Southern Building Code Congress as explained in the following responses. that the incorporated document is International, Inc., 293 F.3d 791 (5th Comments Related to § 250.199— reasonably available to, and how it can Cir. 2002). In the preamble to its General Requirements for Well be obtained by, interested parties. (See recently promulgated amendments to Operations and Equipment id. at § 51.5(b)(2).) the rules for incorporation by reference, The primary regulated community for OFR stated: Summary of comments: Several commenters raised concerns that these regulations is the offshore oil and that recent developments in Federal law, gas industry, for which the costs for including the Veeck decision and the additional time would be needed to purchasing a copy of the industry amendments to the Freedom of Information account for requests for departures from standards (if they choose to do so) Act (FOIA), and the NTTAA have not operating requirements, as provided in incorporated by reference in this final eliminated the availability of copyright § 250.702, and for requests for approval rule are not unreasonable. For other protection for privately developed codes and to use new or alternative procedures or members of the public (including other standards referenced in or incorporated into equipment during operations, as Federal regulations. Therefore, we agreed provided in § 250.701. For example, government entities), BSEE discussed in with commenters who said that when the the preamble to the proposed rule (see Federal government references copyrighted some commenters asserted that the 80 FR 21506), and in this document works, those works should not lose their proposed requirement for use of subsea (under ‘‘Availability of Incorporated copyright. BOPs with ‘‘dual-pod control systems’’ and kelly valves will lead to requests for Documents for Public Viewing’’), the (See 79 FR 66273.) reasonable methods by which the departures and for alternative procedures. The commenter explained standards incorporated here may be 13 Contrary to some commenters’ claims, OFR’s reviewed, inspected, copied, or regulations also do not require BSEE to provide that such requests would be likely purchased. free, downloadable copies of the incorporated because API Standard 53 requires In brief, BSEE explained in both documents online, whether or not they are subsea stacks to ‘‘have fully redundant copyrighted. OFR expressly rejected that suggestion documents how any member of the in its recent document promulgating the current control pods’’ and because kelly valves public may review the referenced regulations governing incorporation by reference. are no longer in widespread use in standards for free on API’s Web site or (See 79 FR 66267 (Nov. 7, 2014).) offshore drilling operations.

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• Response: As discussed later in this with this final rule as described in part subsea BOP, a BOP used in an HPHT part of the document, we have revised VIII (Paperwork Reduction Act (PRA) of environment, or a surface BOP used on the requirement for subsea BOPs with 1995). a floating facility. Specifically, they ‘‘dual-pod control systems’’ to require asserted that BSEE failed to account for Comments Related to § 250.199— only a ‘‘redundant pod control system.’’ the burden of obtaining BAVO Tubing and Wellhead Equipment This change will align the pod certification of the MIA Report, as requirement in the regulations with the Summary of comments: One required by proposed § 250.731(f). language of API Standard 53. BSEE commenter asserted that it may not be • Response: BSEE does not agree that agrees with the comment about the possible to set a packer deep enough to any additional burden hours should be limited availability of kelly valves and have a column of kill weight fluid at the added for compliance with § 250.730(d). has revised final § 250.736(d)(1) by packer. As a result, additional That provision does not create any new replacing the references to kelly valves engineering time would be required to information collection burdens since it with ‘‘applicable [k]elly-type valves’’ as comply with the § 250.518(e) requires compliance with existing described in API Standard 53. requirement for tubing and wellhead industry standards, the costs of which Regardless, BSEE does not agree with equipment for completion operations to are included in the economic baseline. the commenters’ assertions regarding determine if the casing design is However, BSEE has increased the increased paperwork burdens. suitable. burden hours for requesting approval to Ultimately, the requests for alternate • Response: BSEE agrees with the use new or alternative procedures, along procedures or equipment and requests comment and has increased the burden with supporting documentation if for departures referenced in §§ 250.701 for APMs to account for the descriptions applicable under § 250.730, should an and 250.702 are voluntary submissions and calculations of packer depths operator seek to deviate from the made pursuant to longstanding required by this rule. requirements of § 250.730(d). BSEE has regulations found at §§ 250.141 and Comments Related to § 250.199—Well also increased the burden hours for 250.142, and thus do not reflect a new Operations complying with the § 250.731(f) MIA paperwork burden under this rule. Report certification requirement. Summary of comments: We received Comments Related to § 250.199—APDs numerous comments on the § 250.724(b) Subpart B—Plans and Information Summary of comments: Several proposed RTM requirements. What must the DWOP contain? comments requested that we include Commenters stated that such monitoring (§ 250.292) additional burden hours to prepare on all well operations, including required permitting information. One shallow water shelf operations, would This section of the existing regulation commenter stated that the dual riser result in significant additions to the specifies information (e.g., description requirement in proposed § 250.733(b) sensor, data integration, data telemetry of the typical wellbore, structural design may require additional engineering time band width, data reception and storage, for each surface system) that must be to assure existing floating production and data monitoring and interpretation included in a DWOP. BSEE proposed no facilities have the room to accept dual burden for all operators. They also changes to existing paragraphs (a) bore risers or dual shear ram BOPs. expressed concern about how to comply through (o) of § 250.292, and the final Another commenter stated that, to meet with the new requirements to conduct rule makes no changes to those the requirements in § 250.734(c) for continuous RTM of the BOP control paragraphs. BSEE proposed to add a drilling out the surface casing in a new system, the well’s fluid handling new paragraph (p) to this section and to well with a subsea BOP, additional systems on the rig, and the well’s redesignate existing paragraph (p) as burden hours would be needed to downhole conditions with the bottom paragraph (q). Proposed new paragraph submit a revised APD, including the hole assembly tools, and provisions for (p) specified information that must be required third-party verifications, and to storage of the data. included in the DWOP if the operator obtain BSEE’s approval. • Response: BSEE agrees with the proposes to use a pipeline FSHR One commenter stated that comment and has increased the burden meeting certain conditions. This § 250.418(g) of the proposed rule would hours to account for the development information is used in planning for likely require additional engineering and implementation of an RTM plan, as production development. BSEE received time to develop a well abandonment required by the final rule, that includes several comments on this proposed plan that includes wash out or cement all data required by § 250.724. addition, and for the following reasons, displacement to facilitate casing has included proposed paragraph (p) in removal upon well abandonment. Comments Related to § 250.199—BOP the final rule with one revision to the Another commenter stated that an System Requirements proposed language, as described in the additional man-day per individual well Summary of comments: We received following response and in part V.C of would be needed to provide a comments claiming that additional this document. Former paragraph (p) is description of the source control and engineering time would be necessary to also included in the final rule, without containment capabilities and receive comply with the requirements of change, as new paragraph (q). § 250.730(d). Since § 250.730(d) requires APD approval pursuant to § 250.462(c). Comments Related to § 250.292(p)— We also received a comment that any BOP stack manufactured after Pipeline Freestanding Hybrid Risers requesting that we increase the the effective date of the regulation (FSHRs) estimated burden hours given that comply with API Spec. Q1, the additional drilling prognosis commenter stated that additional Summary of comments: Commenters information in the APD may be required burden hours will be needed to design suggested that BSEE apply § 250.292(p) by the District Manager under a BOP stack that complies with API only to permanent FSHRs, and not to § 250.414(k). Spec. Q1. risers used for exploratory wells or for • Response: BSEE agrees with several In addition, several commenters source control and containment. Those of the commenters’ assertions and has stated that there is an additional burden commenters noted that exploration increased the burden estimate for involved with submittals of an MIA wells are not covered under the existing preparing APDs and APMs to comply Report as required by § 250.732(d) for a DWOP regulations (§§ 250.286 through

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250.295), which apply to deepwater What drilling unit movements must I Comments Related to Proposed development projects, and that risers report? (§ 250.403) § 250.413(g)—Well Drilling Design used for source control and containment Criteria are not part of a permanent installation. BSEE proposed to remove and reserve this section of the existing regulation Summary of comments: Multiple • commenters had concerns regarding the Response: BSEE agrees that this and to move the content of this existing requirement applies only to permanent requirement in proposed § 250.413(g) regulation to proposed § 250.712. BSEE FSHRs for development projects under that well drilling design criteria include received no comments on the proposed a DWOP. It is incorporated into a a plot showing maximum ECD. They removal and reservation of this section regulation setting forth requirements for stated that operators need to manage and the final rule implements that the contents of a DWOP. Accordingly, it and adjust ECD during real-time action. is inapplicable to operations that do not operations, and thus no margin between require a DWOP. BSEE would permit What additional safety measures must I ECD and fracture pressure or safety temporary FSHRs, such as those used take when I conduct drilling operations margin should be required to be with containment systems to respond to on a platform that has producing wells specified in advance as part of the APD. an emergency, on a case-by-case basis. or has other hydrocarbon flow? The commenters also suggested that, BSEE has revised this paragraph in the (§ 250.406) since the intended use of the ECD final rule to clarify that it applies only cannot be specified in advance, it to FSHRs ‘‘on a permanent installation.’’ BSEE proposed to remove and reserve should be deleted from § 250.413(g). this section of the existing regulation • Response: BSEE agrees with the Subpart D—Oil and Gas Drilling and to move the content of this former commenters that, since ECD may need Operations General Requirements section to proposed § 250.723. BSEE to be adjusted during operations, BSEE (§ 250.400) received no comments on the proposed would need to provide more removal and reservation of this section clarification about how to determine This section of the existing regulation maximum ECD in order for operators to was entitled ‘‘Who is subject to the and the final rule implements that action. include it within the plots. Therefore, requirements of this subpart?’’ BSEE BSEE removed the reference to ECD proposed to revise, this entire section, What information must I submit with from final § 250.413(g) and inserted in including the section heading, to require my application? (§ 250.411) its place a requirement to plot the that drilling operations be done in a safe planned safe drilling margin, as manner to protect against harm or This section of the existing regulation required to be included in the APD by damage to life (including fish and other specified certain information that must final § 250.414(c). This planned safe aquatic life), property, natural resources be included in an APD, including drilling margin is based in part on the of the OCS (including any mineral descriptions of ‘‘diverter and BOP planned ECD and thus will provide deposits), the National security or systems.’’ BSEE proposed to slightly information essentially equivalent to defense, or the marine, coastal, or revise this section to separate the what inclusion of the maximum ECD human environment. BSEE also requirements for diverter and BOP would have provided. proposed to clarify that, for drilling descriptions, and to updates the cross- operations, the operator must follow the What must my drilling prognosis reference in the section to include new include? (§ 250.414) requirements of this subpart and the subpart G. BSEE received no substantive applicable requirements of proposed comments on this provision of the This section of the existing regulation subpart G. BSEE received no substantive proposed rule and made no changes to describes the information that must be comments on this proposed provision the proposed language, which is included in the drilling prognosis and made no changes to the proposed included in the final rule. portion of an APD. BSEE did not language, which is now included in the propose any changes to paragraphs (a) final rule. What must my description of well and (b), and paragraphs (d) through (g), drilling design criteria address? of the existing regulation and they have What must I do to keep wells under (§ 250.413) been retained unchanged. BSEE control? (§ 250.401) proposed to revise paragraphs (c), (h), This section of the existing regulation and (i) of the existing regulation and to BSEE proposed to remove and reserve specifies the type of information that add new paragraphs (j) and (k) to this section of the existing regulation must be provided in the well drilling § 250.414. Specifically, BSEE proposed: and to move the content of this former description portion of an APD. BSEE To revise paragraph (c) to better define section to proposed § 250.703. BSEE did not propose any changes to the safe drilling margin requirements; received no comments on the proposed paragraphs (a) through (f) of the former clarify paragraphs (h) and (i) with minor removal and reservation of this section § 250.413, which are retained wording changes; to add a new and the final rule implements that unchanged. BSEE proposed to revise paragraph (j) requiring that the drilling action. former paragraph (g) to require that the prognosis include both the type of When and how must I secure a well? maximum ECD be included on the pore wellhead and liner hanger systems to be (§ 250.402) pressure/fracture gradient plot in the installed and a descriptive schematic; APD. BSEE received multiple comments and to add a new paragraph (k) BSEE proposed to remove and reserve on the proposed changes to paragraph requiring submittal of any additional this section of the existing regulation (g) and, for the following reasons, has information required by the District and to move the content of this former decided to revise the proposed language Manager as needed to clarify or evaluate section to proposed § 250.720. BSEE to require that the ‘‘planned safe drilling the drilling prognosis. BSEE received received no comments on the proposed some comments on proposed paragraph margin,’’ instead of the ECD, be removal and reservation of this section (j), but has included that paragraph in included on the pore pressure/fracture and the final rule implements that the final rule without change. BSEE gradient plot under the final rule. action. received many comments on the

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proposed changes to paragraph (c) and paragraph (c) in the final rule to require drilling margins, such as depleted sands on proposed paragraph (k). After a planned safe drilling margin that is or below salt (common occurrences in considering the comments, and for the between the estimated pore pressure the GOMR). Industry will be able to reasons stated in the following and the lesser of estimated fracture determine and use (subject to BSEE responses to those comments, BSEE has gradients or casing shoe pressure approval) appropriate mud properties revised the language of proposed integrity test and based on a risk (density, viscosity, additives, etc.) best paragraphs (c) and (k) and included that assessment consistent with expected suited for a specific well interval based revised language in the final rule. well conditions and operations. Final on drilling and geological parameters. paragraph (c) also requires that the safe The final rule also revised the Comments Related to Proposed drilling margin include use of proposed language to refer to ‘‘off-set § 250.414(c)—Safe Drilling Margin equivalent downhole mud weight that is well’’—instead of ‘‘hole’’—conditions; Summary of comments: BSEE (i) greater than the estimated pore the final rule language will better align received extensive comments on the pressure, and (ii) except as provided in the regulatory language with industry proposed requirements in § 250.414(c) paragraph (c)(2), a minimum of 0.5 terminology and clarify BSEE’s intent. regarding safe drilling margins. The pound per gallon below the lower of the For a more in-depth discussion of the majority of these comments stated that casing shoe pressure integrity test or the changes to final § 250.414(c), refer to the proposed 0.5 ppg safe drilling lowest estimated fracture gradient. Final part V.B.1 of this document. margin would pose operational paragraph (c)(2) now clarifies that, in Comments Related to Proposed problems, reduce the safety of drilling lieu of meeting the criteria in paragraph operations, and lead to unintended § 250.414(j)—Wellhead System and (c)(1)(ii), operators may use an Liner Hanger System consequences. Commenters provided equivalent downhole mud weight as examples of concerns, such as limiting specified in the applicable APD, Summary of comments: BSEE the selection of drilling fluids; provided that the operators submits received comments on the proposed potentially requiring more casing strings adequate documentation (such as risk § 250.414(j) requirements related to or smaller production casing sizes; modeling data, off-set well data, analog wellhead system and liner hanger economic hardships due to not being data, seismic data) to justify the system information. Commenters stated able to reach reservoirs by setting more alternative equivalent downhole mud that operators will not have access to casing; decreased production from the weight. Finally, paragraph (c)(3) states machine drawings for equipment smaller hole sizes; and undue burden of that, when determining the pore purchased from manufacturers since submittals for alternative compliance. pressure and lowest estimated fracture this is considered proprietary data. A Recommendations to revise proposed gradient for a specific interval, the commenter recommended that the word § 250.414(c) included performance of a operator must consider related off-set ‘‘descriptive’’ be changed to ‘‘detailed’’ risk assessment and calculations to well behavior observations. and that BSEE allow documentation that establish safe drilling margins for each Although 0.5 ppg is typically an is available to the operator to be well and for each drilling interval appropriate safe drilling margin for provided to BSEE. within the well. normal drilling scenarios, BSEE • Response: BSEE disagrees with BSEE also received comments on the understands there are circumstances these comments and has made no proposed § 250.414(c)(3) requirements where a lower drilling margin may be changes to § 250.414(j) in the final rule. related to the ECD. Some commenters acceptable to drill a well safely. The BSEE is aware that operators typically interpreted this proposed language to revisions made in the final rule better receive schematics from the mean that drilling must stop when any define safe drilling margins, requiring manufacturers, and those schematics are lost circulation occurs. Clarifying the 0.5 ppg margin under most sufficient to meet the requirements for language was recommended as follows: circumstances, but providing operators describing the wellhead and liner ‘‘if lost circulation occurs, then the with the flexibility to use a lower safe hanger systems. In addition, it is unclear losses should be mitigated, and/or ECD drilling margin when appropriate. from the comment why a change from managed to reduce the effects of lost The changes in the final rule will ‘‘descriptive’’ to ‘‘detailed’’ would better circulation as per API Bulletin 92L.’’ alleviate, if not eliminate, much of classify the type of schematics available. We also received a comment on the industry’s operational and economic proposed requirements in § 250.414(c) concerns with the proposed 0.5 ppg Comments Related to Proposed for determining pore pressure and margin, including industry’s concern § 250.414(k)—Additional Information lowest estimated fracture gradients for that a 0.5 ppg drilling margin—with no Summary of comments: BSEE specific intervals. The commenter exceptions—would effectively preclude received comments on the proposed emphasized that the purpose for this the continued use of dynamic pressure § 250.414(k) requirement to provide any paragraph is to address planning drilling and inhibit development of new additional information required by the (prognosis) for drilling operations and technology. District Manager. Commenters stated that it should not apply to the actual By requiring justification for, and that this section should be restricted to operations. The commenter prior approval by BSEE of, any necessary information that can be recommended the following language: alternative to the 0.5 ppg margin, these reasonably supplied by the operator. ‘‘during planning for a specific interval, revisions will provide BSEE with the Commenters also suggested that the the relevant available offset hole information needed to make appropriate District Manager should provide behavior observations must be case-by-case decisions on specific justification to the operator for the considered.’’ drilling margins. BSEE could also use requested additional information. • Response: BSEE agrees with a this option to identify and focus its • Response: The District Manager majority of the comments on resources on the potentially higher risk may require additional information on § 250.414(c) and has not included well sections where the safe drilling the drilling prognosis on a case-by-case proposed paragraph (c)(3) in the final margin may be of greater concern. These basis, based on unique site or well rule (and renumbered proposed revisions will increase planning conditions. The District Managers paragraph (c)(4) as paragraph (c)(3) in flexibility for operators when drilling would, of course, take into account the the final rule). BSEE otherwise revised into areas that could require lower safe potential need for such information to

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protect personnel or the environment, systems and BOP systems contained in Comments Related to Proposed given the purposes of these regulations. an APD. BSEE proposed to revise this § 250.416(b)(1)—Diverter Systems Like many similar provisions section by removing former paragraphs Summary of comments: Another throughout part 250, § 250.414(k) is (c) through (f), which required certain commenter was concerned that intended to give District Managers the information for BOP system proposed § 250.416(b)(1) would require necessary flexibility and discretion to descriptions, which BSEE proposed to information in the APD about annular require information as needed in move to new §§ 250.703, 250.731 and BOPs in diverter housings, even though specific cases to fulfill the purposes of 250.732, and by removing paragraph (g), not all diverters use annular elements. the regulation. Nonetheless, BSEE has which specified criteria for independent The commenter stated that some slightly revised paragraph (k) in the third-parties that verify certain BOP diverters use ‘‘insert elements,’’ which final rule to confirm that the District information. Under the proposed rule, are not the same as annular BOPs, and Manager may require additional § 250.416 would include only the recommended that BSEE replace information needed to clarify or former language, in paragraphs (a) and ‘‘annular BOP’’ in proposed evaluate the drilling prognosis (b), regarding diverter descriptions and § 250.416(b)(1) with ‘‘sealing element.’’ submitted under this section. would be re-titled accordingly. Based on • Response: BSEE agrees with the What must my casing and cementing comments submitted on the proposed commenter that not all diverters use programs include? (§ 250.415) changes to this section, as explained in annular BOPs. Accordingly, BSEE has the following response, BSEE has revised this section in the final rule by This section of the existing regulation included former paragraph (a) in the replacing ‘‘annular BOP’’ with describes the information on casing and final rule without change, as proposed. ‘‘element,’’ which covers all of the cementing programs that must be BSEE also included former paragraph different types of components included in an APD. BSEE proposed no (b) in the final rule, with one minor (including annular BOPs and sealing changes to paragraphs (b) through (f) of change to the former paragraph (b)(1). elements) that may be installed in the this section, which have been retained diverter housing. unchanged in the final rule. BSEE Comments Related to Proposed proposed to revise former paragraph (a) § 250.416—Descriptions of Diverter What must I provide if i plan to use a of this section to require casing Systems mobile offshore drilling unit (MODU)? information for all sections of each (§ 250.417) casing interval. BSEE proposed that Summary of comments: One BSEE proposed to remove and reserve operators must include bit depths commenter was concerned that this section and to move the content of (including measured and true vertical proposed § 250.416 did not actually this former section to proposed depth (TVD)) and locations of any require use of equipment and § 250.713. BSEE received no comments installed rupture disks, and indicate instrumentation to identify on the proposed removal and either the collapse or burst ratings, in hydrocarbons that have travelled above reservation of this section and the final their APDs. Requiring this information the BOP and into the marine riser. The rule takes that action. for all sections for each casing interval commenter stated that current rigs have What additional information must I will make well design calculations and zero riser instrumentation (for submit with my APD? (§ 250.418) APD submittals more accurate and detecting/tracking hydrocarbons within provide a more complete representation the marine riser), and that they are This section of the existing regulation of the well. BSEE received one comment equipped with a diverter system. The specified certain additional information on the proposed § 250.415, and as commenter suggested that we (e.g., rated capacity of the drilling rig, discussed in the following response, has completely revise § 250.416(b) to require drilling fluids program) that must be included proposed paragraph (a) in the that diverters have riser instrumentation included in an APD. BSEE did not final rule without change. (such as ‘‘distributed’’ pressure gauges propose any changes to paragraphs (a) to measure differential pressures) that through (f) of the existing regulation, Comments Related to Proposed can confirm that the volume of gas does which are therefore retained unchanged. § 250.415—Quality Assurance not exceed a certain limit and impose BSEE proposed to revise paragraph (g) Summary of comments: One back-pressure to keep gas from coming of the existing regulation, which commenter suggested that we require a out of solution. requires operators to seek approval for Quality Assurance/Quality Control (QA/ • plans to wash out or displace cement to QC) plan for cement installation and Response: BSEE does not agree with facilitate casing removal upon well recommended that we add the QA/QC the suggestion that we should transform abandonment, by adding a requirement protocol to § 250.415 and require it for proposed § 250.416 from an to describe how far below the mudline each well. informational provision (i.e., requiring a the operator plans to displace cement • Response: Section 250.420(a)(6) of description of the diverter system) into and how the operator will visually the existing regulations already requires a substantive equipment provision monitor returns. This proposed change the casing and cementing design to requiring specific instrumentation. would provide information to assist include a certification signed by a Although BSEE agrees that there may be BSEE in deciding whether to approve registered PE. This verification of the some potential benefits from the use of such plans. BSEE received no casing and cementing design by a PE instrumentation on the riser, additional substantive comments on this proposed provides the necessary QA/QC. We research and study needs to be done addition to paragraph (g), which is have, therefore, made no changes to before BSEE could determine whether included in the final rule as proposed. final § 250.415 based on the comment. such a substantive requirement should be added to the regulations. If future What well casing and cementing What must I include in the diverter research or study reports or other requirements must I meet? (§ 250.420) description? (§ 250.416) information becomes available to BSEE This section of the existing regulation This section of the existing regulation warranting this additional requirement, imposes specific requirements for casing specified the information that must be BSEE may propose revision of this and cementing of all wells. BSEE included in the descriptions of diverter section in a future rulemaking. proposed to revise the introductory text

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of this section, to re-designate former centralization besides the use of revision will help resolve the paragraph (a)(6) as paragraph (a)(7), and centralizers, and BSEE expects that commenter’s concerns about the to insert a new paragraph (a)(6) that multiple methods may be required to weighted fluid being in the center of the requires adequate centralization to help ensure adequate centralization. BSEE well. ensure proper cementation. BSEE also relies on industry best practices and What are the casing and cementing proposed to add a new paragraph (b)(4), industry standards to help determine requirements by type of casing string? requiring approval by the District suitable methods for centralization (§ 250.421) Manager of changes to certain planned while cementing. BSEE also disagrees casing parameters, as well as a new with the commenter’s recommended This section of the existing regulation paragraph (c)(2), requiring the use of a inclusion of a reference to API Standard specifies casing and cementing weighted fluid during displacement to 65–2 (2nd Edition), since a written requirements applicable to certain types maintain an overbalanced hydrostatic description of how the operator of casing strings (e.g., drive or structural pressure during the cement setting time evaluated the relevant practices is strings, conductor strings). BSEE did not and thus enhance wellbore stability already required under § 250.415(f) propose any changes to paragraphs (a) during cementing. BSEE received and (‘‘What must my casing and cementing and (c) through (e) of the existing considered comments on proposed programs include?’’). Therefore, no regulation, which are therefore retained paragraphs (a) and (c) and, as explained changes to proposed paragraph (a)(6) are unchanged. BSEE proposed revising in the following responses, has included necessary, and BSEE has included that former paragraph (b), however, to proposed paragraph (a) in the final rule paragraph in the final rule as proposed. specify that if oil, gas, or unexpected without change. BSEE also included formation pressure is encountered, the Comments Related to Proposed proposed paragraph (c) in the final rule, operator must set conductor casing § 250.420(c)—Cement Compressive but revised proposed paragraph (c)(2) immediately, above the encountered Strength slightly in response to this section’s zone, even if that is before the planned summary of comments and responses. Summary of comments: One casing point. This proposed provision commenter suggested that BSEE was intended to ensure that conductor Comments Related to Proposed increase the required compressive casing is not placed across a § 250.420(a)—Centralizers strength of cement (500 psi) under hydrocarbon zone. BSEE also proposed Summary of comments: One comment proposed § 250.420(c)(1) in order to to revise former paragraph (f) to was submitted by multiple commenters reduce the risk of cement failure, eliminate the potential use of liners as on the proposed requirement in especially in zones of critical cement conductor casing. This proposed § 250.420(a)(6) for use of centralization where pressures and stresses are higher. revision would help ensure that the to ensure proper cementation. It stated The commenter also recommended drive pipe is not exposed to wellbore that the proposed requirement needs to adding a requirement for the cement pressures. BSEE received and be changed to allow for methods other mixture in the zone of critical cement to considered comments on proposed than centralizers to meet the cementing meet a 1,200 psi compressive standard paragraphs (b) and (f) and, as explained requirements of this section because within 72 hours. in the following responses, has retained there are instances where using • Response: BSEE disagrees and has proposed paragraph (b) in the final rule centralizers will actually increase risk. retained the proposed language without change. However, the final rule The commenters provided examples of requiring 500 psi compressive cement revises the proposed language in the need for centralization, including strength, which is the same as the paragraph (f) as discussed in the the inability to ream down casing and requirement in the former paragraph (c), following responses and in part V.C of the likelihood of greater casing wear if in the final rule. This requirement is this document. the pipe is not centered. The also consistent with the provisions in Comments Related to Proposed commenters also provided examples, API RP 65 part 2, already incorporated § 250.421(b)—Conductors however, of why centralizers should not in the existing regulations, and with be the exclusive method for industry practice. Summary of comments: Some centralization, including the assertion comments on proposed § 250.421(b) that centralizers may increase the Comments Related to Proposed requested clarification as to whether the chance of pack-off, increase the number § 250.420(c)(2)—Cementing 22-inch and 20-inch casing used in of connections in the casing string Summary of comments: One comment deepwater operations is considered (because centralizer subs are often the was submitted by multiple commenters surface pipe and therefore subject to only option for centralization), and on the requirements in proposed regulation under § 250.421(c) damage the wellhead components (due § 250.420(c)(2) for use of weighted (requirements for surface casing) rather to centralizer pass through). One fluids during cementing. The comment than § 250.421(b) (requirements for commenter recommended the following stated that the proposed casing and conductor casing). If BSEE agrees with alternative language: ‘‘Provide adequate cementing requirements increase the that view, the commenter has no centralization and/or other methods to risk of lost circulation, which will result objection to proposed § 250.421(b) with aid proper cementation to meet well in failure to achieve zonal isolation. The regard to 20- and 22-inch casing. design objectives within the constraints commenter suggested that, if A commenter also requested imposed by hydraulic, operational, § 250.420(c)(2) refers to conditions at confirmation that drive pipe and jetted logistical or well architecture the center of the well, the language pipe are considered structural pipe and limitations (ref. [API] Standard 65–2 should be revised to provide: ‘‘You must therefore are subject to regulation under 2nd Edition.)’’ use a weighted fluid during former § 250.421(a) (requirements for • Response: The commenter displacement.’’ drive or structural casing) rather than incorrectly assumes that § 250.420(a)(6) • Response: BSEE agrees with the the proposed § 250.421(b). If BSEE provides for the use of centralizers only. commenter and has revised agrees with that view, the commenter That provision does not specify or limit § 250.420(c)(2) in the final rule by has no objection to proposed how centralization should be achieved. clarifying that a weighted fluid must be § 250.421(b) with regard to drive pipe There are many options to ensure used ‘‘during displacement.’’ This and jetted pipe.

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One commenter suggested rewording rephrasing would add any extra clarity In support of the suggested change, the the proposed revision to the existing or change the meaning of the proposed commenter stated that, for deepwater requirement for setting casing language in any useful way. operations, this language would allow immediately upon encountering oil, gas, Finally, BSEE did not propose any large outside diameter conductor hung or unexpected formation pressure before changes to the existing cementing in the supplemental wellhead adapter to the planned casing point. The language requirements for conductors. As be used as intended (i.e., as a conductor) of the proposed rule would require the described previously, the proposed without being considered a liner subject casing to be set above the encountered change to § 250.421(b) clarifies the to the liner cementing requirements. zone. While the commenter did not location where conductor casing must • Response: BSEE agrees with the object to the proposed revision, it be set if the operator encounters oil or commenter that when the casing string suggested deleting the phrase ‘‘before gas or unexpected formation pressure top is above the mudline and has been the planned casing point’’ from the before the planned casing point; i.e., cemented back to the mudline, the former and proposed regulatory text, above the encountered zone. In any casing string should not be considered and adding to the end of that provision case, BSEE does not agree with the a liner. Accordingly, to clarify this the phrase ‘‘even if it is before the suggested revision to the cementing intent, BSEE has revised the casing planned casing point.’’ requirements with regard to deepwater requirements in final § 250.421(f) to Another commenter suggested a state that ‘‘[a] subsea well casing string change to a longstanding cementing drilling. Current cementing whose top is above the mudline and that requirement in existing (and proposed) requirements, as reflected in former and has been cemented back to the mudline § 250.421(b) for verification of annular proposed § 250.421(b), already provide will not be considered a liner.’’ BSEE fill by observation of cement returns or, that if visual observation of cement also agrees with the commenter that a when observation is not possible, by returns from the annular is not possible, large outside diameter conductor hung using additional cement to ensure fill- additional cement must be added to in the supplemental wellhead adapter back to the mudline. The commenter ensure cement returns to the mudline. should not be considered a liner. No indicated that, due to the long distances To date, BSEE is unaware of any actual between the platform and the mud line problems from applying that practice change to the language of paragraph (f) at deepwater locations, excess reflected in the regulation to fixed is necessary on this point. hydrostatic cement pressure does not platforms drilling in deeper water; thus, Comments Related to Proposed allow for a full column of cement to there is no need to add the language §§ 250.421(b) and (f)—Centralizing reach the platform level, making visual suggested by the commenter. If any Casing observation problematic. The actual problems with that approach Summary of comments: One commenter suggested that BSEE address arise in the future, the operator should this concern by allowing use of lift consult the District Manager regarding commenter supported the proposed new pressure calculations or ‘‘tag and appropriate action and, if warranted, requirements in §§ 250.421(b) and (f), circulate’’ to confirm visual evidence of request approval of alternative but suggested that BSEE add more cement location, and by adding procedures or equipment under specific instruction on how to centralize language to the cementing provisions in § 250.141. casing (e.g., by specifying centralization § 250.421(b) that would require requirements according to casing type). Comments Related to Proposed The commenter stated that if casing operators to discuss the cement fill level § 250.421(f)—Casing and Liners with the District Manager when inside the well is not properly ‘‘drilling in deeper water on fixed Summary of comments: With regard centralized, it will have thinner cement, structures, where it may not be feasible to proposed § 250.421(f)—revising or possibly no cement, where the pipe to observe cement return.’’ existing casing requirements for liners is near or in contact with the earthen • Response: BSEE agrees that 20- and by prohibiting use of liners as conductor wall. The commenter noted that thin 22-inch casing may be considered casings—commenters raised concerns areas of cement are easily cracked and surface pipe and, thus, subject to about how casing would be treated in damaged. The commenter noted further § 250.421(c). BSEE also agrees that drive deepwater riserless operations. One that cement that is not well-bonded to pipe and jetted pipe can be considered commenter suggested that the the outside of the casing or earthen hole, structural pipe and, thus, subject to cementing requirements should apply to or that is damaged by subsequent well § 250.421(a). Accordingly, no change to surface wellhead systems where activities, creates a conduit for the proposed language in paragraph (b) structural casing extends back to the hydrocarbon movement, which is necessary on those points. surface facility, and stated that increases the risk of losing well control. BSEE does not agree that the proposed conductor liner is an effective option for The commenter suggested that, at a conductor casing requirement for use as casing in mud line suspension minimum, surface casing should be encounters with oil, gas or unexpected completion systems. The commenter centralized at the shoe and at every formation pressure that occur before the suggested that BSEE add the following fourth casing joint and that intermediate planned casing point should be text to § 250.421(f): and surface casing should be centralized reworded as suggested by the at the base and top and at every tenth commenter. The casing requirements A casing string whose top is above the casing joint. under former and proposed § 250.421(b) mudline and that has been cemented back to The commenter also suggested that state that if oil, gas or unexpected the mudline will be not considered a liner. additional centralizers should be used formation pressure is encountered When conductor liner systems are needed in in highly deviated well sections. This special applications, such as mud line commenter also recommended that before the planned casing point, casing suspension systems or drilling only must be set immediately; the only applications, you must receive approval from BSEE change the proposed regulation to change proposed by BSEE to paragraph the District Manager. You may not use a liner require that: (a) The surface casing be (b) was to clarify that, in such a case, the as conductor casing when surface wellhead set deep enough to provide a competent casing must be set above the systems are in use without mud line structure to support the BOP and to encountered zone. BSEE does not suspension systems and the structural casing contain any formation pressures that believe that the commenter’s suggested extends back to the surface facility. may be encountered before the next

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casing is run; (b) the entire surface What are the requirements for casing language in existing § 250.423(b), and casing annulus should be cemented to and liner installation? (§ 250.423) BSEE is unaware of any confusion the surface (presumably the mudline); This section of the existing regulation regarding the meaning of that language. and (c) the surface casing must stop was entitled ‘‘What are the requirements Accordingly, BSEE has not changed that above any significant pressure zone or for pressure testing casing?’’ BSEE sentence in the final rule. BSEE agrees with the suggestion that hydrocarbon zone to ensure the BOP proposed to change the former title of more guidance is needed in this section can be installed prior to drilling into a this section to more accurately reflect for operators to determine when casing pressure zone or into hydrocarbons. proposed changes within the section strings and liners have been • Response: BSEE agrees with the that establish requirements for installing successfully installed and cemented. comment that requiring centralization casings and liners. BSEE also proposed Therefore, we have revised proposed will increase the probability of a to revise paragraphs (a) through (c) of § 250.423(a) and (b) in this final rule to former § 250.423 to clarify that liner successful and effective cement job. include references to the cementing latching mechanisms, if applicable, However, BSEE does not agree that requirements of § 250.428(c). In effect, need to be engaged upon successfully centralization requirements should be the latching mechanisms or lock down installing and cementing the casing included in § 250.421, as suggested by mechanisms must be engaged upon string or liner. These proposed revisions the commenter. BSEE proposed, and successfully installing and cementing were intended to reinforce the § 250.420(a)(6) of the final rule requires, the liner. If the operator determines importance of properly securing liners adequate centralization (which does not under § 250.428(c) that the cement job is in place to ensure wellbore integrity. mean the use of centralizers only) to adequate (i.e., successful), then the BSEE received and considered ensure proper cementing programs. In latching/locking mechanisms should be comments on the proposed revisions addition, final § 250.420(a)(7)—formerly engaged. If there are indications of an and the language in proposed § 250.420(a)(6)—already requires that inadequate cement job, actions should paragraphs (a) and (b) has been revised operators submit certifications signed by be taken in accordance with § 250.428 to as discussed in the following responses. registered PEs that the casing and ensure proper cementation before the Proposed paragraph (c), however, is cementing design is appropriate and latching or locking mechanisms are included in the final rule without sufficient. These provisions will help engaged. ensure that casing is properly change. Comments Related to Proposed centralized. In addition, existing Comments Related to Proposed § 250.423(c)—Proper Casing or Liner § 250.415(f) requires that the cementing § 250.423(a) and (b)—Ensuring Installation and casing programs included in the Lockdown Mechanism Is Engaged APD describe how the operator uses API Summary of comments: One Standard 65—part 2 to evaluate best Summary of comments: One commenter suggested that BSEE add a practices, including best practices for commenter recommended that the new requirement to § 250.423(c) for centralizing casing. This also helps introductory sentence in proposed monitoring and verification of make-up ensure that casing is properly § 250.423—regarding casing and liner and torqueing of casing and tubular centralized. Accordingly, BSEE did not installation—be changed in order to connections. The commenter suggested propose any changes to the surface provide greater clarity for industry. the use of torque/turn evaluation Multiple commenters raised the casing provisions under former equipment when installing production concern that the language in proposed § 250.421 with respect to centralization, casing and tubing to confirm that thread § 250.423(a) and (b) does not define or and no change to the former or proposed mating has been performed according to explain how to measure success in requirements are necessary on this applicable specifications. point. ensuring that latching/locking • Response: BSEE does not agree that mechanisms are engaged after these suggested changes are necessary to Comments Related to Proposed ‘‘successfully installing and cementing’’ ensure proper installation of casing and § 250.421(f)—Liner Lap Length the casing string and liner, respectively. tubing. BSEE already requires a pressure They stated that many systems do not Summary of comments: A commenter test on the casing seal assembly under have a way to ‘‘ensure’’ that the former § 250.423(b)(3)—now did not agree with the requirement in lockdown mechanism is properly proposed § 250.421(f) to have a liner lap § 250.423(c)—and submittal to BSEE of engaged; all they can do is ensure that both the test procedures and test results, length specified for liners with liner top the proper procedures to set the packers. The commenter stated that in order to verify the integrity of the lockdown mechanism are followed. The casing and connections. Therefore, no liner lap length requirements in commenters recommended that BSEE production wells may adversely affect additional language is needed to help remove the word ‘‘successfully’’ from confirm casing integrity. the ability to complete the well §§ 250.423(a) and (b) and say instead efficiently. that, ‘‘[y]ou must ensure that the What are the requirements for prolonged • Response: BSEE agrees with the latching mechanisms or lock down drilling operations? (§ 250.424) commenter’s intent and has revised the mechanisms are engaged upon BSEE proposed to reserve and remove proposed cementing requirements for installation of each casing string.’’ this section and to move the content of liners by adding language to final • Response: BSEE does not agree that this former section to proposed § 250.421(f) stating that as provided by the suggested change to the introductory § 250.722. BSEE received no comments (d) and (e), if you have a liner lap and sentence in proposed § 250.423 is on the proposed removal and are unable to cement 500 feet above the necessary to avoid confusion. The reservation of this section, and the final previous shoe, you must submit and commenter did not explain why that rule takes that action. receive approval from the District sentence is unclear or why the Manager on a case-by-case basis. This commenter’s suggested change would What are the requirements for pressure revision provides additional flexibility make the language clearer. In fact, the testing liners? (§ 250.425) to ensure that production wells are introductory sentence in the proposed BSEE proposed to reserve and remove completed efficiently. rule was exactly the same as the this section and to move the content of

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this former section to proposed they would no longer have the paragraph (d), clarifies that if the § 250.721. BSEE received no comments capability to run additional casing cement job is inadequate, the District on the proposed removal and strings as needed to meet the applicable Manager must approve all proposed reservation of this section and the final containment requirements. All remedial actions (except immediate rule takes that action. commenters on this issue recommended action to ensure safety or to prevent a that BSEE revise the second sentence in well-control event). In addition, BSEE What are the recordkeeping § 250.427(b) to state that ‘‘[w]hen you proposed to add paragraph (k) requirements for casing and liner cannot maintain the safe margins, you (concerning the use of valves on drive pressure tests? (§ 250.426) must suspend drilling operations and pipes during cementing operations for BSEE proposed to reserve and remove remedy the situation in accordance with the conductor casing, surface casing, or this section and to move the content of accepted industry practices as liner), to require certain actions to assist this former section to proposed documented in API Bulletin 92L or as BSEE in assessing the structural § 250.746. BSEE received no comments otherwise approved by the District integrity of the well. After consideration on the proposed removal and Manager.’’ Two of the commenters also of comments on these proposed reservation of this section, and the final suggested that BSEE require the operator revisions, BSEE has included proposed rule takes that action. to assess risk in addition to receiving paragraphs (b), (c), and (d) in the final What are the requirements for pressure District Manager approval for the rule without change. However, as integrity tests? (§ 250.427) remedial activity. discussed in the following responses, • Response: As discussed elsewhere BSEE has revised the language of This section of the existing regulation in this document (see part V.B.1), based proposed paragraph (k) in the final rule. requires pressure integrity testing below on other comments BSEE has revised the surface casing or liner and at certain the safe drilling margin requirements in Comments Related to Proposed drilling intervals. BSEE proposed to final § 250.414 to provide operators § 250.428(b)—Changing Casing Setting revise former paragraph (b) of this more flexibility in determining a proper Depths or Hole Interval Drilling Depth section to clarify that operators must safe drilling margin. The revisions to Summary of comments: One maintain the safe drilling margins that section resolve most, if not all, of commenter raised concerns that the required by proposed § 250.414. the concerns raised by the commenters proposed changes to existing Although BSEE received and considered in connection with proposed § 250.427. § 250.428(b), which specifies what comments on this proposed In this final rule, BSEE is not specifying operators must do when they need to requirement, the final rule includes this how the operator must remedy the change casing setting depths or hole paragraph as proposed for the reasons situation when the safe drilling margin interval drilling depths, would be too discussed in the following responses. cannot be maintained. Accordingly, restrictive. The commenter asserted that if the requirement was limited to Comments Related to Proposed BSEE has not made the changes to changes that exceed 300 feet TVD— § 250.427(b)—Safe Drilling Margin proposed § 250.427 requested by the commenters. However, BSEE will instead of 100 feet TVD as proposed— Summary of comments: Multiple evaluate API Bulletin 92L and, if BSEE it would minimize unnecessary commenters raised the concern that determines that it is appropriate to resubmittals of proposed changes to changing the casing design for wells in require application of that standard to District Managers for approval and order to maintain the safe drilling remedial actions when safe drilling certifications of the proposed changes margins specified in proposed § 250.414 margins cannot be maintained, BSEE by PEs. could make some wells uneconomical, may propose incorporating that • Response: BSEE does not agree with due to the need for smaller completions standard in the regulations in a separate this comment. Changing the and thus, potentially uneconomical rulemaking. requirement in § 250.428(b) from 100 production rates. feet TVD to 300 feet TVD would Although BSEE only proposed a What must I do in certain cementing adversely affect the source control and minor change to existing § 250.427 (i.e., and casing situations? (§ 250.428) containment capabilities required by adding a cross-reference in paragraph This section of the existing regulation § 250.462(a) since it could affect the (b) to the new safe drilling margin describes actions that must be taken performance and integrity of the well as provisions in proposed § 250.414), these when certain situations (e.g., designed and affect the determination of same commenters also raised concerns unexpected formation pressures) are whether a full shut-in can be achieved. with the existing requirement in encountered during casing or cementing Accordingly, BSEE made no changes in § 250.427(b) that safe drilling margins operations. BSEE did not propose the final rule to the proposed language must be maintained and that drilling changes to paragraph (a) or paragraphs of paragraph (b) in response to this must be suspended and the situation (e) though (i). BSEE proposed to revise comment. remedied when the drilling margins paragraph (b) of this section to require cannot be maintained. The commenters District Manager approval for proposed Comments Related to Proposed stated that suspending drilling to set hole interval drilling depth changes § 250.428(b) and (d)—PE Certification pipe based on the proposed 0.5 ppg safe (greater than 100 feet total vertical Summary of comments: Multiple drilling margin—which they considered depth), and submittal of a certification commenters raised concerns with the a legacy drilling margin from shallow that a PE has reviewed and approved requirement in proposed § 250.428(b) shelf wells—would have severe negative the proposed changes. These proposed and (d) that a PE certify that he or she consequences for many deepwater or requirements were intended to assist has reviewed and approved proposed depleted zone wells being drilled today BSEE in verifying the actual well changes to casing setting depths as well and to be drilled in the future. In conditions. as proposed changes to the well addition, the commenters claimed that BSEE also proposed to revise former program to remedy an inadequate maintaining the proposed 0.5 ppg safe paragraph (c), to clarify the cement job. The commenters asserted drilling margin may require so many requirements for actions that must be that PE certification of proposed additional casing strings that it could taken if there is an indication of an changes to casing setting depths should hinder many deeper well designs in that inadequate cement job, and former be required only if those changes would

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affect the effectiveness of a barrier or if no change to the proposed language of apply to all wells, even if there is no the change in the casing setting depth those paragraphs is necessary in the indication of an inadequate cement job. would lead to a significant change in the final rule. When there is no indication of an cementing program (e.g., exposure of an inadequate cement job, the existing Comments Related to Proposed additional hydrocarbon zone). requirement to pressure test all casings § 250.428(c)—Indications of Inadequate In case of an inadequate cement job, and liners (formerly § 250.423, Cement Job the commenters recommended that redesignated as § 250.721 in this final BSEE require that: (1) The operator Summary of comments: Several rule) provides a reasonable indication of submit a remedial action plan that commenters recommended adding ‘‘lift a good cement job. includes immediate action and planned pressure analysis’’ to the list of actions future action; (2) the District Manager (i.e., temperature survey, cement Comments Related to Proposed approve the remedial action, unless evaluation log, or combination of both) § 250.428(d)—Immediate Action immediate actions must be taken to as an alternative method to determine Reporting ensure the safety of the crew or to the adequacy of the cement job under Summary of comments: Regarding the prevent a well-control event; (3) if the proposed § 250.428(c)(1). The ‘‘immediate action’’ reporting operator completes any unapproved commenters stated that cement lift requirement in § 250.428(d), one immediate action to ensure the safety of pressure analyses are an industry- commenter asked whether there is an the crew or to prevent a well-control recognized alternative to cement obligation for contractors to provide event, the operator must submit a evaluation logs for determining the top individual reports or to verify that such description of the action to the District of cement. reports have been submitted by the Manager when that action is complete; Another commenter stated that the operator. Regarding the remedial action and (4) any changes to the well program requirements in § 250.428(c) should be reporting, another commenter asked (implicitly including casing or cement revised so that when a casing shoe is not whether BSEE had any expectation that programs) that can impact the set in hydrocarbons, only a shoe test a drilling contractor would submit this effectiveness of the barrier will require would be required to confirm that the report. a certification by a PE that he or she cement job was successful. On the other • Response: As a general matter, reviewed and approved the proposed hand, the commenter suggested that if BSEE looks to the designated operator to changes, and the changed well programs hydrocarbons are present, a shoe test make filings on behalf of all lessees and must meet any other requirements of the would not be enough to confirm cement owners of operating rights. This issue is District Manager. job success, and a combination of other discussed in more detail in part VI.B.5 One commenter also requested that techniques (including lift pressure of this document. BSEE clarify whether the PE analysis, radioactive tracers, and/or Comments Related to Proposed certifications required by § 250.428 refer cement bond logging) should be § 250.428(k)—Valves Used on the Drive only to changes to the casing design and required to confirm job success. Pipe primary cementing plans and not to One commenter supported the proposed changes included in an APM. proposed changes to § 250.428, but Summary of comments: With regard The commenter suggested revising the recommended that the diagnostic tests to proposed § 250.428(k)—specifying PE certification language in that should also be run for all offshore wells what an operator must do when it plans paragraph to read: ‘‘certifying that the to verify adequate cement placement. to use a valve on the drive pipe during PE reviewed and approved the revised The commenter also recommended that cementing for conductor or surface casing and/or cement program.’’ the proposed requirements in casings or for liners—one commenter • Response: BSEE does not agree that § 250.428(d) for remedying inadequate suggested that the reference to use of a any of the changes to proposed cement jobs be strengthened to require valve was too limiting. The commenter § 250.428 suggested in these comments a repeat cement evaluation log to verify suggested changing the word ‘‘valve’’ to are necessary. BSEE does not agree that that the cement repair was successful. ‘‘barrier.’’ This would make the PE certifications for changes to casing • Response: BSEE does not agree that requirements in § 250.428(k) applicable setting depths should only be required the changes suggested by these to pressure caps, stabs, or other barriers when such changes would degrade comments are necessary. Lift pressure in addition to valves. barrier effectiveness. Changes to the analysis and a shoe test by themselves The commenter also pointed out that casing setting depths could also affect are not conclusive indicators of an for subsea wells, several valves are the performance and integrity of the adequate cement job, and the additional normally used, one for each port; well as designed and determinations as techniques (i.e., temperature survey or therefore, the proposed rule should not to whether a full shut-in can be cement evaluation log or a combination use the singular word ‘‘valve.’’ The achieved. In addition, PE certification of both) in § 250.428(c) may be commenter also said that it is common provides additional QA/QC and helps necessary to assist in locating the top of practice to use a secondary barrier (such ensure that the actions are appropriate the cement. as a pressure cap) to supplement a valve for the specific well. If an operator has With regard to the comment on (i.e., in case the valve leaks). Therefore, any questions about what specific strengthening the requirements for the commenter recommended that BSEE changes the PE must certify, the remedial actions in proposed revise the proposed requirement that operator may contact the appropriate § 250.428(d), there is no need to specify ‘‘[y]our description [of the plan to use District Manager. that a repeat cement evaluation is a valve] must include a schematic of the BSEE agrees, however, with the necessary if there is any indication that valve and height above the water line commenter’s request that we clarify that the repair was inadequate. In such a . . .’’ to read: ‘‘Your description must the PE certification requirements in case, § 250.428(c) would still apply, and include a schematic of the primary and proposed § 250.428(b) and (d) apply the actions required by that paragraph, secondary barriers and height above only to the changes described in those including a PE certification, must still mud-line. . . .’’ paragraphs and not to other changes be taken. • Response: BSEE agrees that included in an APM. That is the correct BSEE also does not agree with the changing ‘‘valve’’ to ‘‘valves’’ in interpretation of those provisions and suggestion that § 250.428(c) should § 250.428(k) is appropriate, and has

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revised the final rule accordingly. this former section to proposed What safe practices must the drilling However, BSEE does not agree that the § 250.736. BSEE received no comments fluid program follow? (§ 250.456) other changes suggested by the on the proposed removal and This section of the existing regulation commenters are necessary. In proposed, reservation of this section, and the final specifies safe practices (e.g., proper and now final, § 250.428(k), the rule takes that action. conditioning of drilling fluid) that must reference to valves is limited to valves be included in a drilling fluid program. used to verify visible cement returns, What are the BOP maintenance and inspection requirements? (§ 250.446) BSEE proposed no significant changes and thus it is expected that some to paragraphs (a) through (i) of the cement will escape those valves. They BSEE proposed to reserve and remove existing regulation. However, BSEE do not serve the same purpose as other this section and to move the content of proposed removing paragraph (j) of the barriers. this former section to proposed existing regulation, re-designating What are the general requirements for § 250.739. BSEE received no comments former paragraph (k) as paragraph (j), BOP systems and system components? on the proposed removal and and moving the content of former (§ 250.440) reservation of this section, and the final paragraph (j), which requires District rule takes that action. Manager approval for displacing kill- BSEE proposed to reserve and remove weight fluid, to proposed § 250.720(b). this section and to move the content of When must I pressure test the BOP This was intended to clarify that this this former section to proposed system? (§ 250.447) requirement applies to all drilling, § 250.730. BSEE received no comments workover, completion, and on the proposed removal and BSEE proposed to reserve and remove abandonment operations. BSEE received reservation of this section, and the final this section and to move the content of no substantive comments on this rule takes that action. this former section to proposed § 250.737. BSEE received no comments provision of the proposed rule, and the What are the requirements for a surface on the proposed removal and final rule takes these actions. BOP stack? (§ 250.441) reservation of this section, and the final What are the source control, BSEE proposed to reserve and remove rule takes that action. containment, and collocated equipment this section and to move the content of requirements? (§ 250.462) this former section to proposed What are the BOP pressure tests §§ 250.733 and 250.735. BSEE received requirements? (§ 250.448) This section of the existing regulation no comments on the proposed removal was entitled ‘‘What are the requirements BSEE proposed to reserve and remove for well-control drills?’’ BSEE proposed and reservation of this section and the this section and to move the content of final rule takes that action. to re-title and completely revise this this former section to proposed section, and to move the contents of What are the requirements for a subsea § 250.737. BSEE received no comments former § 250.462 to proposed §§ 250.710 BOP system? (§ 250.442) on the proposed removal and and 250.711. As proposed, § 250.462 reservation of this section, and the final BSEE proposed to reserve and remove would require the operator to this section and to move the content of rule takes that action. demonstrate the ability to control or this former section to proposed What additional BOP testing contain a blowout event at the sea floor. § 250.734. BSEE received no comments requirements must I meet? (§ 250.449) Proposed paragraph (a) would require on the proposed removal and the operator to determine its source reservation, and the final rule takes that BSEE proposed to reserve and remove control and containment capabilities; action. this section and to move the content of proposed paragraph (b) would require this former section to proposed that operators have access to, and the What associated systems and related § 250.737. BSEE received no comments ability to deploy, source control and equipment must all BOP systems on the proposed removal and containment equipment (SCCE) include? (§ 250.443) reservation of this section, and the final necessary to regain control of the well; BSEE proposed to reserve and remove rule takes that action. proposed paragraph (c) would require this section and to move the content of submittal of a description of the source this former section to proposed What are the recordkeeping control and containment capabilities §§ 250.733, 250.734, and 250.735. BSEE requirements for BOP tests? (§ 250.450) before BSEE approves an APD; proposed paragraph (d) requires reevaluation by received no comments on the proposed BSEE proposed to reserve and remove BSEE approval if certain events occur; removal and reservation, and the final this section and to move the content of rule takes that action. and proposed paragraph (e) outlines this former section to proposed maintenance, inspection, and testing What are the choke manifold § 250.746. BSEE received no comments requirements for specified containment requirements? (§ 250.444) on the proposed removal and equipment. After consideration of reservation of this section, and the final BSEE proposed to reserve and remove comments on the proposed section, and this section and to move the content of rule takes that action. as explained in the following responses, this former section to proposed What must I do in certain situations BSEE has included paragraphs (a) § 250.736. BSEE received no comments involving BOP equipment or systems? through (d) in the final rule as proposed. on the proposed removal and (§ 250.451) BSEE has, however, revised the reservation of this section, and the final language of proposed paragraph (e) in rule takes that action. BSEE proposed to reserve and remove the final rule. this section and to move the content of What are the requirements for kelly this former section to proposed Comments Related to Proposed valves, inside BOPs, and drill-string § 250.738. BSEE received no comments § 250.462—Introductory Paragraph safety valves? (§ 250.445) on the proposed removal and Summary of comments: One BSEE proposed to reserve and remove reservation of this section, and the final commenter recommended that an this section and to move the content of rule takes that action. ‘‘alternate contingency plan’’ be added

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at the end of the introductory paragraph device connections or transition Comments Related to Proposed to § 250.462 and also to the description connections from one component to § 250.462(c)—Description of Source of SCCE in § 250.462(c)(1) and (c)(3). another to the equipment listed in Control and Containment Capabilities The commenter asserted that this would § 250.462(b) as SCCE. The commenter Summary of comments: Regarding provide an equivalent seabed source asserted that for industry to proposed § 250.462(c), commenters control and containment alternative, progressively address safety, efficiency, raised questions and recommended and that the proposed rule does not timeliness, certainty in methods and wording changes. Three commenters promote the development of alternative systems to contain and capture reservoir stated that industry already submits the technologies that may be more effective fluid, BOP connections and required documents with each permit than traditional responses. containment points should be application (RP checklist) and suggested • Response: BSEE does not agree with considered as SCCE. that the Regional Containment this comment. Companies are free to • Response: BSEE does not agree with Demonstration (RCD), once approved, design any type of equipment as long as the requested addition to proposed they demonstrate it has the capability to paragraph (b). The equipment would satisfy the new requirements. respond to a loss of well-control requirement that the commenter Other commenters suggested retaining situation. Therefore, no changes are recommends adding to this provision is flexibility for containment capabilities needed to this proposed section in already addressed in the APD and the (i.e., pre-installed capping device for response to this comment. well containment screening tool. BSEE spar and TLPs, in-situ burning and will not approve an APD unless the dispersants) and suggested that BSEE Comments Related to Proposed operator ensures that it has the revise § 250.462(c)(1) to allow an § 250.462(a)—Determining Source equipment needed. BSEE does not ‘‘approved alternate contingency plan’’ Control and Containment Capabilities specify what equipment is to be used for as an alternative to a description of Summary of comments: Several a given scenario under final containment capabilities for controlling commenters suggested revising § 250.462(b); that provision requires and containing a blowout event at the proposed § 250.462(a)(2) to differentiate only that the equipment be accessible seafloor. Commenters also suggested well designs that can be fully shut-in and capable of responding to an oil that BSEE change proposed from those that can only be partially spill. § 250.462(c)(3) to allow ‘‘other approved shut-in, and to require operators to Summary of comments: Some contingency plan equipment’’ as an ‘‘verify,’’ rather than to ‘‘determine,’’ commenters requested other changes to alternative to information showing that that a full shut-in can be achieved. proposed § 250.462(b), asserting that the operator has access to and ability to Some of these same commenters also SCCE requirements should be specific to deploy all equipment required by recommended adding a new paragraph each well and that cap and flow paragraph (b). (a)(3) to require that an operator have equipment should not be required for • Response: BSEE agrees that the RCD the capability to: ‘‘flow and capture the wells that are specifically designed for may indicate source control and residual fluids to a subsea well.’’ shut-in on a full hydrocarbon column. containment capabilities, but operators Commenters also suggested that the Among other things, the commenters should not assume that pre-installed analyses required in proposed requested that BSEE clarify that SCCE containment equipment (i.e., pre- § 250.462(a)(1) and (2) be bolstered by means the capping stack, cap and flow installed capping device) will work. stating that the analyses should be system, and ‘‘(where applicable ..., This equipment is located on the rig and performed using the most current containment dome (i.e., localized, non- does not replace a capping stack, which version of the well containment pressurized, subsea fluids collection is located elsewhere and can be used in screening tool. Commenters stated that device),’’ and that cap and flow systems the event that the equipment located on the BSEE-endorsed well containment (including containment domes) are not the rig fails. Therefore, BSEE requires screening tool provides the necessary required for wells that are designed for operators to demonstrate that they are analysis; operators have used this tool shut-in on a full column of ready to respond with additional for over four years and submit it with hydrocarbons. equipment (i.e., capping stack), if all affected APDs. Commenters suggest • Response: BSEE does not agree that necessary. Moreover, subsea dispersant that this currently accepted practice the requested changes are necessary. equipment are not considered source should be acknowledged and codified. The initial screening of a well might control or containment devices, but • Response: BSEE disagrees with the indicate that it can be fully shut-in, but rather equipment that is collocated and suggestion that the rule should require the operator should always have the deployed alongside SCCE operations. use of the well containment screening equipment necessary and available if Accordingly, BSEE does not agree with tool. Although the rule does not require something happens that would change the recommended changes to proposed operators to use that tool, it is an the outcome of the situation from a full § 250.462(c). acceptable tool to use for the analyses shut-in to a cap and flow scenario. The initial screening presents a model Comments Related to Proposed required in final § 250.462(a)(1) and (2), § 250.462(d)—Notification of BSEE and is typically included as a condition outcome based on what is known at the in APDs. Similarly, the other time that the APD is submitted. BSEE Summary of comments: Some recommended changes to paragraph (a) realizes there is always the potential commenters requested a change to the are not necessary, since use of the well that, although the results of the initial requirements in proposed paragraph (d) containment screening tool would lead screening indicate that the well could be to advise BSEE of any well design to essentially the same results that the controlled through a full shut-in change and to suspend operations until commenters’ recommendations are (capping only), the well could actually the required out-of-service SCCE is intended to achieve. require cap and flow if an actual loss of repaired or replaced. The commenters well control were to occur. BSEE wants asserted that the proposed requirement Comments Related to Proposed to ensure that the operator is prepared to advise BSEE of any well design § 250.462(b)—SCCE for this situation and has all of the change will pose an undue burden on Summary of comments: One assets that may be needed available to both the operator and BSEE. They also commenter requested BSEE add subsea respond to a loss of well control. claimed that it is important to clarify

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that only well design changes which completely shut-in while maintaining suggested that the witness should be negatively impact the results of the well full integrity, then cap-and-flow well either BSEE or a BAVO, but not both. containment screening tool require design and equipment should not be One commenter stated that the notification to BSEE. They also required for the permit. The required function testing of capping suggested that a risk-based approach commenters suggested, however, that stacks should be conducted quarterly, should be adopted, that risk should be the cap-and-flow well design and and that pressure testing of all critical managed to the lowest possible level, equipment should be required for capping stack components should be and that if BSEE’s regional permit approval if the well containment conducted on a biennial basis. representatives are not satisfied that the screening tool indicates loss of wellbore Commenters also suggested changes risk justifies continuing operations, then integrity when attempting a complete to the proposed paragraph (e) to operations should be halted and the shut-in. Another comment concerning implement their comments, including permit withdrawn. Therefore, the the maintenance, testing, and inspection changing ‘‘pressure holding critical commenters suggested that BSEE revise of SCCE, as required in proposed components’’ to ‘‘pressure containing proposed § 250.462(d)(1) to set § 250.462(e), suggested that BSEE critical components, and changing the conditions on when BSEE should be should use the API terminology of proposed witnessing requirement to advised of well design change; i.e., that ‘‘pressure containing,’’ rather than the allow witnessing by BSEE ‘‘and/or an BSEE should be advised only in the independent third-party.’’ proposed ‘‘pressure holding,’’ to • event of ‘‘any changes in the well design eliminate the possibility of Response: As discussed in the or well conditions that require a revised misinterpretation. It was also suggested previous response, BSEE has agreed to permit to drill to be submitted and can that BSEE consider referring to API RP change ‘‘pressure holding critical impact the results of the well 17W in paragraph (e) to provide more components’’ to ‘‘pressure containing containment screening tool.’’ clarity regarding documentation, critical components’’ in the final rule. One commenter also recommended document retention, and reporting This change provides a better that, since proposed § 250.462(d)(2) requirements in the proposed table of description of the purpose of the equipment. BSEE has also addressed the would require the operator to contact requirements. the BSEE Regional Supervisor to • concerns the commenters expressed on Response: Operators should always the use of BAVOs elsewhere in this reevaluate source control and be ready to respond to a discharge or containment capabilities if required document, in regard to §§ 250.731 and loss of well control requiring cap and 250.732 and other BAVO-related SCCE is out of service, the operator flow response elements, even if the should be required to secure the well provisions. BSEE disagrees with the initial screening suggests that the and suspend drilling operations until suggestion that the proposed wellbore can be fully shut-in. However, the SCCE equipment is repaired or requirement that both BSEE and a BSEE agrees that the terminology replaced and returned to full active BAVO witness the pressure tests be change suggested by the commenters service. revised to require the presence of only • Response: BSEE does not agree that (replacing ‘‘pressure holding’’ with one or the other. It is important for any change to proposed paragraph (d) is ‘‘pressure containing’’) will improve BSEE and a BAVO to witness all warranted by these comments. BSEE consistency with current industry usage pressure testing, whenever it is possible will require notification if there are any and provides a better description of the for BSEE to be present. Although BSEE well design changes. However, BSEE is purpose of the equipment. Accordingly, may not be available to witness every not specifying the approach to be used BSEE included that revision in final test, BSEE expects that it will witness a for reevaluation of source control and § 250.462(e). pressure test and a function test at least containment capabilities; the well We do not agree, however, that API once per year. Therefore, BSEE has containment screening tool mentioned RP 17W should be incorporated in the determined that is necessary to require by the commenter would be acceptable final rule at this time. BSEE did not a BAVO to witness every pressure test in most circumstances. The notifications propose to incorporate that standard so that BSEE can be assured that every for the well design changes must be and, although we may consider this test is performed correctly. BSEE has submitted at the time the operator document for incorporation in the also slightly revised the language in submits a revised permit. BSEE will future, using the evaluation process final § 250.462(e)(1)(ii) to clarify that if evaluate, on a case-by-case basis, previously described, if we decide it is a BSEE representative is not available, whether there is adequate equipment appropriate to incorporate that standard, the test may be witnessed by a BAVO available if the SCCE is out of service, we will do so through a separate alone. and will then determine if the operator rulemaking. Comments Related to Proposed needs to suspend drilling operations. Comments Related to Proposed § 250.462(e)(2)(i)—Production Safety Comments Related to Proposed § 250.462(e)—Testing SCCE Systems Used for Flow and Capture § 250.462(e)—Maintaining, Testing, and Summary of comments: Commenters Operations Inspecting SCCE provided specific comments on, and Summary of comments: Several Summary of comments: BSEE recommended revisions to, proposed commenters suggested changes to the received several comments on the cap § 250.462(e), suggesting that BSEE § 250.462(e)(2)(i) requirements for and flow requirements in proposed develop alternative testing methods and production safety systems used for flow § 250.462(e). In general, the comments frequencies that will provide an and capture operations. The stated that it is not necessary to have equivalent or greater degree of commenters stated that subpart H of ‘‘cap and flow’’ capacity if a capping verification. Some comments also part 250 (§§ 250.800 through 250.808) stack is capable of achieving a complete addressed how pressure testing should includes requirements for items below shut-in of the well. The commenters be witnessed. Several commenters the wellhead (i.e., subsurface valves) also stated that if an operator’s suggested that there should only be one that do not encompass source control evaluation, using the BSEE-endorsed witness during pressure testing to avoid equipment. They recommended the well containment screening tool, duplication and the spending of following change in the proposed text of indicates that a wellbore can be unnecessary resources. Commenters paragraph (e)(2)(i): ‘‘Meet the

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requirements set forth in § 250.800 or a plugback, the operator must submit reservation, and the final rule takes that through 250.808, Subpart H, excluding an EOR within 30 days after completing action. equipment requirements that would be the work. This proposed provision was What well records am I required to installed below the wellhead or that are intended to help ensure that BSEE has submit? (§ 250.468) not applicable to the cap-and-flow current well information. BSEE received system.’’ no substantive comments on proposed BSEE proposed to reserve and remove • Response: BSEE agrees with the paragraph (b)(3), and the final rule this section and to move the content of commenter that this provision should includes that paragraph as proposed. this former section to proposed not apply to downhole safety systems §§ 250.742 and 250.743. BSEE received and has revised the final rule to exclude Comments Related to Proposed no comments on the proposed removal equipment below the wellhead. § 250.465—Timeliness and Consistency and reservation, and the final rule takes of BSEE Action on Permit Applications that action. Comments Related to Proposed Summary of comments: Although the What other well records could I be § 250.462(e)(3)—Inspection of Subsea only revision to § 250.465 that BSEE required to submit? (§ 250.469) Utility Equipment proposed was to former § 250.465(b)(3), Summary of comments: Several regarding submittal of EORs (i.e., to BSEE proposed to reserve and remove commenters suggested BSEE should incorporate the new EOR requirements this section and to move the content of define the expectations for inspection of in proposed § 250.744), one commenter this former section to proposed subsea utility equipment in raised general concerns regarding the § 250.745. BSEE received no comments § 250.462(e)(3). They asserted that timeliness and consistency of BSEE on the proposed removal and subsea utility equipment—such as action on permit applications. The reservation, and the final rule takes that debris removal kits, hydraulic power commenter stated that, although action. units, coiled tubing, hydrate control, operators strive to submit permit Subpart E—Oil and Gas Well- and dispersant injection equipment,—is applications well in advance of planned Completion Operations in common use as provided by operations, BSEE engineers are not able contractors and specific equipment is to timely process new applications. General Requirements (§ 250.500) not designated in those retainer Frequently BSEE is reviewing new This section of the existing regulation agreements. They suggested revising the permit requests just prior to a rig requires that well-completion language in proposed paragraph (e)(3) to arriving, or after a rig is already on operations be conducted in a way that more clearly define the scope of location, sometimes just before protects human and animal life, equipment that needs to be available for operations would have begun. The property, OCS natural resources, inspection, as follows: ‘‘Subsea utility commenter also asserted that final National security and the environment. equipment, requirements, you must: approval of APDs and APMs is often BSEE proposed to revise this section by Have all equipment utilized uniquely received after operations begin, adding language requiring operators to for containment operations available for resulting in updated regulatory follow the applicable requirements of inspection at all times.’’ stipulations or changes to plans which • proposed new Subpart G (in addition to Response: BSEE agrees that the can lead to non-compliance issues, Subpart E). BSEE also proposed to nature of the equipment that the confusion between parties, and could replace the word ‘‘shall’’ with ‘‘must’’ operator needs to make available to result in increased operational risks. throughout this section in order to BSEE for inspection can be better • Response: BSEE understands the clarify that the provision is mandatory. defined. Accordingly, BSEE has decided concerns raised by these comments and BSEE received no substantive comments to revise the requirement in final is making efforts to improve the on these proposed revisions to the § 250.462(e)(3) to state, ‘‘[h]ave all timeliness of its review and approval of existing regulation and has made no referenced containment equipment APDs and APMs. With regard to this changes to the proposed language in the available for inspection at all times.’’ rulemaking, however, because these final rule. BSEE also revised this section to comments are outside the scope of the include a parallel provision for proposed rule, BSEE has not made any Equipment Movement (§ 250.502) collocated equipment. If the equipment revisions concerning APM or APD BSEE proposed to reserve and remove is in use for other normal operations, submittals or approvals. Final paragraph this section and to move the content of BSEE expects that it would inspect (b)(3) requires submission of EORs this former section to proposed similar equipment provided by the same within 30 days of completing work and § 250.723. BSEE received no comments contractor (i.e., coiled tubing). does not address the submission of on the proposed removal and When must I submit an application for permit applications. reservation of this section, and the final rule takes that action. permit to modify (APM) or an end of What records must I keep? (§ 250.466) operations report to BSEE? (§ 250.465) BSEE proposed to reserve and remove Crew Instructions (§ 250.506) This section of the existing regulation this section and to move the content of BSEE proposed to reserve and remove specifies circumstances that require an this former section to proposed this section and to move the content of operator to submit an APM or EOR § 250.740. BSEE received no substantive this former section to proposed (Form BSEE–0125) and the timeframes comments on this provision, and the § 250.710. BSEE received no comments for doing so. BSEE did not propose any final rule takes that action. on the proposed removal and changes to this section of the existing reservation of this section, and the final How long must I keep records? regulation, except former paragraph rule takes that action. (b)(3). Accordingly, the remainder of (§ 250.467) former § 250.465 is retained in the final BSEE proposed to reserve and remove Well-control Fluids, Equipment, and rules without change. BSEE proposed to this section and to move the content of Operations (§ 250.514) revise former paragraph (b)(3) to clarify this former section to proposed This section of the existing regulation that, if there is a revision to the drilling § 250.741. BSEE received no comments requires that well-control fluids, plan, major drilling equipment change, on the proposed removal and equipment, and operations be designed,

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used, maintained and tested to control (b) from both sections in the final rule; about the specific packer setting depth the well under foreseeable conditions. has included paragraph (f), as proposed, in any given case, the operator may BSEE did not propose any changes to in both final sections; and has revised contact the appropriate District Manager this section except proposing to remove the proposed language in paragraph (e) for guidance. paragraph (d) of the existing regulation of §§ 250.518 and 250.619, as discussed Finally, BSEE agrees that final and move its content to proposed in the following responses and in part §§ 250.518 and 250.619 are applicable § 250.720. BSEE received no substantive V.C of this document. only to packers and bridge plugs comments on this proposed revision Comments Related to Proposed installed after the effective date of the and the final rule takes that action. §§ 250.518 and 250.619—Packers and final rule, and they do not require removal and replacement of existing What BOP information must I submit? Bridge Plugs packers and bridge plugs already in use. (§ 250.515) Summary of comments: Certain We slightly revised final § 250.518(e) to BSEE proposed to reserve and remove commenters stated that compliance with further clarify that intent; no change to this section and to move the content of API Spec. 11D1 should not be required final § 250.619(e) is necessary since that this former section to proposed for temporary packers and bridge plugs language is already clear on this point. §§ 250.731 and 250.732. BSEE received (i.e., those used for well servicing). no comments on the proposed removal Commenters stressed that API Spec. Subpart F—Oil and Gas Well-Workover and reservation of this section, and the 11D1 does not apply to temporary Operations final rule takes that action. packers and bridge plugs. General Requirements (§ 250.600) Commenters also had concerns about Blowout Prevention Equipment the proposed requirements in This section of the existing regulation (§ 250.516) §§ 250.518(e) and 250.619(e) for setting requires workover operations to be BSEE proposed to reserve and remove depth and location of the packers. For conducted in a way that protects human this section and to move the content of example, the commenters were and animal life, property, OCS natural this former section to proposed concerned that the regulations could resources, National security and the §§ 250.730, 250.733, 250.734, 250.735, require setting the packers as close as environment. BSEE proposed no and 250.736. BSEE received no possible to the perforated interval and changes to this section except proposing comments on the proposed removal and within the cemented interval of the to add a requirement for operators to reservation of this section, and the final casing section. follow the applicable provisions of new rule takes that action. One commenter asked BSEE to clarify subpart G (in addition to subpart F). whether the requirements in proposed BSEE received no substantive comments Blowout Preventer System Tests, §§ 250.518 and 250.619 would apply on this proposed revision, and the final Inspections, and Maintenance only to packers and bridge plugs rule adds the proposed language to final (§ 250.517) installed after the rule takes effect, or § 250.600. BSEE proposed to reserve and remove whether they would also apply to this section and to move the content of packers and plugs already installed Equipment Movement (§ 250.602) this former section to proposed before the rules take effect. BSEE proposed to reserve and remove §§ 250.711, 250.737, 250.738, 250.739, • Response: BSEE agrees with the this section and to move the content of and 250.746. BSEE received no commenters that the API standard itself this former section to proposed comments on the proposed removal and does not apply to temporary plugs and § 250.723. BSEE received no comments reservation of this section, and the final packers, and thus that these regulations on the proposed removal and rule takes that action. should only require compliance with reservation of this section, and the final API Spec. 11D1 for permanent packers rule takes that action. Tubing and Wellhead Equipment and bridge plugs. Accordingly, BSEE (§§ 250.518—Completion Operations has revised the text in paragraphs (e)(1) Crew Instructions (§ 250.606) and 250.619—Workover Operations) of final §§ 250.518 and 250.619 to reflect BSEE proposed to reserve and remove These sections of the existing that the requirement applies only to this section and to move the content of regulation provide requirements for permanently installed packers and this former section to proposed placement of tubing strings, periodic bridge plugs. § 250.710. BSEE received no comments evaluation of casing subject to BSEE understands the concerns about on the proposed removal and prolonged operations, and monitoring of the production packer setting reservation of this section, and the final casing pressure for completions and requirements. However, BSEE wants to rule takes that action. workovers, respectively. BSEE proposed ensure that the packer is set as required to remove former paragraph (b) from in this section in order to help ensure Well-Control Fluids, Equipment, and both sections (and to redesignate the long term equipment reliability. For Operations (§ 250.614) remaining paragraphs accordingly); and example, setting a packer in a cemented BSEE proposed to remove paragraph to add new paragraphs (e) and (f) to both interval will slow down deterioration (d) of this former section and to move sections. Those new paragraphs would that could occur in other settings and it to proposed § 250.720. BSEE received apply to packers and bridge plugs and thus will prolong the effectiveness of no substantive comments on this require adherence to newly the packer. Also, BSEE wants to ensure provision of the proposed rule and the incorporated API Spec. 11D1, Packers that the packer is not set too high, so final rule takes that action. and Bridge Plugs; clarify criteria that, if there is a problem with the production packer setting depths; and packer in the well (e.g., a leak), What BOP information must I submit? require that an APM include a operators will have enough space above (§ 250.615) description of, and calculations for the packer to pump a sufficient volume BSEE proposed to reserve and remove determining, the production packer of weighted fluid into the well to exert this section and to move the content of setting depths. After consideration of a hydrostatic force greater than the force this former section to proposed comments on the proposed revisions, created by the reservoir pressure below §§ 250.731 and 250.732. BSEE received BSEE has removed former paragraphs the packer. If there are any concerns no comments on the proposed removal

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and reservation of this section, and the provision of the proposed rule and has the requirements in the regulations. final rule makes that change. made no changes to the proposed Other commenters also raised questions language in the final rule. regarding contractor responsibilities. Coiled Tubing and Snubbing Operations • Response: BSEE and the operators (§ 250.616) May I use alternate procedures or need enough flexibility under these This section of the existing regulation equipment during operations? rules to reasonably accommodate a wide was entitled ‘‘Blowout Prevention (§ 250.701) range of potential alternative Equipment’’ and provided criteria for May I obtain departures from these compliance methods and departures. design, use, maintenance, and testing of requirements? (§ 250.702) Requests to use alternate procedures or BOPs and related well-control equipment must provide sufficient As provided for in the proposed rule, equipment. BSEE proposed to re-title justification for BSEE to make a §§ 250.701 and 250.702 add provisions § 250.616 as ‘‘Coiled tubing and determination that the proposed to new Subpart G acknowledging snubbing operations,’’ to remove alternatives provide a level of safety and operators’ ability to request BSEE paragraphs (a) through (e) of the former environmental protection that equals or approval of alternative procedures or section, and to move the content of surpasses current requirements. With equipment and to request departures those sections to final §§ 250.730 and respect to requests for departures from from operating requirements in 250.733 through 250.736. BSEE also operating requirements, BSEE does not accordance with existing §§ 250.141 and proposed to re-designate former specify the type of justification required 250.142, respectively. BSEE has paragraphs (f) through (h) as paragraphs because doing so could unnecessarily considered the comments submitted on (a) through (c) without changing the limit the submission of supporting these proposed sections, and as contents of those paragraphs. As documentation that could be pertinent explained in the following responses, proposed, redesignated paragraph (a) under the various circumstances that the final rule includes these sections sets minimum requirements for coiled might arise. Moreover, even though without change. tubing equipment and operations; existing § 250.409 and proposed redesignated paragraph (b) sets certain Comments Related to Proposed § 250.702 do not expressly require an requirements for BOP system §§ 250.701 and 250.702—Alternate operator seeking a departure to components for workover operations Procedures or Equipment and demonstrate that the operator can still with a tree in place; and redesignated Departures achieve the same level of safety and environmental protection required by paragraph (c) requires that an inside Summary of comments: Multiple BOP or certain types of safety valves be the rules, BSEE expects that any request commenters raised concerns about such for departure will include appropriate maintained on the rig floor during requests. In particular, some workovers. BSEE received no measures to ensure safety and commenters claimed that some of environmental protection. Accordingly, substantive comments on this provision BSEE’s past decisions on alternatives of the proposed rule and final § 250.616 BSEE has not made any changes to this and departure requests were not provision in the final rule. includes the proposed changes without consistent across all districts. additional revision. BSEE is aware of operator perceptions Another commenter asserted that the that some past decisions made by Blowout Preventer System Testing, proposed rule is unclear about when it different Regions or Districts on Records, and Drills (§ 250.617) would be appropriate for BSEE to allow alternative compliance or departure BSEE proposed to reserve and remove a departure from the well operations requests appeared to lack complete this section and to move the content of and equipment regulations in subpart G. consistency. However, approval of an this former section to proposed The commenter stated that the reasons alternative compliance or departure §§ 250.711, 250.737, and 250.746. BSEE for granting a departure are not request is largely dependent upon received no comments on the proposed specified in existing § 250.142 or specific site conditions and operational removal and reservation of this section, proposed § 250.702, and that the parameters that can vary significantly, and the final rule takes that action. existing and proposed regulatory even for requests that otherwise seem language for departure requests does not similar on their face. Thus, some What are my BOP inspection and specify that the operator must perceived inconsistent decisions are maintenance requirements? (§ 250.618) demonstrate that it will achieve at least explainable in light of the different case- BSEE proposed to reserve and remove the same level of safety and specific facts and circumstances. BSEE this section and to move the content of environmental protection as the strives to ensure consistency in this former section to proposed regulation from which it wants to decision-making among all Regions and § 250.739. BSEE received no comments depart. The commenter recommended Districts, and BSEE is developing on the proposed removal and that BSEE remove the proposed and internal procedures to improve reservation of this section, and the final existing regulations for departures, consistency. In any event, this rule takes that action. unless BSEE can explain its reasons for commenter’s concerns about allowing departures from the applicable consistency do not require any change Subpart G—Well Operations and drilling requirements, or why a to the regulations. Equipment departure should be allowed without Regarding the concerns raised about General Requirements requiring an adequate substitute for the contractor responsibilities, that issue is relevant requirements. The same discussed in part VI.B.5 of this What operations and equipment does commenter suggested that existing document. this subpart cover? (§ 250.700) § 250.408 and proposed § 250.701 As provided for in the proposed rule, provide an adequate option for What must I do to keep wells under this new section explains that subpart G operators to request approval to use control? (§ 250.703) applies to drilling, completion, alternative procedures in situations, As provided for in the proposed rule, workover, and decommissioning such as technical innovations, where this new section is intended to clarify activities and equipment. BSEE received there is a beneficial reason to allow such certain precautions required to ensure no substantive comments on this alternatives, that must meet or exceed well control at all times. Paragraphs (a)

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through (f) of proposed § 250.703 are including ways to better identify an which it will be exposed while in included in the final rule without influx to a well and to improve rig service.’’ Commenters asserted that change for the reasons discussed in the personnel situational knowledge. As multiple extreme conditions are following responses to comments. more information on such unlikely to occur simultaneously; thus, Proposed paragraph (f) of this section advancements becomes available, BSEE expected conditions based on would require the use of equipment that may use that information to update the engineering judgment would better is appropriately designed, tested, and regulations, as appropriate, in separate represent the real world. The rated. However, as explained in the rulemakings. As a result, no changes commenters stated that unnecessary following responses to comments on were made to the proposed rule in over-design of equipment, which could this proposed section, paragraph (f) in response to this comment. result from the proposed language, the final rule has been revised to clarify Comments Related to Proposed could decrease overall system reliability that it applies to the ‘‘maximum § 250.703—Best Available and Safest and introduce additional risk. For environmental and operational Drilling Technology example, the commenters noted that conditions’’ (rather than the proposed increased design loads for BOPs would ‘‘most extreme conditions’’) to which Summary of comments: One lead to larger material forgings, adding the equipment will be exposed. commenter discussed concerns about to overall stresses and fatigue loads the potential change in expectations for Comments Related to Proposed experienced by wellheads and casing operations that could result from the strings. § 250.703—General Well-Control absence of the phrase ‘‘best available Requirements Other commenters asserted that the and safest drilling technology,’’ which proposed language regarding ‘‘most Summary of comments: One was contained in former § 250.401(a) extreme conditions’’ is unclear, and commenter asserted that the rules but which was not in proposed recommended revising the regulation to should focus on minimizing the volume § 250.703. Instead, proposed use the term ‘‘anticipated conditions’’ of an influx to a well and should require § 250.703(a) would require the operator instead. Some commenters also better ways (such as Coriolis meters, to ‘‘use recognized engineering practices suggested that if BSEE believes extreme additional sensors, and personnel that reduce risks to the lowest level load survival is warranted for certain training) to determine and recognize practicable.’’ The commenter pieces of equipment, then BSEE should flow. This commenter described an recommended that BSEE include both require extreme load survivability, and alternative approach based on phrases in the final, promulgated justify it, as a separate provision. understanding and recognizing well version of § 250.703. • • Response: BSEE agrees that characteristics. The commenter noted Response: BSEE does not agree that confusion could be created by the term that some companies already routinely adding the phrase ‘‘best available and ‘‘most extreme conditions.’’ perform this type of work. The safest drilling technology’’ to § 250.703 Accordingly, BSEE has revised final commenter suggested the following is necessary. The BSEE Director, under § 250.703(f) by replacing ‘‘most extreme revisions to the proposed rule: (1) authority delegated by the Secretary of service conditions to which it will be Providing more emphasis on accurately the Interior, will determine when to exposed’’ with the phrase ‘‘the measuring flows to and from a well; (2) apply BAST for specific technologies. In maximum environmental and remedying the current lack of control applying BAST, the BSEE Director will operational conditions to which it may devices/instrumentation installed with determine: When the failure of be exposed.’’ The latter phrase is deep-water marine riser systems; (3) equipment would have a significant derived from former § 250.417(a), which requiring well-specific/rig-specific effect on safety, health, or the is now designated as § 250.713(a) in this training for personnel; and (4) requiring environment; the economic feasibility of final rule and which retains that phrase. realistic well control modeling of the the technology; if the incremental Thus, industry is already familiar with well systems. benefits are clearly insufficient to justify the meaning of that language. BSEE • Response: This section of the final the incremental costs of utilizing such intends that language to ensure that rule provides both specific and general technologies; and whether requiring the equipment used for operations is performance-based parameters for use of BAST is practicable on existing keeping wells under control that are designed, tested, and rated for the most operations. adverse weather and other conditions applicable to all types of wells and In this rulemaking, BSEE is not specific to the location in which it will conditions. However, the listed undertaking a BAST determination with be used and the well conditions to parameters are not exclusive of other respect to any specific technology that which it may be exposed. For example, well control measures. This section may be utilized to satisfy the equipment used in the GOM does not requires operators to ‘‘take the necessary requirements of § 250.703. Moreover, need to be designed, tested, and rated precautions,’’ not just the precautions the requirement to use recognized for Arctic conditions unless that listed in § 250.703, to control wells and engineering practices is one broadly equipment will be used in the Arctic. to ‘‘[u]se and maintain equipment and associated with processes and methods. However, equipment used in the GOM materials necessary to ensure the safety In contrast, the BSEE’s BAST authority does need to be designed, tested and and protection of personnel . . . and the focuses on technologies, rather than rated for the possibility of extreme environment.’’ BSEE did not prescribe practices. specific technological requirements, weather conditions, including including some of the equipment Comments Related to Proposed hurricanes. § 250.703(f)—Most Extreme Service recommended by the commenter, Rig Requirements because we do not want to limit the Conditions operators’ options to ensure and Summary of comments: Some What instructions must be given to improve safety. BSEE is directly commenters requested revisions to personnel engaged in well operations? involved with numerous research proposed § 250.703(f), which would (§ 250.710) projects, and aware of others, involving require the use of equipment that ‘‘has As provided for in the proposed rule, technological advancements that could been designed, tested, and rated for the this new section requires personnel improve equipment and processes, most extreme service conditions to engaged in well operations to be

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instructed in safety requirements, rig floor. The commenter noted that the Some commenters were concerned possible hazards, and general safety plan can be a complex, lengthy, about the stipulation that the same drill considerations, as required by subpart S technical document, and thus could not be repeated consecutively. of part 250, prior to engaging in recommended that a copy of the They stated that the nature of drills is operations. Also as provided for in the complete well control plan should be to reinforce learning objectives and it proposed rule, this section clarifies that available on the rig floor for reference, may be appropriate to repeat a drill the well-control plan must contain and that a shorter version of the plan until a successful outcome is achieved. instructions for personnel about the use (with the key well-control steps) should They also noted that the drills should of each well-control component of the be posted on the rig floor for quick reflect the operation being conducted; BOP system, and must include reference. certain operations continue over an procedures for shearing pipe and sealing • Response: BSEE does not agree that extended period of time, and therefore the wellbore in the event of a well the changes suggested by the commenter it may be appropriate to repeat the drill control or emergency situation before are necessary. BSEE believes it is for the ongoing operation. Also, certain MASP conditions are exceeded. These important that the completed well- drills should be repeated due to the changes will help establish better control plan be available (i.e., ‘‘posted’’) criticality of upcoming operations. proficiency for personnel using well- in the specific areas where the One commenter recommended that control equipment. personnel doing the work can review the type of drills to be run should be After consideration of the comments and use it to confirm any pertinent recommended by a well-control expert submitted on this proposed section, details of their and other personnel’s and included in the written well-control BSEE included the proposed language well-control duties. If only a summary plan. Also, this commenter stated that for this new section in the final rule of the plan were required to be posted, the operator should document lessons without change, except that final there would be some risk that the learned from drills as well as any need paragraph (a) includes minor revisions summary would omit key details of for additional or repeat training. to the proposed language in order to which rig personnel need to be aware. • Response: BSEE wants to ensure clarify the intent of this paragraph that In addition, BSEE does not believe that all personnel complete drills personnel must be instructed in hazards that it is necessary for a well-control involved with all relevant aspects of and safety requirements. expert to draft the plan, as long as it operations. However, BSEE recognizes describes the specific well-control that some drills may be more critical Comments Related to Proposed actions that rig personnel need to take, than others and should be done on a § 250.710(b)—Well and Rig Specific and provides the other essential regular basis. Therefore, based on the Training information that the personnel need to comments received, BSEE has revised Summary of comments: One know, as specified in § 250.710(b). Nor final § 250.711(a) to clarify that a commenter recommended that this is it necessary to include the additional particular drill cannot be run section should place more emphasis on information (e.g., availability of SCCE or consecutively with the same crew. This well and rig specific training for the a secondary relief rig) suggested by the change will help avoid overly narrow crew. The commenter suggested that commenter; that information would be training for certain personnel and proposed § 250.710(b)—regarding the more appropriate for an Oil Spill improve proficiency in well-control contents and use of well control plans— Response Plan, but is not relevant to the procedures by a broader set of rig comes close to that goal. However, the well-control duties of the rig personnel. personnel without unduly limiting the commenter suggested that BSEE should operator’s discretion to schedule go further, including requiring that What are the requirements for well- important drills. personnel be fully informed of the control drills? (§ 250.711) BSEE agrees that it is useful for an characteristics of the well. As provided for in the proposed rule, operator to document any lessons • Response: BSEE does not agree that this section consolidates requirements learned from completed drills and that the suggested changes to this section are for well-control drills from various the operator should take appropriate necessary. The requirements of sections of the existing regulations (i.e., steps to correct any deficiencies or other § 250.710(b) are intended to, and should §§ 250.462, 250.517, 250.617, 250.1707) problems noted from past drills. For be sufficient to, help ensure that rig and makes the requirements applicable example, if the operator notes that personnel engaged in well operations to all drilling, completion, workover, certain personnel did not perform their are informed about their specific well- and decommissioning operations duties correctly during a drill, it should control duties and capable of covered under new subpart G. After consider scheduling extra drills performing them. consideration of the comments involving those personnel and submitted on this proposed section, otherwise ensure that the personnel Comments Related to Proposed BSEE has included the proposed understand and can perform their § 250.710(b)—Well-Control Plan language in the final rule without specific duties, as described in the well- Summary of comments: Another change, except for a minor change to control plan. However, it is not commenter expressed general support paragraph (a), as explained in the necessary to add such specific, for proposed § 250.710(b), but following response to comments and in prescriptive requirements to the rule, recommended that BSEE require that a part V.C of this document. This change because § 250.711(a) already imposes a well-control expert prepare the plan. to the proposed language of paragraph responsibility on the operator to ensure This commenter also provided (a) will help establish better proficiency that drills familiarize well operations additional suggestions for what the plan for personnel using well-control personnel with their roles so that they should address, such as well-control equipment. can perform their well-control duties measures using the primary rig, source promptly and efficiently. BSEE believes control and containment equipment, Comments Related to Proposed that this performance-based and secondary relief rigs. The § 250.711—Well-Control Drills requirement, allowing operators to commenter also expressed concerns Summary of comments: Some decide the most effective ways to about the proposed requirement to post commenters asserted that the proposed structure their drills, is appropriate a copy of the well-control plan on the requirement is overly prescriptive. given that drills may vary from rig-to-rig

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according to the specific rig’s location proposed rule. The commenter noted Comments Related to Proposed and circumstances and the well terms used in this section include: § 250.712(c)—Stacking of Rigs conditions. However, if, as provided by ‘‘Barge,’’ ‘‘coiled tubing unit,’’ ‘‘drill Summary of comments: A commenter § 250.711(c), BSEE orders a drill (in ship,’’ ‘‘jackup,’’ ‘‘snubbing unit,’’ recommended that BSEE should include consultation with the operator’s onsite ‘‘semisubmersible,’’ ‘‘submersible,’’ an ‘‘escape clause’’ under proposed representative) during an inspection, ‘‘wire-line unit,’’ ‘‘rig,’’ ‘‘rig unit,’’ § 250.712(c) so that operators who have and BSEE observes any deficiencies, ‘‘MODU,’’ ‘‘platform rig,’’ and ‘‘drilling not expressly provided permission for BSEE will notify the operator of any rig.’’ The commenter stated that these stacking a MODU on their lease would deficiencies and appropriate follow-up terms do not seem to be used not be required to provide the specified actions, if necessary. If appropriate, consistently. information to BSEE. • Response: Different sections of the BSEE may also require additional drills • Response: BSEE does not believe regulations may have different during subsequent inspections. that it is necessary to change the BSEE expects the well-control plan requirements for specific types of rigs, proposed language. BSEE intends that and drills, as required by §§ 250.710 and and BSEE has used different terms to the responsibility for reporting the rig 250.711, to function together as effective specify what rigs are covered by each tools to help rig personnel understand specific section. In particular, proposed movement under this provision falls on and efficiently perform their well- and final § 250.712 expressly require the operator or lessee on the lease where control responsibilities and duties. reporting of movements by rig units, the rig is working, not the operator or Accordingly, except with regard to the including MODUs, platform rigs, lessee where the rig is being moved to revision described previously in snubbing units, wire-line units used for for stacking. Thus, if a lessee or operator § 240.711(a), no further revisions to final non-routine operations, and coiled has not given permission for another § 250.711 are needed. tubing units. As a result, no changes to operator’s MODU or platform rig to be the rig terminology are necessary in the stacked on its lease, the operator/lessee What rig unit movements must I report? final rule. If any operator is unsure as who holds the lease would not be (§ 250.712) to whether a particular section of the required to provide the information to As described in the proposed rule, rules applies to a particular unit, the BSEE, as the commenter suggested. this section includes language similar to operator may contact the District Comments Related to Proposed former § 250.403 and adds several new Manager for assistance. If future § 250.712(d)—Notification of requirements for reporting rig experience with these final rules Construction, Repairs, or Modifications movements to BSEE. Paragraphs (a) and indicates that further guidance is (b) of the final rule address rig needed on the meaning of any terms, Summary of comments: Regarding movement reporting requirements for all BSEE may issue appropriate guidance or proposed § 250.712(d)—requiring rig units moving on and off locations. amend the regulations at that time. notification of repairs or modifications Paragraph (c) requires notifications to to the drilling package for stacked BSEE if a MODU or platform rig is to be Comments Related to Proposed units—a commenter suggested that warm or cold stacked on a lease, § 250.712(a)—72-Hour Rig Movement BSEE should not assume an operator including information about where the Notification has stacked a rig on the operator’s rig is coming from, where it would be Summary of comments: Several location, but rather should want to positioned, whether it would be commenters raised concerns that the know if any stacked rig returns to manned or unmanned, and any changes requirement in proposed § 250.712(a)(2) operation and what was done to it prior in the stacking location. Paragraph (d) to notify the District Manager 72 hours to the commencement of operations. requires notification to the appropriate before the planned movement of a rig— The rig may not be resuming operations District Manager of any construction, as compared to the longstanding for the operator who held the contract repairs, or modifications associated with requirement for 24-hour advance when it was moved. Another the drilling package made to the MODU notification under former § 250.403(a)— commenter requested that BSEE define or platform rig prior to resuming will result in many inaccurate estimates the components of the ‘‘drilling operations after stacking. Paragraph (e) of rig moves, given the potential for package’’ and that, since equipment requires notification to the District plans and schedules to change. Such repairs are performed to return the Manager if a drilling rig enters OCS changes are likely to result in multiple equipment back to specification, the waters as to where the drilling rig is reporting adjustments being submitted requirement to report repairs should be coming from. Paragraph (f) clarifies that to BSEE. Another commenter stated that removed. A commenter stated that the if the anticipated date for initially the 72-hour notice requirement would requirement to notify the District moving on or off location changes by be cumbersome and expensive for Manager of ‘‘any’’ construction, repairs more than 24 hours, an updated Rig wireline and coiled tubing units. or modifications associated with the • Movement Notification Report (Form Response: BSEE agrees with drilling package is ambiguous. • BSEE–0144) must be submitted to BSEE. commenters that the proposed 72-hour Response: The information required After consideration of the comments notice requirement may result in by this section is necessary for planning received, and as explained in the additional revisions to the submitted and response purposes, including following responses to comments and in form, due to the possibility of frequent planning for possible inspections. The part V.C of this document, BSEE has adjustments to the rig movement term ‘‘drilling package’’ is a commonly made several revisions to the proposed schedule over that period. A 24-hour understood industry term and does not language in this final rule. notice requirement would provide a require further definition. BSEE intends better, more reliable indication of when that ‘‘any’’ construction, repairs, or Comments Related to Proposed a rig will actually move and will modifications should be reported. If § 250.712—Terminology minimize the need for revisions to repairs or modifications were made to Summary of comments: A commenter previous notifications. Accordingly, the the drilling package, BSEE could need noted that there were inconsistencies in final rule retains the requirement of 24 that information to plan and conduct BSEE’s use of various terms for ‘‘rig’’ in hours, which was in the pre-existing inspections and perform additional this section and throughout the regulation. reviews to ensure the repaired or

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modified equipment is used as • Response: Although there may be dynamically positioned rigs, MODUs intended. Although BSEE cannot some benefit to applying these and multi-purpose supply vessels predict in advance all potential types of requirements to other types of typically do not stay on location during repairs or modifications that may arise, platforms, BSEE does not currently have hurricane season. enough data to make that determination. BSEE expects a rule of reason, and does Another commenter stated that the not expect every trivial, de minimis, BSEE will need more data, and more requirement to collect and submit repair (e.g., replacing a loose screw) to research needs to be conducted, to environmental data to the District be reported. justify expanding the scope of this section to other vessels and rigs. Manager after an APD/APM is approved Comments Related to Proposed Similarly, BSEE does not have enough would not benefit the MODU or lift boat § 250.712(e)—Rig Entering OCS Waters information at this time to proceed with that is already on location under the Summary of comments: A commenter the commenter’s suggestion that we set approved permit and that is collecting asserted that paragraph (e) assumes the specific criteria for analyzing structural the data, and the MODU or lift boat operator has the rig under contract pipe on deepwater wells. could be at risk if it were truly when it enters OCS waters. The In addition, BSEE would need to ‘‘unsuitable’’ for the site conditions commenter suggested that the gather more information and to further where it is gathering the data. The requirement instead be keyed to when a consult with USCG before deciding commenter recommended that a rig is first utilized for well operations whether to add USCG to the metocean specialist assess the after coming from an overseas location. § 250.713(d) requirement for providing suitability of the MODU or lift boat for • Response: BSEE disagrees. BSEE documentation on operational limits. the location, applying conservative expects an operator that has a contract BSEE may consider addressing these environmental criteria. If there is on a rig coming from overseas to make issues in separate rulemakings at a later uncertainty in the metocean criteria that date. In the meantime, BSEE will the notification upon entry of the rig cannot be resolved, the environmental continue its close coordination with into U.S. waters, so that BSEE has an data should be gathered before USCG in all matters involving BSEE and opportunity to inspect or otherwise mobilizing a MODU or lift boat to the USCG responsibilities. determine that the rig is suitable, before location. the rig is first utilized on the OCS. Comments Related to Proposed • Response: BSEE agrees that the Operators should be aware if its contract § 250.713—Terminology requirement to submit information on rig is entering OCS waters and where it Summary of comments: Another the most extreme environmental is coming from. commenter asserted that the use of conditions that the unit is designed to What must I provide if I plan to use a inconsistent terminology for ‘‘rigs’’ (e.g., withstand only requires information mobile offshore drilling unit (MODU) for unit, rig unit) in this section may create regarding the minimum air gap where well operations? (§ 250.713) confusion and recommended that BSEE that is a relevant factor in the unit’s review the Part 250 regulations for how design. For example, not all MODUs As provided for in the proposed rule, the various terms referring to rigs are this section includes MODU have or require an air gap (e.g., used and then include appropriate drillships). However, BSEE does not requirements (e.g., fitness and definitions. foundation requirements) from former • Response: Different sections of the believe it is necessary to expressly add § 250.417, and makes the former regulations may have different such a limitation in § 250.713(a), since requirements applicable to all requirements for specific types of rigs, it is already clearly implied by the operations covered under subpart G. and BSEE has used different terms to language stating that the operator is only Paragraph (g) of the final rule also specify what rigs are covered by each required to submit information about codifies certain monitoring specific section. However, BSEE agrees the most extreme conditions the requirements previously discussed in with the suggestion that the uses of ‘‘MODU is designed to withstand.’’ BSEE NTL 2009–G02, Ocean Current various terms for rigs in this specific BSEE agrees that environmental data Monitoring. This final section is revised section could cause some confusion. should be gathered before mobilizing a from the proposed rule as discussed in Accordingly, BSEE made minor changes MODU to location, although no change the comment responses for this section to this section to improve consistency to the regulatory text is required to make and part V.C of this document. between rig terms (e.g., we replaced that point. The requirements in Comments Related to Proposed ‘‘unit’’ with ‘‘MODU’’ in final § 250.713(a) have been in place—in § 250.713—Platform Types and USCG § 250.713(a)). The suggestion that BSEE former § 250.417(a)—for years and BSEE review all of part 250 regarding the is not aware of any problems occurring Summary of comments: One terminology for rigs falls outside the because a unit was onsite before the commenter suggested that this section scope of this rulemaking. BSEE may should also apply to other types of data was gathered and submitted. Nor review all of part 250 for this purpose does BSEE believe that it is necessary to platforms, including multi-purpose at a later date. service vessels. Another commenter require a metocean expert to assess the recommended that BSEE coordinate Comments Related to Proposed suitability of the unit for the with United States Coast Guard (USCG) § 250.713(a)—Fitness Requirements environmental conditions under this regarding specific operating criteria Summary of comments: A commenter longstanding provision. Furthermore, used to analyze structural pipe on suggested that, under proposed the District Manager has the authority to deepwater wells and take this § 250.713(a), the requirement to provide revoke approval of the permit if data opportunity to set uniform standards information demonstrating the unit’s collected during operations shows the across the OCS. A commenter suggested capability to perform under the most MODU cannot perform at the proposed adding the USCG to the provision under extreme conditions (including the location. This will help BSEE ensure proposed § 250.713(d) regarding minimum air gap for the hurricane that the MODU proposed for OCS documentation of operational limits season) should apply only if operations is appropriate for the specific imposed by a classification society. appropriate. This commenter noted that location.

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Comments Related to Proposed provisions to § 250.713(e), which will help operators, and BSEE, to § 250.713(b)—Foundation Requirements requires contingency plans for identify impacted infrastructure in order Summary of comments: One dynamically positioned MODUs to to improve responses to a dropped commenter asserted that § 250.713(b)— move offsite in emergencies, in order to object. regarding foundation requirements for ensure that the operator has plans to Section 250.714(e) is intended to give MODUs and lift boats—should apply secure the well during planned District Managers the necessary suspensions. flexibility and discretion to require only to bottom-supported MODUs or lift • boats, where a loss of foundation is Response: Requirements for information as needed in specific cases catastrophic, and that BSEE should securing a well during any interruption, to fulfill the purposes of the regulation. exclude moored MODUs from this including suspensions, are adequately However, BSEE has further clarified requirement. Another commenter covered under final § 250.720. final § 250.714(e), by stating that a suggested adding text to this section to Therefore, no changes to § 250.713(e) District Manager may require additional state that the District Manager may are necessary in this regard. information as appropriate to clarify, update, or evaluate a dropped objects accept lower-bound and upper-bound Do I have to develop a dropped objects plan. Thus, the District Manager may soil properties, based on regional soil plan? (§ 250.714) data and developed by a knowledgeable require additional information regarding As provided for in the proposed rule, dropped objects on a case-by-case basis, geotechnical engineer, in lieu of the this new section codifies some of the requirement to submit information on based on unique site or well conditions. language from BSEE NTL 2009–G36, BSEE currently does not have enough site-specific soil conditions. Using Alternate Compliance in Safety • Response: BSEE agrees with the information about SIMOPS to warrant Systems for Subsea Production comment that paragraph (b) should including such a requirement in this Operations, and is intended to help apply only to bottom-founded MODUs. final rule. However, BSEE agrees that avoid prolonged damage to subsea Accordingly, BSEE revised § 250.713(b) SIMOPS may be a tool that operators infrastructure and to assist operators to clarify that this provision requires should consider when multiple and BSEE in responding to a dropped submittal of information showing that operations are being conducted at the object. This section also requires an site-specific soil and oceanographic same time or in conjunction with each conditions are capable of supporting the operator to develop a dropped objects other. If research or studies or other proposed bottom-founded MODUs. (In plan and specifies certain information information about SIMOPS become addition, as explained later, BSEE has and procedures that must be included in available in the future that warrant removed lift boats altogether from this the plan. This final section is revised further revision of this regulation, BSEE section of the final rule.) from the proposed rule as discussed in may propose such a revision in a future However, BSEE does not agree that the comment responses for this section rulemaking. and in part V.C of this document. regional soil data should be allowed in Do I need a global positioning system place of site-specific soil data. The Comments Related to Proposed (GPS) for all MODUs? (§ 250.715) purpose of the soil data requirement in § 250.714(c)—Modeling a Dropped As provided for in the proposed rule, § 250.713(b) is to ensure that the Object’s Path foundation at the specific site is actually this new section codifies existing BSEE Summary of comments: One comment capable of supporting a bottom-founded NTL 2013–G01, Global Positioning on proposed § 250.714(c)—requiring MODU, and regional soil data may not System (GPS) for Mobile Offshore be sufficient to demonstrate the floating rigs in areas with subsea Drilling Units (MODUs). The GPS suitability of the soil at that particular infrastructure to model a dropped requirements for MODUs include: site. object’s path—asserted that modeling Providing a reliable means to monitor the path does not significantly reduce and track the unit’s position and path in Comments Related to Proposed the risk associated with a dropped real-time if the unit moves from its § 250.713(c)—Frontier Areas object. location during a severe storm; Summary of comments: One With regard to proposed installing and protecting the GPS commenter asserted that proposed § 250.714(e)—requiring operators to equipment to minimize the risk of the § 250.713(c) (requiring information include in their dropped objects plan system being disabled; having the about units in frontier areas) and (f) ‘‘any additional information required by capability of transmitting data for at (availability of units for inspection) the District Manager’’—one commenter least 7 days after a storm has passed; should not apply to lift boats. The recommended that BSEE should limit and providing BSEE with real-time commenter stated that lift boats are requests for additional information to access to the unit’s GPS location data. classified as offshore support vessels ‘‘information needed to ensure This final section is revised from the and are regulated by the USCG. protection of onsite personnel or the proposed rule as discussed in the • Response: Commenters raised environment.’’ Another commenter comment responses for this section and several jurisdictional and technical asserted that § 250.714(e) is ambiguous in part V.C of this document. concerns regarding the applicability of and that BSEE should clarify it. Another Comments Related to Proposed this section to lift boats. For example, commenter observed that companies § 250.715—Terminology some of the information, or access to should have simultaneous operations information, required by this section (SIMOPS) procedures in place. Summary of comments: A commenter may not be available or pertinent for • Response: BSEE does not agree that raised concern about apparent some lift boats. Accordingly, BSEE there is no potential benefit to modeling inconsistencies in the use of revised the final rule by deleting all a dropped object’s path. With the terminology related to rigs in this references to lift boats in § 250.713. continuing expansion of subsea section. The commenter pointed out infrastructure, BSEE determined that it that in the proposed rule this section Comments Related to Proposed is important for operators to be aware of, referred to ‘‘MODUs and jack-ups,’’ § 250.713(e)—Contingency Plans and plan for, the potential impacts of a ‘‘jack-up and moored MODUs,’’ Summary of comments: Another dropped object. Having a dropped object ‘‘moored MODU or jack-up,’’ and ‘‘Rig/ commenter recommended adding plan helps increase such awareness and facility/platform.’’ In addition, the

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caption for this section implies that a during each hurricane season, before moving off the well. Nor is any jack-up is not a MODU. consistent with the language in NTL change needed to clarify that the • Response: BSEE agrees that the 2013–G01 that this provision is barriers must be installed and tested proposed rule’s terminology concerning codifying (see 80 FR 21519). before moving off location; in fact, rigs in this section might cause some § 250.720(a) already expressly requires confusion. BSEE made some minor Well Operations that two independent barriers must be changes to this section in the final rule When and how must I secure a well? installed ‘‘[b]efore moving off the well,’’ to improve consistency between rig (§ 250.720) and § 250.720(b) effectively requires that terms. For example, BSEE has revised As provided for in the proposed rule, the barriers be tested before removing the title of this section to ‘‘Do I need a mud from the riser in preparation for this section consolidates requirements GPS for all MODUs?’’ and in final moving off the well. from various provisions of the existing § 250.715(a), we have replaced ‘‘jack-up regulation regarding how to secure a and moored MODU’’ with ‘‘MODU.’’ What are the requirements for pressure well whenever operations are testing casing and liners? (§ 250.721) Comments Related to Proposed interrupted. Paragraph (a) requires that As provided for in the proposed rule, § 250.715—Applicability the District Manager be notified when this section incorporates and revises Summary of comments: A commenter operations are interrupted and provides certain requirements from former suggested that this provision should be examples of events that would warrant §§ 250.423 and 250.425 for pressure extended to all MODUs, including interruption of operations (e.g., any testing casing and liners. Among other dynamically positioned MODUs, rather observed flow outside the well’s casing). things, final § 250.721 increases the than just moored MODUs. All MODUs The requirement to notify the District minimum test pressure specification for moved from the path of a storm should Manager gives BSEE awareness of conductor casing (excluding subsea be tracked for emergencies. interrupted operations and an wellheads) from 200 psi, as under the • Response: BSEE agrees with the opportunity for an appropriate response. former regulations, to 250 psi; requires commenter that all MODUs should be Paragraph (a) also requires a negative operators to test each drilling liner and tracked during severe storms, as pressure test to ensure wellbore and liner-lap before further operations are required by § 250.715(e). In any event, barrier integrity before removing a continued in the well and provides the as previously stated, BSEE has revised subsea BOP stack or surface BOP stack parameters for such tests; clarifies that final § 250.715(a) by deleting the word on a mudline suspension well. the District Manager may approve or ‘‘moored.’’ In addition, to avoid any Paragraph (a)(2) clarifies that if there is require other casing test pressures as potential confusion, BSEE revised the not enough time to install the required appropriate to ensure casing integrity; title of this section to refer to ‘‘all barriers or other special circumstances requires that operators follow additional MODUs.’’ occur, the District Manager may approve pressure test procedures when they plan alternate procedures in accordance with to produce a well that is fully cased and Comments Related to Proposed § 250.141. Paragraph (b) of this section cemented or is an open-hole § 250.715(a)—GPS Monitoring and requires prior approval by the District completion; requires a PE certification Tracking Manager for displacement of kill-weight of plans to provide a proper seal if there Summary of comments: Another fluid from a wellbore and/or riser and is an unsatisfactory pressure test; and commenter recommended revising specifies the information that must be requires a negative pressure test on all proposed § 250.715(a) by removing the included in an APD or APM to seek wells that use a subsea BOP stack or phrase ‘‘if the moored MODU or jack-up such approval. This section is wells with mudline suspension systems. moves from its location during a severe unchanged from the proposed rule. This final section is revised from the storm.’’ proposed rule as discussed in the • Response: BSEE does not agree with Comments Related to Proposed § 250.720(a)—Testing and Verifying comment responses for this section and the commenter’s suggestion. The in part V.C of this document. commenter provided no explanation for Barriers this recommendation. Operators and Summary of comments: Some Comments Related to Proposed BSEE will need the GPS data, and thus commenters recommended that the § 250.721—Monitoring and Verification all MODUs must possess GPS systems barriers required by proposed Summary of comments: A general capable of providing such data to track § 250.720(a), when operations are comment on this section asserted that units during severe storm events. interrupted be tested and verified as BSEE should consider improvements to Removing the phrase suggested by the effective by an engineer before the BOP the monitoring and verification of commenter would require that the GPS is removed. One commenter also makeup/torqueing of casing/tubular systems also be able to monitor and recommended that the regulation clearly connections, under this section and track the unit when making normal rig require that barriers be installed prior to § 250.423(c). Similarly, another moves under routine conditions. removing a BOP. This commenter commenter stated that BSEE should Although any GPS system that provides asserted that it appears this was focus on ensuring integrity of the casing the tracking and monitoring data during intended, but that the regulatory string and recommended doing so by a severe storm would be able to provide language would benefit from additional linking minimum casing test pressure to such data during a normal move, BSEE clarification, including clarifying that it formation integrity pressure. does not need access to such data and applies when a BOP is removed but the • Response: BSEE does not agree that sees no need to require operators to rig has not yet moved off location. these suggested changes are necessary to have such a capability. BSEE is • Response: BSEE does not agree with ensure proper installation of casing and particularly concerned about MODUs the suggested changes. It is not tubing. BSEE already requires a pressure that lose station-keeping or part necessary to add a requirement to this test on the casing seal assembly under moorings during storms. Thus, BSEE paragraph for a PE verification of a former § 250.423(b)(3)—now slightly revised the first sentence in this barrier’s effectiveness, given that the § 250.423(c)—and submittal to BSEE of section to clarify that BSEE must have barriers must be tested, according to both the test procedures and test results, real-time access to GPS data prior to and § 250.720(b)(2), to ensure integrity in order to verify the integrity of the

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casing and connections. There is no and BSEE is not aware of industry should revise § 250.721(f)—requiring need for additional language to confirm raising any concerns with implementing pressure testing of a well before these results. that requirement. In any event, any resuming operations—to require operator that wants to seek approval of operators to run pressure tests long Comments Related to Proposed an alternative test pressure under enough to stabilize the pressure and to § 250.721(a) Through (c)—Liner Lap § 250.721(d) in a specific case may do hold a constant pressure for 30 minutes. Testing so. • Response: BSEE does not agree that Summary of comments: Multiple holding a constant pressure for 30 commenters asserted that testing of the Comments Related to Proposed minutes is necessary to demonstrate liner-lap, as specified in proposed § 250.721(e) sufficient stability to resume operations. § 250.721(a) through (c), is not possible. Summary of comments: A commenter Due to well parameters such as, but not The commenters recommended instead raised concerns about proposed limited to, thermal effects, fluid that the liner-top be tested to confirm § 250.721(e)—regarding pressure testing compressibility, fluid characteristics, integrity of the casing. for a well that is planned for and environmental conditions, holding • Response: BSEE agrees with the production—stating that the proposed a constant pressure for 30 minutes may comment that the liner lap cannot be language to ‘‘pressure test the entire not be possible. The proposed tested as proposed, since the liner-lap well to maximum anticipated shut-in requirement that—if the pressure will not actually respond to the pressure tubing pressure’’ is not clearly defined. declines more than 10 percent in 30 from such a test, while the liner-top will The commenter asserted that the text is minutes—the District Manager must respond to that pressure. Accordingly, not clear as to whether the ‘‘anticipated approve a PE-certified plan to resolve testing of the liner-top is sufficient to shut-in tubing pressure’’ is the pressure the pressure issue is sufficient to ensure demonstrate the integrity of the well, with a full column of hydrocarbons or that the well is fit to be operated. and BSEE has revised final § 250.721(b) the pressure after perforating with an Comments Related to Proposed and (c) by substituting ‘‘liner-top’’ for underbalanced fluid. The commenter § 250.721(g)—Negative Pressure Test ‘‘liner-laps’’ with regard to the testing claimed that this ambiguity would make required to confirm integrity. implementing this requirement Summary of comments: BSEE problematic when the fluid in the well received multiple comments on Comments Related to Proposed at the time of pressure testing is of a proposed § 250.721(g), which addressed § 250.721(a)—Testing of Surface, different density than the planned negative pressure testing of wells with Intermediate and Production Casing completion fluid. The commenter subsea BOP stacks or mudline Summary of comments: Another described various risks associated with suspension systems. Commenters commenter stated that under proposed this situation and suggested that BSEE asserted that the negative pressure tests § 250.721(a)(3)—regarding testing of clarify that the testing pressure must not under § 250.721(g)(1) and (3), should surface, intermediate and production ‘‘exceed 70 percent of the burst rating only be required if hydrocarbons are casing—BSEE should allow operators to limit of the weakest component.’’ present. Commenters also recommended test the casing to either 70 percent of the Another commenter stated that the that § 250.721(g) require two barriers casing’s minimum internal yield existing regulations on testing only if hydrocarbons are present. pressure (as proposed) or to MAWHP (§ 250.423) are fit-for purpose, and that • Response: BSEE disagrees with the plus 500 psi, in order to avoid putting industry’s long standing practice to test comments about testing the barriers unnecessary loads on the casing or casing to maximum values only with a only if there are hydrocarbons present. cement. technical reason for doing so is BSEE determined that ensuring barrier A commenter claimed that there is no sufficient. The commenter stated that integrity and well stability by engineering basis for the requirement in testing to maximum anticipated shut-in performing the required tests is proposed § 250.721(b) to test formation tubing pressure may do unnecessary important, even if hydrocarbons are not integrity at the liner shoe, if the liner harm to the cement integrity. present at the time, because geological will not be exposed to that amount of • Response: BSEE agrees that conditions (e.g., fluid migration) may pressure. The commenter claimed, for continually pressure testing to the exist that could subsequently result in example, that casing shoes set in salt are maximum anticipated shut-in tubing hydrocarbons entering the well if the not exposed to such pressures. pressure may put additional stresses on barriers are not effective. Thus, testing • Response: BSEE does not agree that the cement and thus potentially affect the barriers’ effectiveness under such the suggested changes are needed or cement integrity. Therefore, as conditions will help ensure that appropriate. The requirement for testing suggested by one of the commenters, hydrocarbons will not enter the well at casing to 70 percent of its minimum BSEE has revised final § 250.721(e) by a later date. internal yield pressure is a longstanding inserting the phrase ‘‘but not to exceed What are the requirements for prolonged requirement, formerly in § 250.423(a)(3), 70 percent of the burst rating limit of the operations in a well? (§ 250.722) and BSEE is not aware of any significant weakest component’’ to help ensure problems or concerns with testing to long term cement integrity. In addition, As provided for in the proposed rule, that limit. If an operator has any as provided by final § 250.721(d), if an this section consolidates and clarifies concerns with the testing procedures in operator has other concerns about various sections of the existing a specific case, however, the operator casing test pressures, it may seek regulations that established may request, and the District Manager approval from the District Manager or requirements for well integrity for may approve, other casing test pressures Regional Supervisor for alternative test operations continuing longer than 30 on a case-by-case basis under pressures on a case-by-case basis. days from a previous casing or liner test. § 250.721(d). If well integrity has deteriorated to a For the same reasons, BSEE does not Comments Related to Proposed level below minimum safety factors, this agree that the suggested changes to § 250.721(f)—Pressure Testing Before section requires repairs or installation of § 250.721(b) are warranted. That testing Resuming Operations additional casing and subsequent requirement has been in place for many Summary of comments: One pressure testing, as approved by the years (formerly in § 250.425(a) and (b)) commenter recommended that BSEE District Manager. As discussed in the

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comment responses for this section and measures for operations on a platform term might not be suitable for use in in part V.C. of this document, BSEE has that has a producing well or other every context.14 revised the language of proposed hydrocarbon flow. Among other paragraph (a) in the final rule. requirements, this section requires the Comments Related to Proposed installation of an emergency shutdown § 250.723(c)—Lift Boats Comments Related to Proposed § 250.722—Introductory Paragraph station, for the production system, near Summary of comments: A commenter the rig operator’s console. This suggested that BSEE not include lift Summary of comments: BSEE provision helps ensure that rig units boats in § 250.723(c)(3), which requires received a comment on the introductory would be able to shut-in the production shut-in of producible wells when a paragraph of § 250.722, which specifies system of the host facility. For the MODU or lift boat moves within 500 actions that must be taken if wellbore reasons discussed in the following operations continue more than 30 days comment responses, the final rule feet of the platform. The commenter after the previous pressure test. The makes no changes to the proposed rule observed that lift boats are self-powered commenter suggested that the in regard to this section. motor vessels, which are more introductory text be revised to include maneuverable than, and not comparable ‘‘or independent third-party review of Comments Related to Proposed to, a MODU that is towed on location. § 250.723—Terminology the well’s casing or liner’’ as a condition • Response: BSEE disagrees with the of timing for performing the Summary of comments: A commenter comment about removing lift boats from requirements in this section. noted that there are apparent paragraph (c)(3). Even though a lift boat • Response: BSEE did not revise this inconsistencies in BSEE’s use of terms may be more maneuverable than a section based on the comment. It is not for ‘‘rig’’ in this section. The commenter MODU, care must still be taken when clear from the comment how the noted terms used in this section any large object, such as a lift boat, independent third-party would review include: ‘‘coiled tubing unit,’’ ‘‘lift the well’s casing or liner. undertakes any movement near a well boat,’’ ‘‘drill ship,’’ ‘‘jackup,’’ ‘‘snubbing with producing hydrocarbons. The risk Comments Related to Proposed unit,’’ ‘‘wire-line unit,’’ ‘‘rig unit,’’ and of a collision or other incident that ‘‘MODU.’’ However, the commenter § 250.722(a)—Prolonged Well could trigger a well-control event cannot provided no specific suggestions for Operations be eliminated simply because the addressing this issue. Summary of comments: Other moving object may be relatively • Response: For the reasons stated in commenters raised concerns with response to similar comments on maneuverable. proposed § 250.722(a), which requires proposed § 250.712, BSEE has that operations stop as soon as What are the real-time monitoring determined that no changes to the practicable, and that the operator must: requirements? (§ 250.724) terminology in this section are Evaluate the effects of prolonged necessary. As described in the proposed rule, operations using a pressure test, caliper this new section includes requirements or imaging tool; and report the results, Comments Related to Proposed for gathering and monitoring real-time including calculations showing the § 250.723—Definition of ‘‘Platform’’ well data. The proposed section has well’s integrity is above minimal safety Summary of comments: Another factors, to the District Manager. been revised in the final rule as commenter stated that the term Commenters asserted that calculations discussed in the comment responses for ‘‘platform,’’ which is mentioned in this that show a well’s integrity is above the this section and in part V.B.4 of this section’s heading, is not defined in part minimum safety factors cannot be document. Proposed paragraph (a) has 250, and that facilities or rigs may be performed for a casing pressure test, and been revised to clarify that it requires built and operated on gravel islands or thus recommended revisions to using an independent, automatic, and installed on bottom-founded offshore § 250.722(a)(2) to clarify that the report continuous monitoring system capable structures. The commenter must include calculations showing that of recording, storing, and transmitting recommended that BSEE develop and the well’s integrity is above the data regarding the BOP control system, add a new definition of ‘‘platform,’’ minimum safety factors only if an the well’s fluid handling system on the including facilities on gravel islands or imaging tool or caliper is used. rig, and the well’s downhole conditions. bottom-founded structures, to § 250.105. • Response: BSEE agrees with the Proposed paragraph (b) has been revised • Response: This comment comment that calculations that show a to describe some of the required RTM recommends adding a new provision well’s integrity cannot be performed for operational capabilities and procedures. a casing pressure test. Accordingly, that was not in the proposed rule, and the commenter did not suggest a Proposed paragraph (c) has been revised BSEE has revised final § 250.722(a)(2) to to require that an operator develop and say that the report must include specific definition for BSEE to consider. BSEE has decided that it is not implement an RTM plan, to specify calculations that show the well’s certain information that must be integrity is above the minimum safety appropriate to include such a new definition in this final rule. Various included in the plan, and to require that factors if an imaging tool or caliper is BSEE be provided with access to the used. sections of BSEE’s current regulations have long used the term ‘‘platform’’ (or plan, and to RTM data, upon request. What additional safety measures must I similar terms), including former take when I conduct operations on a § 250.406, on which final § 250.723 is 14 14 For example, BSEE has already proposed platform that has producing wells or has partially based, and BSEE is unaware of adding a definition of ‘‘fixed platform’’ to § 250.105, other hydrocarbon flow? (§ 250.723) for use in connection with proposed amendments any significant difficulties by regulated to § 250.108. (See 80 FR 34113 (June 15, 2015).) As provided for in the proposed rule, entities in understanding that term in While that proposed definition would be this section consolidates and revises connection with that former section. appropriate for use under the specific Moreover, since that term is used in circumstances applicable to the proposed requirements from several former amendments to § 250.108 (see id. at 31446), it might sections (i.e., §§ 250.406, 250.518(b), somewhat different contexts in different not be as appropriate for defining similar terms in 250.619(b)) regarding additional safety provisions, a single definition of that other sections.

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Comments Related to Proposed • Response: Concerns about cyber • Response: For clarity and to avoid § 250.724—Claims That the RTM security, data retention, and data quality any potential confusion, BSEE deleted Requirements are Premature have been and will continue to be an the phrase ‘‘all aspects of’’ from final Summary of comments: Some issue for all regulatory programs that § 250.724(a), which now requires that comments asserted that any RTM rule require electronic transmission or the RTM system be capable of would be premature until after studies storage of data. However, much rig- ‘‘recording, storing, labeling, and and research on the application of such based data has long been, and will transmitting data regarding’’ the ‘‘BOP monitoring and analysis to offshore oil continue to be, transferred to shore control system data . . .,’’ the ‘‘well’s fluid handling system . . .,’’ and the and gas operations is complete. without regard to the proposed RTM ‘‘well’s downhole conditions . . . .’’ Specifically, some comments suggested requirements and, in many cases, that BSEE take no final action on the without being required by any Comments Related to Proposed RTM regulation until after the National regulation. Many effective measures to § 250.724(b)—Concerns About RTM and Academy of Sciences (NAS) address cyber security (e.g., access Decision-Making Transportation Research Board controls, encryption, firewalls, intrusion detection), data retention, and data Summary of comments: Many completes a study on RTM, commenters asserted that the proposed commissioned by BSEE, and releases its quality issues are available, and BSEE is confident that the offshore oil and gas RTM requirements would lead to an final report. erosion of authority of, or shifting • industry is aware of and frequently uses Response: RTM is not a novel operational decision-making away from, concept or technology, and it is such measures. Accordingly, such concerns do not justify foregoing the the rig-site personnel. In particular, currently widely used in many some commenters claimed that the industrial applications, including expected benefits of the RTM requirements of this final rule. requirement in proposed § 250.724(b)(4) offshore oil and gas development. that RTM data be ‘‘immediately Several of the industry commenters Comments Related to Proposed transmitted’’ to onshore personnel who stated that they already have RTM plans § 250.724—Concerns About Compliance must be in ‘‘continuous contact’’ with and use RTM systems in their offshore Timing rig personnel implied that BSEE operations, and acknowledged the value expected onshore personnel to be able Summary of comments: Some of such programs. In addition, based on to override rig personnel in making key comments requested that, in lieu of the regular interaction with operators, BSEE operational decisions based on the RTM proposed requirements, BSEE give is aware that many other operators data. The commenters asserted that such operators 5 years from publication of the already use RTM capabilities to monitor intervention could be detrimental to the final rule to address BOPs in RTM certain aspects of their operations. Thus, rig personnel’s performance of their BSEE does not agree that it is plans. • operational duties, as well as their sense appropriate to delay promulgation of the Response: Those comments did not of accountability, and thus could RTM requirements in this final rule include any specific explanation or actually inhibit their responses to until after the completion of the NAS support for the requested 5-year period unusual data and otherwise degrade Report, especially since compliance for incorporating BOP RTM data in such safety and environmental protection. with the RTM requirements will not be RTM plans. BSEE has reviewed the • Response: The proposed rule did required until three years after relevant comments and supporting not intend to, and the final rule does publication of the final rule, and the information, and determined that 3 not, contribute to an erosion of authority NAS report is currently scheduled to be years will provide sufficient time to of, or shifting of operational decision- completed in May 2016. (More implement the final RTM requirements making away from, the rig-site information on the NAS study is for all of the specified data, including personnel. The proposed requirement available at: http://www.bsee.gov/ data regarding the BOP control system, was intended only to ensure that RTM Technology-and-Research/Technology- as proposed. Based upon public data is transmitted onshore and that Assessment-Programs/Projects/Project- comments and prior consultation with onshore personnel who have the ability 740/.) BSEE will carefully consider the industry, BSEE believes that many to monitor the data and contact rig NAS report when it is issued, and if operators have already implemented personnel in the event that unusual data BSEE concludes that the report warrants some form of RTM for at least some rig warrants discussion with and potential any revisions to these final regulations, equipment and operations (e.g., drilling evaluation by rig personnel. (See 80 FR BSEE may propose such changes in a and fluid handling systems); thus, 21520.) BSEE intended the proposed separate rulemaking. modifying (if necessary) such existing rule to ensure that onshore personnel RTM programs to include the data could serve as ‘‘another set of eyes’’ to Comments Related to Proposed specified in § 250.724(a), including BOP monitor the data and potentially to § 250.724—Concerns About RTM data, can be reasonably accomplished assist rig personnel in performing their Transmission within 3 years. duties, but not to override the key onsite Summary of comments: Some Comments Related to Proposed decision makers or interfere with rig comments raised concerns regarding the § 250.724(a)—Scope of Data To Be personnel performing their onsite possibility that the transmittal of RTM Monitored duties. to an onshore location could provide However, to avoid any confusion in another opportunity for data system Summary of comments: Some this regard, BSEE has revised final attacks, and that this increases the need comments questioned what was meant § 250.724(b) to address the commenters’ for more cyber security. In addition, by the proposed requirement that the concerns, while staying true to BSEE’s some comments asserted that the operator’s RTM system must be capable original intent. In particular, we have proposal would increase problems with of monitoring ‘‘all aspects of’’ the BOP replaced the proposed requirement to data retention and data quality (e.g., control system, the well’s fluid handling ‘‘immediately transmit’’ the RTM data to availability of bandwidth and upload system, and the well’s downhole the onshore location with a requirement time), although no specifics were conditions with any installed bottom to transmit these data as they are provided in those comments. hole assembly tools. gathered, barring unforeseeable or

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unpreventable interruptions in Comments Related to Proposed eliminate RTM requirements from the transmission. In addition, we have § 250.724(c)—Concerns About Notifying final rule. Some of the commenters who replaced the proposed reference to BSEE suggested that BSEE require RTM plans onshore personnel ‘‘who must be in Summary of comments: Various also suggested specific issues that continuous contact with rig personnel’’ commenters raised concerns about the should be covered in such RTM plans with a new sentence requiring that practicality of the requirement in (e.g., qualifications for onshore ‘‘[o]nshore personnel who monitor real- proposed § 250.724(c) to immediately personnel; protocols for time data must have the capability to notify the District Manager if RTM communications between rig and contact rig personnel during capability is lost. Commenters pointed onshore personnel; protocols for operations.’’ out that there will be brief losses in handling interruptions in such communications and in RTM Comments Related to Proposed monitoring capability from time-to-time, capabilities; location of onshore § 250.724(b)—Concerns About RTM which are expected and unavoidable. monitoring facilities), although each Interruptions However, the operators and the District Managers could be inundated with plan could be tailored to fit the Summary of comments: A commenter notifications for very short interruptions circumstances applicable to each rig suggested that the proposed requirement operator. that are insignificant and have no • in § 250.724(b) regarding potential consequences. Response: BSEE agrees with many communications (continuous contact) • Response: BSEE did not intend the of the commenters’ suggestions between rig personnel and onshore proposed rule to require notifications regarding the potential advantages of a personnel would result in a shutdown for every loss of RTM capability, no performance-based RTM plan of operations at the rig in the event of matter how brief or insignificant the requirement. In particular, BSEE agrees any interruption, no matter how brief or interruption might be. BSEE agrees with that requiring rig-specific RTM plans inconsequential, to onshore-rig the commenters that it would be could allow operators to optimize their communications. The commenter impractical and an unnecessary burden resources to better focus on areas or asserted that such shutdowns, and for operators and the District Managers issues that need the most attention. subsequent restarting of operations, if immediate notifications were required Further, the availability of the RTM would be extremely costly and would for every minor interruption. plans to BSEE would provide extra create additional risks of malfunction Accordingly, BSEE has removed the insight into ways in which RTM can be during the shutdowns without any proposed requirement to immediately used to improve safety and corresponding benefits. Another notify the District Manager every time environmental protection. In addition, commenter also suggested that loss of RTM is interrupted from the final rule. such plans would provide operators RTM transmission to onshore should However, BSEE still expects to be with a more flexible, performance-based not result in a shutdown under informed when there is a significant or opportunity to address issues such as proposed § 250.724(c). prolonged loss of RTM capability as what to do when RTM capabilities and • Response: Nothing in the proposed outlined in the RTM plan, that communications are interrupted. Accordingly, BSEE revised the final rule suggested that an operator must potentially could increase the risk of a rule, as requested by some commenters, automatically shutdown, or that BSEE well-control event. Thus, as described to include a requirement, in final would necessarily order a shutdown of in more detail elsewhere, BSEE has § 250.724(c), that operators develop and operations due to any break, no matter added a provision to the final rule, at implement RTM plans and make the how minor, in transmittal of RTM data § 250.724(c), requiring operators to plans available to BSEE upon request. onshore or in communications between develop an RTM plan that includes a That provision requires that the RTM onshore and rig personnel. However, description of how the operator will plans include certain information, such although these concerns were not notify the District Manager when such as: supported by the proposed regulatory a loss occurs. Æ text, they are addressed by the revisions Descriptions of how RTM data will in this final rule to §§ 250.724(b) and Comments Related to Proposed be transmitted onshore, and the onshore 250.724(c). As already discussed, BSEE § 250.724(c)—Requests To Delete RTM location(s) where the data will be Requirements and/or Require RTM monitored and stored; has revised final § 250.724(b) to require Æ that operators transmit the RTM data as Plans Procedures for communications they are gathered, barring unforeseeable between onshore and rig personnel; Summary of comments: Several Æ Actions to be taken if such or unpreventable interruptions in commenters requested that BSEE delete communications or RTM capabilities are transmission, and that operators have the proposed RTM requirements from lost; the capability to monitor the data the final rule. Some of those Æ Procedures for responding to any onshore, using qualified personnel in commenters also suggested that, if BSEE significant or prolonged interruptions of accordance with an RTM plan, as did not delete RTM altogether, it should monitoring or communications; and provided in final paragraph (c). Finally, replace at least some of the prescriptive Æ A protocol for notifying BSEE of onshore personnel who monitor real- RTM requirements with a performance- any significant or prolonged time data must have the capability to based requirement for operators to interruptions. contact rig personnel during operations. develop their own RTM plans (similar These RTM plan requirements will In addition, as discussed elsewhere in to the safety and environmental complement the other RTM this document, BSEE has revised final management system—SEMS—plans requirements in § 250.724(a) and (b). § 250.724(c) and removed the language required by BSEE regulations), which that would have authorized the District would be available to BSEE upon Comments Related to Proposed Manager to require other measures request. Some other commenters, who § 250.724—Miscellaneous Concerns during a loss of RTM capabilities. These did not expressly urge BSEE to require Summary of comments: Several revisions eliminate the language that the RTM plans, nonetheless relied on the comments did not fit into the commenters perceived could have existence of their own RTM plans to summaries already discussed. These required shutdowns. justify their recommendation that BSEE miscellaneous comments include

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assertions: (a) That the RTM in part 250, OEM recommendations • Response: As explained in the requirements will not result in (unless otherwise directed by BSEE), previous response, BSEE has revised increased functionality, reliability and and recognized engineering practices. final § 250.730(a) to require that the operability of BOPs and that no RTM Paragraph (c) requires operators to use operators ‘‘ensure’’ that the equipment centers are known to reduce incidents failure reporting procedures consistent is designed, installed, maintained, etc., and increase safety; (b) that rig alarms with specified industry standards and to to ensure well control. To the extent and visual inspection are more effective report failures to BSEE. Paragraph (d) that drilling contractors actually than RTM; and (c) that the rule requires requires that if an operator uses a BOP perform those activities, the contractors the gathering of a huge amount of stack manufactured after the effective will be jointly and severally responsible information. date of this rule, that BOP stack must for compliance with this provision. • Response: Some of these have been manufactured in accordance Comments Related to Proposed with API Spec. Q1. Proposed § 250.730 miscellaneous comments express § 250.730(a)—MASP opinions (e.g., that rig alarms and visual has been revised in the final rule as inspection are better than RTM; the discussed in the comment responses for Summary of comments: Some RTM requirement will not result in this section and in part V.C of this commenters recommended that BSEE increased functionality, reliability and document. change the reference to ‘‘MASP’’ in proposed § 250.730(a) (i.e., that the operability of BOPs), with no supporting Comments Related to Proposed facts or explanations and some are working pressure rating of each BOP § 250.730(a)—BOP Design, Installation, component exceed the applicable largely irrelevant (i.e., this rulemaking and Maintenance does not require operators to establish MASP) to ‘‘maximum anticipated RTM centers). For the reasons stated in Summary of comments: In response to wellhead pressure’’ (‘‘MAWHP’’). They the proposed rule and elsewhere in this the language in proposed § 250.730(a) asserted that there is no industry agreed- document, BSEE expects the use of RTM that operators ‘‘must design, install, upon definition of ‘‘MASP,’’ but that maintain, inspect and use’’ BOP system MAWHP is defined in API Standard 53. to improve safety and environmental • protection significantly and that such components, several commenters Response: BSEE does not agree that improvements will be seen over time. pointed out that operators do not the recommended change is necessary. BSEE understands that the RTM design, install, or maintain BOP As a practical matter, for surface BOPs, provisions of this final rule will result systems. Typically, drilling contractors the MASP is the same as the MAWHP; in more information being gathered, and select and obtain the equipment from and for subsea BOPs, the MASP, when BSEE took that into account in assessing OEMs and have the BOP stack built to taken at the mudline as required by the potential costs and benefits of this order in accordance with API Standard § 250.730(a), is also the same as the rule under E.O. 12866 and the 53. These commenters recommended MAWHP. BSEE does not agree that use Paperwork Reduction Act, as discussed revising this section to replace ‘‘design’’ of ‘‘MASP’’ will cause any confusion. in part VIII and in the final RIA. For all with ‘‘ensure’’ or ‘‘select.’’ BSEE’s existing regulations (e.g., former • Response: Although the of the reasons stated in this document § 250.448(b)), have long used the term requirements in § 250.730(a) have long and in the final RIA, BSEE has ‘‘MASP,’’ and BSEE does not believe been in place under existing regulations determined that the benefits of the final that the industry will have any (former § 250.440), BSEE agrees with the RTM requirements, including the value difficulty in understanding the meaning comment that operators do not usually of the RTM information to be collected, and use of that term in this rule. design, install, or maintain the BOP are appropriate in relation to the systems. Therefore, BSEE has revised Comments Related to Proposed potential costs, including the burdens final § 250.730(a), as suggested by § 250.730(a)—Annular BOPs associated with collecting RTM commenters, to state that lessees/ Summary of comments: Several information. operators must ensure that the BOP commenters also stressed that annular Blowout Preventer (BOP) System system and system components are BOPs capable of meeting the specified Requirements designed, installed, maintained, pressure rating for ‘‘each BOP inspected, tested, and used properly to component’’ under proposed What are the general requirements for ensure well control. This change § 250.730(a) are not currently available BOP systems and system components? addresses the commenters’ concern, and are not considered technologically (§ 250.730) while clarifying that the lessee or feasible in the near term. They As provided for in the proposed rule, operator retains overall responsibility suggested that BSEE clarify that this this section consolidates and revises for ensuring the BOP system’s proper, proposed requirement applies only to requirements from several sections of design, installation, maintenance, lower stack components (including and the existing regulations for design, inspection, testing and use. below the uppermost ram) and that fabrication, installation, maintenance, components above the uppermost ram inspection, repair, testing and use of Comments Related to Proposed (e.g., annular and LMRP or riser BOP systems and BOP components. § 250.730(a)—BOP Design connect) should be excluded. Another Among other things, paragraph (a) of Responsibility commenter suggested excluding annular final § 250.730 requires compliance Summary of Comments: Some BOPs that comply with § 250.738(g), with relevant provisions of API comments asserted that the which sets procedural requirements for Standard 53 and several related industry requirements in proposed § 250.730(a) annular BOPs with rated working standards and adds a performance-based would implicitly impose QA/QC and pressures (RWPs) lower than anticipated requirement that the BOP system be able oversight responsibilities for BOP surface pressure. to meet anticipated well conditions and equipment on lessees/operators that are • Response: BSEE agrees that still be able to seal the well. Paragraph infeasible, given that the design, annulars may not be able to meet the (b) requires that operators ensure that manufacturing and testing of such MASP requirements. BSEE is aware that design, fabrication, maintenance, and equipment are completed before the the current design for annulars does not repair of the BOP system is done contracts between the lessees/operators match the pressure rating for large ram pursuant to the requirements contained and drilling contractors are in place. preventers greater than 10,000 psi.

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Annulars are typically used with BSEE is also aware that testing an Comments Related to Proposed wellbore pressures less than MASP. An individual ram component under all § 250.730(a)(2)—Normative References annular does not have any locking possible well conditions is not feasible Summary of comments: In general, mechanisms to keep it closed, as do with current testing mechanisms. some industry commenters did not pipe rams and blind shear rams, and it Accordingly, BSEE has revised final support the incorporation by reference will relax and not seal if the hydraulic § 250.730(a) to clarify that the BOP of the additional standards associated pressure is lost. Thus, a single annular system, not each ram, must be capable with API Standard 53, as listed in is not commonly used for well-control of closing and sealing the wellbore at all proposed § 250.730(a)(2), since those purposes; rather, annulars are times under ‘‘. . . anticipated flowing listed standards are merely normative commonly used in conjunction with conditions for the specific well references in API Standard 53. These other MASP-rated components, such as conditions . . . .’’ If an operator has associated documents are pipe rams or blind shear rams, that can manufacturing specifications, and since seal the well under MASP. Therefore, any questions about the anticipated they are already referenced in API excluding annulars from the MASP flowing conditions in any specific case, Standard 53, the commenters stated that pressure rating requirement will not it may request assistance from the it is redundant to also reference them in decrease safety. Accordingly, we have District Manager. the regulations. Several major industry revised final § 250.730(a) to exclude Comments Related to Proposed commenters requested that, if BSEE annulars from the requirement that § 250.730(a)—Concerns About working pressure rating exceed MASP. does reference these documents in the Compliance Date regulations, then it should clarify that Comments Related to Proposed only the relevant provisions of those § 250.730(a)—Flowing Conditions Summary of comments: Commenters documents are required to be complied also raised concerns that Summary of comments: Various with. implementation of proposed § 250.730 • commenters raised issues regarding the Response: BSEE recognizes that the would be required within 90 days of requirement in proposed § 250.730(a) industry standards listed in publication of the final rule. They that each ram (except casing shears/ § 250.730(a)(2) are normative references supershears) must be capable of closing asserted that BOPs available today are within API Standard 53. BSEE is and sealing the wellbore at all times, not designed to close and seal under the including the standards in the including under flowing conditions. worst-case flowing conditions that the regulations, however, because they Some commenters viewed the proposed commenters assumed the rule would provide certain relevant specifications language as requiring each ram to be require. Similarly, various commenters for BOP system components, and are assessed against an absolute worst-case stated that BSEE has not defined testing important to compliance with API event (i.e., any conceivable flowing parameters and protocols necessary to Standard 53 itself. As requested by conditions), and that it is not realistic to meet such scenarios. Thus, multiple industry commenters, however, BSEE expect a drilling BOP ram to close and commenters requested that BSEE has revised final § 250.730(a)(2) to seal on a high flow-rate well stream. significantly extend the proposed 90- clarify that the BOP system must meet Some comments asserted that the ability day implementation period in order to those provisions of the listed industry to test to such extreme worst-case provide time for manufacturers to standards that apply to BOP systems. conditions does not exist. Various develop new BOPs and for drillers to Comments Related to Proposed comments asserted that the actual goal purchase and install such new designs. § 250.730(a)(2)—Standards—Current of the regulation should be for the BOP • Editions system as a whole (including both Response: In light of the revisions annulars and rams) to reliably shut-in to final § 250.730(a) previously Summary of comments: Other the well under ‘‘reasonably anticipated’’ described (i.e, the deletion of the commenters stated that the additional or ‘‘anticipated’’ flowing conditions. requirement for each ram to close and standards listed in proposed Multiple commenters emphasized that seal, and the insertion of ‘‘anticipated’’ § 250.730(a)(2) are outdated equipment the industry has demonstrated the before ‘‘flowing conditions’’), BSEE is manufacturing standards, and that capability to successfully seal the not changing the compliance date for incorporating a specific outdated wellbore under a variety of anticipated requiring that BOP systems have the edition renders equipment flowing conditions (with flow checks capability to close and seal the well. manufactured prior to the standard, or using an annular BOP). Some BSEE is aware, and several industry manufactured to earlier versions of the commenters, however, claimed there are commenters have stated, that industry standard, obsolete. They asserted that currently no criteria for determining has already demonstrated that incorporating only API Standard 53, anticipated flowing conditions; while reasonably available existing BOP which includes updated normative other comments suggested that systems are capable of successfully references, and deleting the outdated anticipated flowing conditions should closing and sealing the wellbore under standards listed in paragraph (a)(2), be defined by the OEM. a variety of flowing conditions under would resolve this issue. Alternatively, Multiple commenters, therefore, the existing BOP regulations (former some commenters suggested that the asked BSEE to clarify the conditions § 250.440). Given the changes to the regulation should allow equipment to be used if it complies with the editions of that the equipment must be designed to final rule language, and industry meet, while other commenters API Standard 53 and the associated commenters’ acknowledgment of their specifically asked BSEE to require that standards that were in effect at the time ability to comply with the similar the anticipated flowing conditions be the equipment was manufactured. defined in the APD for the specific requirements under the existing A commenter also noted that there are operation and well conditions. regulations, BSEE does not anticipate significant misalignments between API • Response: BSEE recognizes that a that industry will need to make any Standard 53 and the current versions of single ram may not be capable of closing significant changes to its current or most of these associated standards (e.g., and sealing the wellbore at all times planned BOP systems to comply with accumulator capacity requirements), under all possible flowing conditions. the final rule. which would make it impossible to

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comply with API Standard 53 and these requirement is not adopted, some wells. Thus, any changes to the associated standards. The commenter commenters suggested that BSEE revise drawings and equipment would be also noted that API Standard 53 and the rule to allow alternative control included in the APD for the next well. these associated standards are currently measures based on risk assessments. Those commenters recommended being revised, and that the API • Response: BSEE agrees with the deleting that portion of § 250.730(a)(4) committees working on the new comments about pipe rams and VBRs that would require such suspensions. editions are aware of these not being able to close and seal around • Response: BSEE disagrees with the misalignment issues. tubing with exterior control lines and comment’s suggestion that changes • Response: Whenever BSEE flat packs. An annular is the only BOP would always be made between wells. incorporates a standard by reference in component currently able to seal around BSEE understands that this is usually the regulations, it must incorporate a tubing with exterior control lines and is the case; however, there are specific edition of the standard (see 1 only used for a low pressure situation, circumstances where repairs and CFR part 51), and compliance is then which is usually the case when running modifications to the BOP or control required with the incorporated tubing with exterior control lines. system are made at other times and not standard. BSEE proposed to incorporate Accordingly, BSEE has revised final necessarily between wells. Thus, there the most recent (Fourth) edition of API § 250.730(a)(3) to clarify that pipe rams is no reason to revise this provision. Standard 53, which refers to the other and VBRs are not required to be able to standards but which—in contrast to close and seal around tubing with Comments Related to Proposed Federal regulations—does not specify exterior control lines and flat packs. In § 250.730(a)(4)—Schematic Drawings the edition of those other standards to addition, BSEE has determined that this Summary of comments: A commenter which it refers. Some of the associated exclusion will not have significant recommended that BSEE clarify standards incorporated by reference in safety or environmental consequences § 250.730(a)(4) to specify that the § 250.730(a)(2) are the current versions since §§ 250.733(a) and 250.734(a)(1)(ii) schematic drawings required for the (e.g., API Spec. 16A and API Spec. 16D); will require that the shear rams be able BOP and its control system be the same other standards have been updated and to cut and seal tubing with exterior drawings listed in § 250.731(b)(1) new editions adopted by industry since control lines in the hole. through (10). BSEE developed and issued the • Response: No changes to the Comments Related to Proposed proposed rule. BSEE understands the proposed paragraph (a)(4) are necessary. § 250.730(a)(3)—Claimed Conflicts With industry is also working to update some Under final § 250.730(a)(4), schematic API Standard 53 of the current standards. BSEE will drawings may include other schematics evaluate any new editions of the Summary of comments: Commenters (such as those required under standards as they are finalized by requested clarification regarding the § 250.737(d)(12)) that are not listed in industry. If BSEE determines that any requirement in proposed § 250.730(a)(3) § 250.731(b)(1) through (10). such revised standards are appropriate that the pipe rams and VBRs be able to for incorporation in this regulation, close and seal the tubing using the Comments Related to Proposed BSEE may do so in a separate ‘‘proposed regulator settings’’ of the § 250.730(b)—Lowest Level Practicable rulemaking. In addition, as previously BOP system. The commenters claimed Summary of comments: A commenter discussed, an operator that wishes to that this language potentially conflicts recommended that BSEE revise the first use equipment manufactured to a more with API Standard 53. The commenters sentence in proposed § 250.730(b) to recent edition of the incorporated also suggested that the reference to require that the design, fabrication, standard, may ask for approval to do so ‘‘regulator settings’’ should be removed maintenance, and repair of BOP systems in accordance with § 250.198(c) and from this provision because such reduce risks to the lowest level § 250.141 or § 250.142. settings are part of the BOP control practicable instead of ‘‘according to the system described in § 250.730(a). requirements of this subpart, OEM Comments Related to Proposed • Response: This regulation does not recommendations, . . . and recognized § 250.730(a)(3)—Pipe and Variable Bore prescribe any specific requirements for engineering practices’’ as proposed by Rams (VBRs) regulator settings. BSEE requires only BSEE. Summary of comments: Commenters that the regulator settings function as • Response: The requested changes raised concerns that the proposed designed or as specified in the APD are not necessary. BSEE expects these requirement in § 250.730(a)(3) (i.e., that submitted to and approved by BSEE. types of activities to utilize recognized pipe rams and VBRs be able to close and Therefore, BSEE does not believe that engineering practices that reduce risks seal any drill pipe, workstring and this provision will cause any conflict or to the lowest level practicable, as tubing) is not achievable for tubing with confusion for operators, including with already required by existing control lines, electric cable, and flat respect to API Standard 53, and thus no § 250.107(a)(3). packs. Commenters asserted that the change or further clarification is Comments Related to Proposed interstices between the tubular and necessary. these ancillary lines become leak paths § 250.730(b)—BOP Design and when the pipe or VBRs are closed Comments Related to Proposed Fabrication around the tubing arrangement. In § 250.730(a)(4)—Approval of BOP Summary of comments: Other addition, some commenters stated that Changes comments stated that operators do not the proposed requirement would be Summary of comments: With regard design and fabricate the BOP systems; redundant with existing dual barrier to proposed § 250.730(a)(4), requiring they select the equipment based upon systems (including annulars), and thus that operations be suspended pending their specifications and capabilities. would provide negligible additional BSEE approval of any changes to the Accordingly, commenters suggested that improvements to safe operations. BOP or control systems that would alter BSEE should revise the text, replacing Commenters recommended that tubing previously approved schematic ‘‘design, fabricate, maintain, and repair’’ with such exterior lines be excluded drawings—some commenters observed with ‘‘select, maintain, and repair.’’ from the proposed requirement. If the that any changes to the BOP stack or • Response: BSEE agrees with the requested exclusion from the proposed control system would be made between comments that operators do not usually

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design and fabricate the BOP systems. standards, published peer-reviewed requirements apply to BOP-related Therefore, BSEE revised this paragraph technical reports or industry RPs, and training, and those requirements should in the final rule to state that an operator similar documents applicable to be sufficient without BSEE creating yet must ensure that the design, fabrication, engineering, design, fabrication, another training program. maintenance, and repair of its BOP installation, operation, inspection, Comments Related to Proposed system is in accordance with the repair, and maintenance activities. § 250.730(b)—Meaning of OEM requirements contained in the part. This Comments Related to Proposed change will help clarify that the lessee Summary of comments: Some § 250.730(b)—Training of Personnel or operator is responsible for ensuring comments questioned the meaning of the BOP system’s proper, design, Summary of comments: Commenters OEM in this provision. They asked if the installation, maintenance, inspection, recommended that BSEE remove the OEM is the BOP component testing and use even if it does not design proposed requirements for training of manufacturer or the suppliers of parts and fabricate the BOP system. repair and maintenance personnel. used by the component manufacturer. Some commenters observed that OEMs Commenters suggested that, if the Comments Related to Proposed do not publish training, qualification, proposed rule implies that service and § 250.730(b)—BOP Repair and and maintenance recommendations. maintenance personnel must receive Maintenance Others stated that OEM maintenance training from subcontractors of the Summary of comments: A commenter recommendations are one ‘size fits all’, OEM, it would not be a workable rule. suggested that repair and maintenance since OEMs do not have a clear One commenter suggested that there should be carried out in accordance understanding of how the equipment would be a severe impact on the with OEM specifications and will be used, maintained or preserved. availability of personnel permitted to maintenance manuals and the Commenters emphasized that the carry out maintenance, depending on equipment owner’s planned equipment owners are responsible for the definition of OEM. maintenance procedures. Additionally, the condition of the equipment and that • Response: BSEE does not agree that a commenter advised that the OEM’s they should be responsible for defining any definition of OEM is necessary at recommendations for repair and the skills and training for their this time. BSEE expects that where maintenance should include the maintenance personnel. They also noted operators have relevant quantity and quality of parts that the that operators are already required to recommendations from manufacturers owner or operator subsequently uses. address training as part of their SEMS of individual parts of the BOP system, • Response: The suggested changes program under BSEE’s SEMS as well as recommendations from the are unnecessary. As previously regulations (see § 250.1915), and that BOP component manufacturer, they are discussed, the lessee or operator is the equipment owners (e.g., rig able to implement both sets of responsible for ensuring that the BOP contractors) are also establishing recommendations. Conversely, this system is designed, repaired and training standards for their personnel. regulation does not require operators to maintained in accordance with the One commenter recommended that follow the recommendations of OEMs, requirements of this final rule, which BSEE should implement an accredited/ whether manufacturers of BOP includes ensuring that the BOP licensed training program, to be components or individual pieces of equipment is suitable for the conditions developed by the industry, instead of equipment, if no such recommendations under which it will be used (see, e.g., relying solely on OEMs and recognized exist. In the event an operator has any § 250.731), as well as with any OEM engineering practices. questions as to the applicability of any recommendations, which would include • Response: None of the suggested specific OEM recommendation, it may OEM specifications and maintenance. changes are necessary. BSEE agrees that ask the District Manager for assistance. As to the second comment, BSEE the SEMS training requirements are pertinent to personnel maintaining, Comments Related to § 250.730(c)—BOP expects the equipment to operate as Failure Reporting Procedures designed and to be used under the inspecting or repairing BOPs, and BSEE conditions for which it was designed. added an express reference to those Summary of comments: A commenter However, the commenter’s suggestion requirements in final § 250.739(d), as recommended that BSEE add near-miss that OEMs should include the quantity discussed elsewhere in this document. reporting to failure reporting and quality of parts subsequently used However, BSEE does not see any requirements. Commenters also by the operator in the OEMs’ inconsistency between the requirements suggested that BSEE define ‘‘failure’’ recommendations for repair and in § 250.730(b), for training based on and specify the types of failure covered OEM recommendations and recognized by this provision. maintenance is beyond the scope of this • rulemaking, which addresses engineering practices, and BOP-related Response: The comment regarding requirements that must be met by training as part of the SEMS program near-miss reporting is outside the scope operators. and under § 250.739(d). There is no of this rulemaking and the suggested reason why operators’ SEMS training changes are not necessary or appropriate Comments Related to Proposed programs should not incorporate OEM at this time.15 § 250.730(b)—Recognized Engineering recommendations and other recognized BSEE agrees, however, with the Practices practices. suggestion that a definition of ‘‘failure’’ Summary of comments: Commenters In addition, BSEE does not agree that would clarify the scope and recommended that the phrase it should require a new training applicability of this provision. Since ‘‘recognized engineering practices’’ be program, whether developed by there are no definitions of ‘‘failure’’ in removed since the phrase is vague and industry, as suggested by the any of the industry standards (i.e., API undefined. commenter, or not. Contrary to the Spec. 6A, API Spec. 16A, or API • Response: The recommended commenter’s assumption, BSEE is not deletion is neither necessary nor relying solely on OEM 15 BSEE notes, however, that the U.S. Bureau of Transportation Statistics has developed (with appropriate. Recognized engineering recommendations and recognized BSEE’s assistance) a voluntary near-miss reporting practices are commonly understood to engineering practices. As explained system for OCS facilities and operations. More be found in established codes, industry previously, the SEMS training information is available at www.SafeOCS.gov.

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Standard 53) referenced in this information are gained under this rule, ‘‘ensure’’ that a failure report is provision, BSEE added a general BSEE will both provide guidance and provided to the manufacturer. definition of ‘‘failure’’ in final clarification on this rule as necessary, • Response: BSEE does not agree that § 250.730(c)(1). and consider any new information it these suggested changes are necessary. learns in considering whether any In paragraph (c), BSEE is requiring the Comments Related to Proposed adjustments to the rule may be operator to provide the notifications and § 250.730(c)—Failure Reporting Under warranted. handle the interactions with the API Standard 53 manufacturer because operators are Summary of comments: A commenter Comments Related to Proposed responsible for all activities under a asserted that since API Standard 53 § 250.730(c)—Failure Database lease. covers failure reporting by the owner of Summary of comments: Some the equipment, regulations on this point commenters advised BSEE that a group Comments Related to Proposed § 250.730(c)—Failure Investigation and are not necessary. Since it is covered in of drilling contractors have developed a Analysis API Standard 53, the commenter database for reporting BOP failures. presumed that a prudent drilling These failures are automatically copied Summary of comments: A commenter contractor would conduct such follow- to the OEM by the database. According noted that not every failure warrants a up. to the commenters, this group plans to full investigation and suggested • Response: BSEE understands that implement the failure reporting replacing ‘‘investigation and a failure failure reporting requirements are found database industrywide. Within a year or analysis’’ in the proposed rule with throughout various voluntary industry so, according to the commenter, this ‘‘investigation and, when required, a standards, several of which are group may have sufficient data to failure analysis.’’ According to the incorporated in this provision. As with identify problem areas, to collectively commenter, major failures should be any voluntary standard incorporated focus on these areas until design and discussed with the OEM and an into BSEE’s rules, that incorporation has procedure changes are implemented investigation initiated; however, the the intended benefit of making that will make well-control equipment system would be unsustainable if every compliance with the standard a even more reliable. (including a minor) failure required regulatory requirement, which promotes • Response: The commenters investigation by the OEM, a third-party consistency across the regulated recommended no specific changes to the or a combination of both. community. BSEE is also including rule or other action by BSEE. In any • Response: BSEE disagrees with the additional failure reporting case, it would not be appropriate for assertion that the failure reporting requirements in this rule. Such BSEE to take any action now based on system would break down if every reporting can lead to improved and a program that may or may not exist in minor failure required investigation. It more reliable equipment. the future. However, BSEE encourages is possible that even a so-called ‘‘minor’’ failure could indicate a potentially more Comments Related to Proposed continued proactive evaluation by serious problem that warrants § 250.730(c)—Manufacturing Standards industry of potential failure mechanisms to enhance safety and correction, which would otherwise Summary of comments: Some environmental protection offshore. escape attention, if not for the commenters suggested that BSEE only investigation of the ‘‘minor’’ failure. needs to reference API Standard 53 in Comments Related to Proposed Since it is not possible to know in this section, and that BSEE should § 250.730(c)—Written Failure Report advance which seemingly minor failures remove the references to API Spec. 6A Summary of comments: With regard may lead to a ‘‘major’’ problem, BSEE and Spec. 16A. API Standard 53 is an to proposed § 250.730(c)(1), a does not believe that it is appropriate to operational document, while API Spec. commenter suggested replacing the limit the requirement as suggested. 6A and API Spec. 16A are requirement for a ‘‘written report’’ of Comments Related to Proposed manufacturing-related failure reporting equipment failure to the manufacturer § 250.730(c)—Timing of Failure methods. Alternatively, BSEE needs to with ‘‘written notification.’’ provide guidelines on the intended use • Response: BSEE agrees that such a Analysis for referencing Spec. 6A and Spec. 16A. change is appropriate. This requirement Summary of comments: A commenter • Response: No changes to this is only the first step in the failure also suggested that a 60-day window to proposed paragraph related to this reporting process, and a notice at this complete and submit failure analysis comment are necessary. BSEE step is sufficient. A more detailed findings is not realistic. It often takes 6 incorporated the failure reporting analysis report of the failure will be months or more for these findings to be requirements from all three of the provided to the manufacturer, as well as obtained and approved. Reporting of the industry standards in the proposed to BSEE, under final § 250.730(c)(2). analysis results within 60 days will provision because each standard Accordingly, BSEE has revised final potentially lead to narrowing the scope contains useful reporting procedures § 250.730(c)(1) to require only a written or lessening the intensity of the that the others do not. In addition, the notice. investigation and diminishing its incorporation of the failure reporting potential value. procedures of API Spec. 6A and API Comments Related to Proposed • Response: The commenter Spec. 16C adds value to this provision § 250.730(c)—Concerns About Who apparently misinterpreted the proposed because those standards apply Should Submit Failure Reports rule as requiring that the findings of the specifically to equipment that is part of Summary of comments: Some failure analysis be produced within 60 a BOP system. BSEE expects that the commenters stated that, since operators days, when the proposed requirement failure reporting procedures of all three do not own the BOP equipment, and are actually provided that the investigation standards will complement each other. not the primary source of failure data, and analysis must be initiated within 60 On the other hand, BSEE sees no need failure reports should come from the days. Nonetheless, BSEE agrees with the to provide guidance on the potential use drilling contractors. Therefore, the commenter that 60 days may not be of API Specs. 6A and 16A at this time. commenters recommended revising this sufficient for an effective failure As experience and additional section to state that the operator must analysis to be performed. However,

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BSEE does not agree with the Comments Related to Proposed available from ANSI, and that BSEE commenter’s suggestion that 6 months § 250.730(c)(3)—Questions Concerning should incorporate API Spec. Q1 9th or more may be necessary to produce Who Must Notify BSEE of Failures edition, as it is the correct edition. In the findings of such analysis. There is Summary of comments: A commenter addition, other commenters asserted value to concluding the analysis, and requested that BSEE clarify paragraph that there is no API standard for a BOP providing the results to the (c)(3) regarding who is required to notify stack, and that API Spec. Q1 would manufacturer at a reasonably early date BSEE of an equipment design change or apply only to the individual after the failure, so that any necessary components. change in operating or repair • follow up actions can be taken sooner, procedures; i.e., whether it should be Response: BSEE already and thus potentially prevent additional the operator or the contractor (the owner incorporates ISO 17011 under related failures from occurring. of the equipment involved in the §§ 250.1900, 250.1903, 250.1904, and Accordingly, BSEE has revised final failure.) 250.1922 for qualifications of § 250.730(c)(2) by modifying the time • Response: Paragraph (c)(3) clearly accreditation bodies under SEMS. Incorporating that standard here ensures for performing a failure analysis to 120 requires the operator to report the consistency with the SEMS days. design changes or modified procedures, unless another person covered by the requirements for quality management Comments Related to Proposed regulatory definition of ‘‘you’’ informs systems. Regarding incorporation of ISO § 250.730(c)—Failure Occurrence the operator it has done so. 29001 as an optional alternative standard, BSEE generally expects that Summary of comments: A commenter Comments Related to Proposed operators are following the industry suggested that BSEE revise this section § 250.730(c)(3)—Submittal of Failure developed standards, regardless of to reflect only failures that occur when Report to BSEE whether the standard is incorporated in the BOP system is in service and not Summary of comments: Some the regulations. However, when BSEE during maintenance periods. comments questioned why the report of incorporates a standard in the • Response: BSEE does not agree that equipment changes or procedural regulations, compliance with that these suggested changes are necessary. changes must be sent to BSEE’s standard is not optional. An operator In § 250.730(c), BSEE incorporated the headquarters office instead of the may request approval from BSEE to District Manager. comply with an alternative standard failure reporting requirements of 3 • industry standards, and those standards Response: BSEE will require that under § 250.141. BSEE recognizes the concerns related to incorporating the provide enough specificity as to when a these reports be sent to BSEE most current edition of each standard. failure triggers the need for reporting. In headquarters in order to ensure that The issue of incorporation of a newer any event, a failure may be an indicator emerging trends occurring across various Districts and Regions are edition was addressed in comment- of a serious problem requiring recognized early and that potentially responses under § 250.198. The change investigation and potential follow-up serious concerns can be addressed in a to a new edition or removal of a action whenever the failure occurs. coordinated and uniform way discontinued standard is not automatic Comments Related to Proposed nationwide. and requires rulemaking. Operators may § 250.730(c)(2)—Analysis Report request approval from BSEE to follow a Comments Related to Proposed later edition of a standard under Summary of comments: Another § 250.730(d)—Scope of API Spec. Q1 § 250.198(a)(1). BSEE recognizes that commenter recommended that BSEE (Quality Control) API Spec. Q1 applies to the manufacture revise proposed paragraph (c)(2) by Summary of comments: One of individual components, however, as changing ‘‘copy of the analysis’’ to commenter asserted that the proposed previously stated, the intent of the ‘‘results of the investigation.’’ regulation at § 250.730(d) does not provision is that the complete BOP stack • Response: BSEE agrees with the clearly define the scope of the must be manufactured pursuant to API requirement to implement API Spec. Spec. Q1, not the individual substance of this comment and has Q1. The commenter requested that BSEE components of the BOP system. revised final § 250.730(c)(2) by changing clarify whether this requirement only ‘‘copy of the analysis’’ to ‘‘copy of the Comments Related to Proposed applies to complete BOP stacks, or if it analysis report.’’ This revision will § 250.730(d)—Applicability of API Spec. also includes any BOP component that ensure that the results of the analysis, Q1 (Quality Control) is manufactured after the including any recommendations for implementation of the rule (e.g., a single Summary of comments: Some corrective action, are documented and BOP ram). comments requested that BSEE clarify provided to the manufacturer. BSEE • Response: The intent of the this provision since ‘‘BOP stacks’’ are expects that the analysis report will provision is that the complete BOP stack not ‘‘manufactured;’’ i.e., only the describe the analysis as well as the must be manufactured pursuant to API components are manufactured. In results, since it is frequently useful to Spec. Q1, not the individual addition, compliance with the API review the analysis to determine the components of the BOP system. standard incorporated by reference adequacy of the results. For the same should be sufficient; there is no need for reason, BSEE has revised final Comments Related to Proposed BSEE to add ISO requirements. § 250.730(c)(2) to require that a copy of § 250.730(d)—Reference to ISO 17011 • Response: BSEE recognizes that API the analysis report also be provided to Summary of comments: Some Spec. Q1 applies to the manufacture of BSEE, since it is important that BSEE be commenters suggested that the reference individual components, however, as aware of the results of failure analyses to ISO 17011 is incorrect and that the previously stated, the intent of the in order to help BSEE identify potential actual reference should be to ISO 17021. provision is that the complete BOP stack trends and, if appropriate, make others In addition, they suggested that BSEE must be manufactured pursuant to API aware of a potential problem that may add ISO 29001 as an optional alternative Spec. Q1, not the individual require action to prevent similar failures standard. They also noted that ANSI/ components of the BOP system. The or to improve equipment reliability. API Spec. Q1 8th edition is no longer incorporation of ISO 17011 ensures the

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manufacturers of the BOP systems program to the Chief of OORP and not required to be submitted with APDs, follow the quality management system to submit the request under § 250.141. APMs and other submissions is required by API Spec. Q1. necessary to help BSEE make informed What information must I submit for BOP decisions in the approval process by Comments Related to Proposed systems and system components? providing a clear understanding of the § 250.730(d)(1)—Approval of Other (§ 250.731) BOP system, equipment and operations. Quality Programs As provided for in the proposed rule, These provisions essentially set Summary of comments: With regard this section consolidates and revises performance-based goals for the to the proposed option under requirements from various former operators and verifiers, and several of § 250.730(d)(1) for seeking BSEE sections for including BOP information the descriptions of processes and approval for BOP equipment in APDs, APMs or other submittals to equipment that must be verified are manufactured under some quality BSEE. Among other things, paragraphs broad enough to allow the persons program other than API Spec. Q1, a (a) and (b) require submission of a doing the verification some flexibility to commenter stated that operators are not complete description and schematic decide whether, under the specific typically in the business of drawings of the BOP system. Paragraph circumstances, it is the equipment or manufacturing BOPs for their (c) requires submission of a certification process that should be verified. operations. Instead, they typically select by a BAVO: That test data demonstrates BSEE also disagrees with the a MODU/Rig with a BOP as part of the the BOP shear ram(s) will shear the drill comment indicating that these equipment package. Therefore, these pipe as required; that the BOP was verification requirements are requirements should be placed upon the designed, tested, and maintained to unnecessary. BSEE believes that these drilling contractor when applying for perform under the anticipated certification and verification provisions their license to operate in the U.S. maximum environmental and will serve as a useful tool for BSEE and Another commenter asserted that operational conditions; and that the the industry to better ensure—as proposed § 250.730(d)(1) would allow accumulator system has sufficient fluid compared to the current rules and for potential approval of an alternative to operate the BOP system without industry practices—that equipment and quality program (instead of API Spec. assistance from the charging system. processes function as intended to Q1) for the manufacture of BOP Paragraph (d) requires additional protect safety and the environment. equipment, but that the path for certification by a BAVO regarding the obtaining such approval does not appear design and functionality of BOPs used Comments Related to Proposed to be available to contractors (unless in certain circumstances (e.g., subsea § 250.731(a)—BOP System Connections sponsored by an operator). BOPs); while paragraph (e) requires Summary of comments: A commenter • Response: Section 250.730(d) is descriptions of the autoshear, deadman, noted that § 250.731(a)—requiring applicable to operators/lessees in the and EDS systems on subsea BOPs. descriptions of BOP systems—does not same way that most of the requirements Paragraph (f) requires a certification that address how the devices along the BOP in existing part 250 are applicable. the required MIA Report has been stack are connected, and that there is no Ultimately, the operator/lessee is submitted within the preceding 12 mention of capping or containment responsible for compliance with these months. BSEE has revised proposed points along the BOP stack. The requirements. As is common practice paragraphs (c) and (d) of this section in commenter suggests that the BOP under the regulations, however, the final rule as discussed in the system description should address operators may contract with others for comment responses for this section.16 technology that enables better the performance of many of the required Comments Related to Proposed containment and is integrated with that actions. In that case, the operator/lessee § 250.731—Concerns About Prescriptive system. Locations along those devices at and the person (contractor) actually Requirements which containment and capture performing that activity are jointly and equipment may be attached should also severally responsible for compliance Summary of comments: BSEE be included in the system description. with the applicable requirement. (See received a comment stating that this • Response: BSEE disagrees with the § 250.146(c).) The actions required by section is overly prescriptive on certain commenter that capping or containment § 250.730(d) are no different. issues, including accumulator sizing, points should be included in this testing, BOP configurations, and QA/QC provision. It is unclear from the Comments Related to Proposed oversight. comment what devices, technology, and § 250.730(d)(1)—Request for Alternative Another commenter claimed that this shortcomings the commenter would Quality Programs section would be unnecessary given that propose including in § 250.731(a). In Summary of comments: Commenters effective verification processes are any case, source control and also noted the proposed rule refers to already in place, and that the additional containment requirements are approval of alternatives under verifications required by this rule would adequately covered under final § 250.141, which is granted by District not increase the safety of operations or § 250.462, as described elsewhere in this Managers and Regional Supervisors, but the reliability of equipment. • document. requires that the request be submitted to Response: BSEE disagrees with the the Chief, Office of Offshore Regulatory comment that this section is overly Comments Related to Proposed Programs (OORP). The commenter prescriptive. The specific information § 250.731(a)(7) Through (9)— noted that, even if approval by the Chief Calculations of OORP is obtained, the accepted 16 Any information submitted to BSEE should Summary of comments: Another identify any confidential commercial or proprietary alternative would not appear to be information. Any confidential or proprietary commenter observed that the binding on other District Managers or information will be protected consistent with the calculations required in paragraphs Regional Supervisors. Freedom of Information Act (5 U.S.C. 552) and § 250.731(a)(7) through (9) should • Response: BSEE agrees with the DOI’s implementing regulations (43 CFR part 2); demonstrate that there is adequate section 26 of OCSLA (43 U.S.C. 1352); 30 CFR comment and revised final § 250.730(d) 250.197, Data and information to be made available pressure available to operate each item, to require operators to send the requests to the public or for limited inspection; and 30 CFR especially shear rams. The commenter to use an alternative quality assurance part 252, OCS Oil and Gas Information Program. suggested adding information to the rule

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that confirms this is the purpose for are used in conjunction with testing to Commenters were also concerned that conducting the calculations, and demonstrate that the pipe can be this requirement may impact suggests that the calculations should sheared at the well. Therefore, no compliance with API Specs. 16A and take into account the actual planned revision to paragraph § 250.731(c)(1) is 16D. Commenters suggested that BSEE sequence of BOP operation for warranted. revise this section to require the deadman, autoshear, and any emergency Comments Related to Proposed accumulator system to have sufficient disconnect programmed operations. fluid, as defined by § 250.734(a)(3) for • Response: BSEE disagrees with the § 250.731(c)(2)—Most Extreme Anticipated Conditions subsea accumulators and § 250.735(a) suggestion that we include the purpose for surface accumulators, to function the for conducting the calculations, and Summary of comments: Most of the BOP system without assistance from the specifying that the calculations must comments concerning paragraph charging system. Other commenters take into account the planned sequence. § 250.731(c)(2) were related to the suggested that BSEE revise this BSEE will review the volume and pre- requirement for verification that the provision to refer to the accumulator charge accumulator calculations BOP has been designed, tested and volume test in API Standard 53. maintained to perform under the ‘‘most required by paragraphs § 250.731(a)(7) • and (9), regardless of sequence, to extreme anticipated conditions.’’ Response: BSEE does not agree that determine that they are adequate to Commenters expressed concerns that the suggested changes to paragraph operate all of the required BOP the term is undefined and asked § 250.731(c)(3) are necessary given that, functions specified in §§ 250.734(a)(3) whether this phrase refers, for example, as discussed elsewhere, BSEE has and 250.735(a) without assistance from to the worst-case discharge or a kick. revised the final accumulator the charging system. Commenters also stated that shearing requirements of § 250.734(a)(3) for and sealing on flowing wells at worst- subsea accumulators and § 250.735(a) Comments Related to Proposed case discharge rates is not a typical for surface accumulators to more closely § 250.731(c)—Verification of Shearing drilling BOP testing scenario, and the align with API Standard 53. Those Test Data commenters described how testing to revisions are consistent with Summary of comments: Commenters verify BOP capabilities is commonly recommendations made by some of questioned the requirement in proposed performed. Commenters also pointed these commenters. paragraph § 250.731(c)(1) for out potential hazards from testing for verification of test data on shearing worst-case discharges. Commenters Comments Related to Proposed capabilities. Since a test facility to suggested that BSEE’s emphasis should § 250.731(d)(1)—Verification of BOP simulate subsea conditions for shear be on early detection and correct shut in Design testing does not exist, the requirement procedures. A commenter asserted that Summary of comments: Several of the for shear testing at water depth implies none of the BOPs currently in use comments on proposed paragraph the BOP is in an environment that would meet the ‘‘most extreme § 250.731(d)(1) raised concerns with the simulates the required water depth anticipated conditions’’ requirement, requirement for verification that the (instead of on the surface, where shear and that OEMs do not qualify BOP BOP stack is designed for the specific tests are currently performed). The components under flowing conditions. equipment on the rig and for the commenters asserted that there is a risk Commenters recommended that the specific well design. Commenters of damaging equipment when carrying requirement should be to ‘‘ensure the asserted that the BOP stacks are not out shearing tests under these BOP is designed, tested, and maintained designed for specific equipment; they conditions. The current industry to perform under the anticipated are selected in consideration of such practice is to apply proven calculation conditions of the well.’’ equipment, which is designed to meet methods to surface shear test data and • Response: As previously discussed, the RWP conditions for the site. Also, relevant maximum allowable working BSEE has revised paragraph BOP stacks are not moved from rig to pressure conditions. The commenters § 250.731(c)(2) by replacing ‘‘to perform rig, they are part of the rig equipment claimed that if shear tests must be at the most extreme anticipated and selected to suit the rig design and performed under subsea conditions, all conditions’’ with ‘‘to perform under the capabilities. Commenters suggested that of the past shear test data will be maximum conditions anticipated to BSEE revise this provision to require the irrelevant, and that the time and effort occur at the well.’’ This change clarifies BOP stack be suitable for use with the to re-test will likely shut down the GOM this requirement by relying on specific equipment on the rig, instead of for a considerable time. The reasonably predictable, site-specific designed for the equipment. commenters requested that BSEE revise conditions instead of hypothetical this requirement to allow supporting worst-case conditions. In any event, if • Response: BSEE does not agree that engineering calculations instead of test an operator has any questions about the it is appropriate to remove the reference data for shear capability. maximum anticipated conditions in any to ‘‘designing’’ the BOP stack. The Another commenter recommended specific case, it may request assistance commenters appear to be interpreting that the equipment manufacturers from the District Manager. that term unnecessarily restrictively. should demonstrate shearing capability BSEE believes that the process and provide shearing data instead of Comments Related to Proposed described by the commenters for how operators having to do so. § 250.731(c)(3)—Accumulator Systems BOP stacks are put together with regard • Response: BSEE agrees that there Summary of comments: The primary to the equipment on the rig is effectively are technological limitations with concern raised by commenters regarding what BSEE intended by ‘‘designed.’’ testing facilities to simulate subsea paragraph § 250.731(c)(3) was that there BSEE does agree, however, with the conditions. BSEE currently allows, and appeared to a conflict between the commenters that the BOP stack must be will continue to allow, operators to use requirement for the accumulator suitable for use with the specific calculations to help verify shearing at systems, on the one hand, and API equipment on the rig. Accordingly, water depth. In fact, this provision Standard 53, as well as the current work BSEE has revised final § 250.731(d)(1) expressly references final § 250.732, industry is undertaking to update the by inserting ‘‘and suitable’’ after the which clearly provides that calculations specifications, on the other. word ‘‘designed.’’

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Comments Related to Proposed that the regulation does not identify BAVOs cannot be ‘‘approved’’ by BSEE § 250.731(d)—Independent Verification who issues the certification. until after the effective date of the final • Response: This comment is vague Summary of comments: A commenter rule (i.e., 3 months after publication); and unclear. The MIA certification recommended that BSEE revise therefore, compliance with the proposed required in paragraph (f) must be proposed § 250.731(d) in order to § 250.731(c) and (d) certification included in the applicable APD or APM, require independent verification of all requirements within 3 months, as but BSEE is not aware of any OCS operations requiring a BOP (rather proposed, would not be possible. Some duplication between this requirement than just the operations specified in the commenters claimed this could result in and any other certification requirement. a bottleneck that would effectively proposed rule), since the purposes of BSEE does not specify who must independent verification are not unique become a moratorium on OCS drilling. provide the certification in paragraph Given the other demands of the to subsea BOPs, surface BOPs on a § 250.731(f); so any appropriate person floating facility, or BOPs operating in a proposed rule, some commenters acting on behalf of the operator/lessee asserted that 3 years is a more feasible HPHT environment. The commenter may do so. recommended that BSEE revise the rule timeline for implementation of this Summary of comments: Many requirement. Other commenters, in this way and then reconsider, after commenters recommended that BSEE several years, whether the program is however, requested that the BAVO revise or delete § 250.731(f) as certification requirements should not go working effectively and delivering duplicative or unnecessary and results, or whether it should be scaled into effect until 12 months after the burdensome. Some commenters initial BAVO list is published. back. requested that BSEE clarify whether this • • Response: BSEE does not agree that Response: As previously discussed certification is required only if an APD in part V.C of this document, BSEE has the requested change is appropriate at has not been submitted in the previous this time. The verifications required in revised the final rule to extend the 12 months. Commenters suggest that, if compliance dates for certain provisions, paragraphs § 250.731(a) through (c) are it is in addition to an APD submitted already applicable to all BOPs. including those that require the use of within the prior 12 months, it appears a BAVO. Under the final rule, operators’ Paragraphs § 250.731(d) through (f) only to be an unnecessary time and expense apply to BOPs used in certain situations APD will not be required to submit burden. BAVO certifications under § 250.731 because BSEE determined that those Other commenters stated that this until one year from the date when BSEE situations present higher risks than the report is unnecessary, asserting that all publishes a list of approved other situations in which BOPs are of the requested information is already organizations. BSEE anticipates that used. The certification and/or reported in the APD/APM and the BOP most of the current independent third- verification requirements in paragraphs and Well Compatibility Certificate. § 250.731(d) through (f) are specific to • Response: BSEE does not agree that parties currently used by industry could the equipment, systems or procedures paragraph § 250.731(f) should be deleted become BAVOs; thus, one year will be that are related to such risks. BSEE does or revised for any of the reasons sufficient for operators to make use of a not believe those same concerns apply suggested by the commenters. As BSEE-developed list of BAVOs suitable equally to the BOP situations described required by § 250.731, a certification for this rulemaking. in paragraphs§ 250.731(a) through (c). statement as described in paragraph (f) Summary of comments: A commenter asked if BSEE approval as a verification Comments Related to Proposed must be included each time an APD or APM is submitted. Therefore, if organization is open for any company § 250.731(e)—Subsea BOP Descriptions that applies. multiple APDs/APMs are submitted • Summary of comments: Regarding the within a 12 month period, each one Response: Any verification proposed requirement in paragraph must include a certification statement organization that seeks approval and § 250.731(e) that subsea BOP that an MIA Report was completed submits the information specified in descriptions include a description of the within the 12 months preceding that § 250.732(a) to BSEE may be considered EDS, commenters recommended that APD/APM. However, the regulation by BSEE for approval as a BAVO. BSEE add ‘‘if installed’’ after ‘‘EDS does not require that a certification be Summary of comments: A commenter systems.’’ submitted every 12 months separately suggested that BSEE should allow use of • Response: BSEE does not agree that from an APD/APM. Nor does it require current verification companies this change is appropriate. BSEE already that an MIA Report be completed or whenever a BAVO is not available. • recognizes that an EDS system is not submitted every time an APD or APM is Response: Under § 250.732, BSEE installed or necessary on every rig with submitted. will not require the use of BAVOs until a subsea BOP, and § 250.731(e) is not In addition, BSEE disagrees that the one year after BSEE establishes a BAVO intended to require descriptions for EDS requested information (i.e., a list. After that occurs, there will not be systems that are not present and not certification statement regarding any need to use other verification otherwise required by the regulations completion of an MIA Report) is already companies. BSEE expects many existing (see § 250.734(a)(6)). required to be submitted with an APD. independent third-parties and Section 250.731(f) itself establishes that verification companies to become Comments Related to Proposed BAVOs. § 250.731(f)—MIA Report requirement. BSEE is unaware of any BOP and Well Compatibility certificate, Summary of comments: Some Summary of comments: A commenter as mentioned by the commenter, that is commenters asserted that the suggested that the MIA report currently applicable and duplicative of requirements to use BAVOs for certification required by § 250.731(f) is § 250.731(f). certification could create conflicts of equivalent to the certification in the interest and render the third-party APD. The commenter suggested that the Comments Related to Proposed neutrality concept ineffective. That is, if regulation be revised to consider either § 250.731(c) and (d)—BAVOs BSEE approves the verification an MIA or an APD certification Summary of comments: Several organization, and the operators/ submitted within the past 12 months as commenters highlighted the fact that contractors are required to hire them, sufficient. The commenter also asserted BAVOs do not currently exist and that neither BSEE nor the BAVO nor the

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operators would be independent of each paragraph (b) lists the types of actions the equipment is suitable for the other. (e.g., shear testing) for which an conditions under which it will operate. A commenter asserted that BAVOs operator must submit BAVO In addition, while BSEE appreciates provide BSEE with selective powers not verification. Paragraph (c) of this section the value of operators’ existing quality generally associated with a regulatory requires additional BAVO verifications control programs, including those based organization in a free market system. for BOPs and related equipment on API Spec. Q1 or similar standards, Commenters recommended that BSEE associated with wells in an HPHT BSEE cannot rely on such voluntary remove/delete all references to BAVOs environment. Paragraph (d) requires an programs to provide the information or due to potential legal implications and operator to submit to BSEE an annual assurances that BSEE needs. As restriction of trade. MIA report prepared by a BAVO. These explained in the proposed rule, • Response: BSEE disagrees with the BAVO actions will help BSEE ensure § 250.732 is necessary to ensure that suggestion that the BAVO approach will that BOPs will perform as necessary to BSEE receives accurate information compromise third-party neutrality or protect safety and the environment from regarding BOP systems so that BSEE effectiveness or is otherwise losses of well control. BSEE has revised may ensure the system is appropriate for impermissible. To the contrary, certain provisions of the proposed rule the proposed use. In particular, the approval of verification organizations by in final § 250.732 as discussed in the verification and documentation of such BSEE will ensure that the BAVOs are comment responses for this section and information by a BAVO would enhance independent of the parties whose in part V.C of this document. BSEE’s review of the information in crucial equipment and processes the APDs and APMs. (See 80 FR 21509, BAVO will review and evaluate. Other Comments Related to Proposed 21522.) BSEE believes that the regulatory regimes throughout the world § 250.732—Existing Quality Control importance and complexity of BOP use similar systems. Systems systems warrant a thorough and regular Summary of comments: Some Summary of Comments: Many assessment of the systems and commenters also asked how BAVOs will comments asserted that operators verification that design, installation, work and what specific factual already have adequate systems in place maintenance, inspection, and repair situations BAVOs would or would not for quality control (e.g., voluntary activities for such systems are be able to certify or verify under compliance with API Spec. Q1 or documented and traceable. The BAVO- §§ 250.731(c) and (d) and 250.732 (e.g., similar standards), to verify related provisions in § 250.732 will how will a BAVO be able to verify that repeatability of testing, and/or to serve this purpose, through independent a stack has not been compromised from engineering reviews to ensure that previous service?). comply with existing requirements under BSEE’s regulations for SEMS required testing is effective at ensuring • Response: These comments seek the equipment will perform as designed answers to hypothetical questions about programs (including a requirement for SEMS program audits). Commenters under the conditions to which it will be how the rules may be implemented in exposed. (See 80 FR 21509.) Voluntary suggested that these systems adequately very specific factual situations. It would compliance with industry standards address many of the same items subject be premature and speculative for BSEE alone cannot provide BSEE with such to BAVO verification under proposed to attempt to do so. A BAVO will need assurances. to certify or verify the matters specified § 250.732, and thus, that BAVO Similarly, BSEE believes the SEMS in §§ 250.731 and 250.732, but those verification of similar issues is regulations are an important step toward rules do not prescribe exactly how the unnecessary and overly burdensome. building an offshore safety culture that • BAVO must perform those tasks. Rather, Response: BSEE does not agree that includes oil and gas companies as well the purpose of BSEE evaluating and the BAVO-related requirements of as their employees and contractors, and approving verification organizations to § 250.732 are unnecessary; nor does the SEMS rules will result in substantial serve as BAVOs is to ensure that they BSEE agree that those requirements will safety and environmental protection are knowledgeable and capable enough not provide additional value, to justify improvements over time. However, the to perform these tasks without BSEE the burdens on the operators, compared SEMS requirements are very different needing to prescribe in great detail how to existing voluntary industry practices from, and serve different purposes than, to do so under a very specific factual and BSEE’s other regulatory the BAVO-related requirements. The scenario. requirements. Third-party consultants SEMS regulations focus on creating hired by the operator for quality control, internal safety and environmental What are the BSEE-approved to confirm equipment testing management systems that will foster verification organization (BAVO) repeatability, or for a SEMS audit do not safety and environmental protection by requirements for BOP systems and address the specific BOP and well- ensuring that offshore personnel comply system components? (§ 250.732) control issues required by the present with policy and procedures identified in As provided for in the proposed rule, rule. Quality control and equipment a facility’s SEMS plan. The SEMS rules this new section creates a process for testing repeatability are, as stated in the lay out largely performance-based BSEE to identify BAVOs and sets out comments, addressed by several elements that the SEMS plan must various situations that require voluntary industry standards. While address in areas such as hazards verification or a report by a BAVO. compliance with industry standards that management, inspections and Paragraph (a) clarifies that BSEE will are not incorporated in the regulations maintenance, training, and quality develop and maintain a list of BAVOs is voluntary, the BAVO verifications assurance and mechanical integrity of on its public website, and that required by the final rule will document critical equipment. (See § 250.1901.) compliance with the BAVO-related compliance with key regulatory However, the SEMS rules do not provisions of the rule will not be requirements for ensuring that BOPs prescribe specific technical required until 1 year after BSEE issues will perform as needed to protect safety requirements that the plans must ensure that list. Paragraph (a) also specifies the and the environment. For example, the are met. Nor is BSEE routinely informed information (regarding qualifications) final rule requires verification of shear of the specific results from actual that applicants for inclusion on the testing, pressure integrity testing, and implementation of the SEMS plan at a BAVO list must submit; while related calculations for verifying that rig.

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By contrast, BAVO verifications or one year after BSEE publishes a list of capable of performing their intended reports under § 250.732 will provide BAVOs. BSEE has determined that this functions. BSEE with important information will provide enough time for operators In any case, BSEE will publish a list regarding, among other things: Actual to select a BAVO and for the BAVO to of BAVOs so that choices will be shearing capabilities (through perform the required verifications. In available to operators. BSEE expects that recognized testing protocols and the interim, for the reasons previously there will also be enough listed BAVOs analyses), and pressure integrity testing discussed, BSEE has revised final that operators will be able to base their (see § 250.732(b)); comprehensive § 250.732(a) to require operators to use choices between BAVOs on various review of the BOP system demonstrating an independent third-party to provide factors, such as experience, price, the performance and reliability of the the certifications, verifications, and availability, and access to appropriate equipment; and annual reports by the reports that a BAVO must provide after technology. After the initial BAVO list BAVO on mechanical integrity for BOPs the requirements to use a BAVO become is published, BSEE will continue to used in certain high risk environments. effective. evaluate other verification organizations BSEE needs the information that BAVOs that apply for approval as BAVOs and will verify or create in order to ensure Comments Related to Proposed will refresh or supplement the list from that effective and appropriate well- § 250.732(a)—General Comments on time to time as necessary to ensure that control equipment and procedures are BAVOs choices continue to be available to actually in place to prevent or minimize Summary of Comments: Multiple operators. future well-control events. BSEE cannot comments raised the following issues: Concerning the suggestion that BSEE get that kind of information through (a) BSEE is restricting industry’s choice should provide industry with the operators’ voluntary compliance with of third-parties by requiring use of a opportunity to comment on the detailed either industry standards or the SEMS BAVO; BSEE should provide industry scope of the work that BSEE intends regulations. with the opportunity to comment on the BAVOs to perform, the final rule, in However, in response to commenters’ intended detailed work scope for a §§ 250.731 and 250.732, provides the suggestions that BSEE allow the BAVO; (b) industry must be provided scope of the certifications and continued use of independent third- with a means of recourse to BSEE on verifications that BAVOs must perform. As to how a BAVO will perform each parties to perform verifications (as decisions made by BAVOs where there specific task for a specific facility, the required under provisions of the is a difference of opinion regarding the BAVO and the operator employing the existing regulations that are being application or interpretation of a rule or 17 BAVO will work together to determine replaced by these final rules), and to standard; and (c) some of the proposed the precise nature and execution of the comments requesting additional time to requirements imply that the BAVO may work. BSEE expects that the BAVOs and comply with the BAVO requirements, make recommendations on how to operators will establish these BSEE has revised § 250.732(a) of the improve the fabrication, installation, parameters through the contracting final rule. The revised paragraph will operation, maintenance, inspection, and process. require that an independent third-party, repair of operator equipment. meeting the same criteria as specified in Concerning the comments that • Response: Concerning the former § 250.416(g)(1), perform the same industry should have a means of comments on BSEE restricting functions that a BAVO must perform recourse to BSEE on decisions made by industry’s choice of third-parties by until such time as the operator uses a BAVOs where there is a difference of requiring use of a BAVO, BSEE is aware BAVO to perform those functions (i.e., opinion regarding application or that the requirement to use BAVOs will no later than 1 year after BSEE interpretation of a rule or standard, impose some limits on the choices of publishes a list of BAVOs). several means exist for BSEE to resolve third-parties. However, that is an such differences of opinion. In the first Comments Related to Proposed unavoidable feature of any requirement place, BSEE expects the BAVO and the § 250.732(a)—Timing of Compliance that depends on the use of a third-party operator to communicate with each With BAVO Requirements having relevant qualifications necessary other and attempt to resolve any Summary of Comments: Many to perform specific tasks, whether BSEE differences of opinion in a mutually comments asserted a need for sufficient determines who meets those acceptable way. However, if necessary, time to comply with the BAVO-related qualifications or the operators make the operator may refer requests for an requirements after BSEE issues a list of those decisions themselves. In addition, interpretation of a specific regulation, or BAVOs. Specifically, multiple for the reasons stated in the proposed a standard incorporated in the comments addressed the need for time rule, BSEE determined that it is regulations, to BSEE for assistance. In to select a BAVO and to have the BAVO necessary for each BAVO performing addition, if it appears that there is a implement the required verifications. the important safety and environmental broader need for an interpretation to These comments raised essentially the tasks specified in §§ 250.731 and guide BAVOs and operators, BSEE will same concerns previously discussed 250.732 to be technically qualified, consider issuing a NTL, an Information with regard to BAVO certifications as experienced and capable of performing to Lessees and Operators, or a similar required by § 250.731. the functions necessary for BSEE and notice of interpretation or guidance, as • Response: BSEE, as previously the public, as well as the operators, to appropriate. explained, has revised the final rule to be sure that the BOP systems and BSEE disagrees with the comments extend the time required to comply with equipment will function as intended. suggesting that the proposed the requirements to utilize a BAVO until Therefore, in its oversight role, it is requirements imply that the BAVO may necessary that BSEE make the first make recommendations on how to 17 Former §§ 250.416(e) and (f), 250.515(c) and decisions as to which third-parties are improve the fabrication, installation, (d), 250.615(c) and (d), and 250.1705(c) and (d) eligible to be used for these purposes, repair, etc., of operator equipment. The require verifications of various aspects of drilling, rather than leaving that decision rule does not state or imply that a BAVO completion, workover and decommissioning must or should make recommendations operations, respectively. Those requirements are entirely to the operators whose superseded and replaced by the requirements of equipment and processes must be to an operator with respect to the final § 250.731(c) and (d). evaluated and verified to be suitable and equipment. However, BSEE does expect

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the BAVO process to help, over time, Comments Related to Proposed § 250.732(b)(1)(ii) is intentionally the industry to improve the performance § 250.732(b)(1)(i)—BOP Shearing Tests general and performance-based so as to of the equipment and to develop more Summary of Comments: Multiple leave operators free to use testing and better testing protocols. (See 80 FR commenters raised concerns with the facilities that meet generally accepted 21509.) proposed requirement in quality assurance standards. BSEE Comments Related to Proposed § 250.732(b)(1)(i) for shearing tests that believes that operators are capable of § 250.732(a)(1) Through (7)—Criteria for demonstrate the BOP will shear the drill identifying such standards, but if future BAVOs pipe and any electric-, wire-, and slick- experience under this provision line to be used in the well. They demonstrates that operators need Summary of Comments: Multiple guidance to identify such standards, comments asserted that the criteria used asserted that many rigs do not currently have shearing capability that would BSEE may provide appropriate guidance to evaluate the technical knowledge of at a later date. the BAVOs must be established in conform to that requirement and cannot advance and be more detailed than the obtain such equipment within the 3 Comments Related to Proposed proposed criteria. A commenter also months provided by the proposed rule § 250.732(b)(1)(v)—BOP Shearing suggested that industry should be for compliance. As a result, many Capacity drilling operations could be shutdown. consulted in helping to identify Summary of Comments: Several qualified candidates. However, other They requested that BSEE extend the requirement for shearing the exterior commenters requested that BSEE revise commenters recommended that the proposed § 250.732(b)(1)(v)—regarding regulation expressly require BAVOs to control lines (e.g., wire-line) to 5 years. • demonstration of the shearing capacity be independent of equipment Response: BSEE agrees that more time may be necessary to allow of the BOP—to clarify that the manufacturers and operators. demonstration must be specific to the • Response: BSEE disagrees with the installation on all BOPs of shear rams capable of shearing electric-, wire-, drill pipe to be used in the well. comments calling for more detailed • BAVO criteria. Proposed § 250.732(a)(1) slick-lines to be used in the hole. Response: BSEE disagrees with the through (6) (renumbered as However, BSEE does not agree that 5 suggested change to specify that this § 250.732(a)(3)(i) through (vi) in the years is necessary for compliance with requirement applies only to the drill final rule) specified the criteria that this requirement. Although 5 years pipe used or to be used in the well, BSEE would apply in evaluating the might be appropriate if no technology since that point is already stated in qualifications, caliber, and technical capable of meeting this requirement § 250.732(b)(1)(i), and the same knowledge of each verification existed, BSEE is aware that some limitation is implied throughout organization before deciding whether it technology to meet this requirement § 250.732(b)(1). should be approved. The commenters already exists (and thus does not need Comments Related to Proposed on this issue provided no additional to be newly developed after § 250.732(b)(1)(vi)—BOP Shearing Test detailed criteria for BSEE to apply in promulgation of this rule). Nonetheless, Results evaluating verification organizations, BSEE understands that significantly and BSEE sees no reason to add more more than 90-days will be needed for all Summary of Comments: Several criteria at this time. operators to obtain, modify (if necessary commenters requested that BSEE revise In addition, BSEE disagrees with the to meet specific circumstances), and the proposed requirement in suggestion that industry should be install the technology. Therefore, BSEE § 250.732(b)(1)(vi) that ‘‘all [shear] consulted in helping to identify BAVO has revised §§ 250.732(b)(1)(i) and testing results’’ be provided to BSEE by candidates. As explained in the 250.734(a)(1)(ii) in the final rule to changing ‘‘all’’ to ‘‘relevant.’’ proposal, the purpose of the BAVO extend the compliance date for • Response: BSEE agrees with the concept is to ensure that BOP demonstrating that the BOP can shear commenter and has revised final equipment is monitored during its electric-, wire-, or slick-line until 2 § 250.732(b)(1)(vi) by replacing ‘‘all’’ lifecycle by an ‘‘independent third- years after publication of the final rule. testing results with ‘‘relevant’’ testing party’’ to verify compliance with the This extended compliance date will results. This change will ensure that the regulations, OEM recommendations, allow sufficient time for operators to testing data provided to BSEE is and recognized engineering practices. acquire and install appropriate applicable and relevant to the specific (See 80 FR 21522.) As explained in the equipment without causing any rig shear testing issues covered by proposed rule, a potential BAVO must downtime. § 250.732(b)(1) and that other, non- apply to BSEE for approval, and must relevant testing results, which could submit specific information and Comments Related to Proposed cause confusion, are not submitted. documentation demonstrating its § 250.732(b)(1)(ii)—BOP Shearing Tests Comments Related to Proposed qualifications and experience, as Summary of Comments: One § 250.732(b)(1)(iv)—Off-Center Pipe provided in § 250.732(a)(1) through (7). comment was received on proposed Shearing (See id. at 21510, 21522.) BSEE will § 250.732(b)(1)(ii), requiring a then evaluate that specific information demonstration that the operator’s shear Summary of Comments: Multiple to determine whether the verification testing at a facility that meets generally commenters stated that proposed organization is qualified to carry out the accepted quality assurance standards. § 250.732(b)(1)(iv)—regarding off-center BAVO-related tasks listed in The commenter stated that ‘‘generally pipe shearing—was inconsistent with § 250.732(b) through (d) and in other accepted quality assurance standards’’ proposed § 250.734(a)(16), which sections. If BSEE determines, based on needs to be clarified, and recommended requires operators to install shear rams the information submitted and BSEE’s that BSEE provide examples of this that center drill pipe during shearing no understanding of the specific tasks requirement (e.g., ISO 9001). later than 7 years from the publication BAVOs must perform, that an • Response: BSEE does not believe of the final rule. One suggestion was to organization is qualified to perform that revisions to the regulatory text are revise § 250.732(b)(1)(iv) as follows: those task, BSEE will add that needed in response to this comment. ‘‘Ensures that the test demonstrates off- organization’s name to the BAVO list. The proposed language in center pipe shearing capability within

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the time period referenced in • Response: BSEE disagrees with the Comments Related to Proposed § 250.734(a)(16)(i).’’ comment that this paragraph is unclear § 250.732(c)(2)—Verification of BOP • Response: BSEE disagrees with the or confusing as written. BSEE also System Testing comment about the inconsistencies disagrees with the recommended Summary of Comments: One between the compliance timeframes for changes to this provision. The testing commenter suggested that the proposed the two referenced sections. The described in § 250.732(b)(2)(ii) is requirement in § 250.732(c)(2)—for requirement in § 250.734(a)(16) to center performed at a testing facility, while the verification that designs of the BOP the drill pipe while shearing is commenter’s suggested language system and individual components have important to help increase shearing apparently contemplates testing been proven in a testing process that capabilities and ensure effective conducted on a rig. shearing in an emergency. However, as demonstrates the equipment’s reliability discussed elsewhere, BSEE has Comments Related to Proposed in a way that is repeatable and determined that additional time is § 250.732(b)(3)—Calculations—MASP reproducible—be cross-referenced to needed for such technology to continue appropriate validation testing required to be developed, produced, acquired Summary of Comments: One in industry specifications (e.g., API comment was received from multiple Specs.16A/16C/16D). and installed, and thus proposed 7 years • as a reasonable time to comply with that commenters that the proposed Response: BSEE disagrees with the requirement. (See 80 FR 21510.) By requirement in § 250.732(b)(3) for commenter’s suggestion that we contrast, the technology to perform off- calculations include shearing and reference specific industry standards in center shearing is already in widespread sealing pressures that are corrected for § 250.732(c)(2). This paragraph is setting use, and there is no reason to postpone MASP should be revised. The comment general requirements and is intended to the adoption of the testing requirements stated that MASP/MAWHP should be be broad enough to allow for flexibility for that technology. limited to the RWP of the preventer in verifying the component designs above the uppermost shear ram, because without limitation to any specific Comments Related to Proposed it is not possible to have more than the existing standard(s). § 250.732(b)(1)(iii)—Shear Test RWP of the preventer above the shear Documentation Comments Related to Proposed ram. § 250.732(c)(4)—API Spec. Q1 Summary of Comments: Several • commenters stated that the requirement Response: BSEE disagrees with the Summary of Comments: One of § 250.732(b)(1)(iii)—for documenting commenter’s recommended revision. commenter suggested that quality that the shear testing provides a The requirements of § 250.732(b)(3) only control and assurance mechanisms reasonable representation of field apply to calculations identifying the referred to in § 250.732(c)(4) require applications—should be in accordance sealing pressure for all pipe to be used compliance with API Spec. Q1. with current industry standards only. in the well. The calculations are to be • Response: BSEE disagrees with the This includes shearing the drill pipe used to determine the applicability and commenter’s suggestion to reference with zero wellbore pressure and zero use of the shearing components; it is the specific industry standards in tension. The commenter asserted that operator’s responsibility to determine § 250.732(c)(4). This paragraph sets there is a safety risk when shearing a how the calculations are applied to the general requirements and is intended to drill pipe in the lab with high pressure specific components on the rig. be broad enough to allow for flexibility in the wellbore and flowing conditions. Therefore, no changes are necessary to in verifying that the fabrication, • Response: BSEE does not agree with this paragraph. manufacture and assembly of BOP the commenter that a change is components and the BOP system use Comments Related to Proposed necessary to § 250.732(b)(1)(iii). BSEE appropriate quality control and § 250.732(c)—Facility Access understands that the technological assurance mechanisms, without limiting capabilities of shear testing are limited; Summary of Comments: Multiple the choices of such mechanisms. however, BSEE also recognizes that commenters requested that BSEE revise Comments Related to Proposed advancements have been made to § 250.732(c) with regard to a BAVO § 250.732(c)(4)—Quality Control and improve testing capabilities to better having access to any facility associated Assurance simulate field applications. Therefore, with the BOP system during the review Summary of Comments: One industry BSEE has not made any changes to this process. The comments requested that commenter stated that the proposed paragraph. BSEE expects all shear BSEE change the wording of ‘‘access to requirement in § 250.732(c)(4) that testing to be done in a safe manner to any facility’’ to ‘‘access to quality assurance and control ensure personnel safety. documentation.’’ The comments mechanisms cover ‘‘all contractors, Comments Related to Proposed asserted that this provision was too subcontractors, distributors, and § 250.732(b)(2)(ii)—Pressure Integrity broad and implies that BAVOs have law suppliers at every stage’’ is overly broad Testing enforcement rights. and undefined. The commenter asserted Summary of Comments: Several • Response: BSEE disagrees. BAVOs that complying with such a broad commenters stated that the proposed must have access to the relevant requirement would take many years. requirement in § 250.732(b)(2)(ii) that facilities in order to perform the testing The commenter suggested that BSEE pressure integrity testing demonstrate and certification functions necessary to revise this provision to read: ‘‘The that the equipment will seal at the RWP ensure that BOPs function as intended quality control, assurance requirements of the BOP pressure, should be revised to prevent well-control events. There is and material documentation specified because it could create potential no basis for the suggestion that requiring by the industry standard(s) for the confusion. One commenter also said operators to provide facility access to components and systems.’’ that the test pressure should be MASP/ the BAVO—which the operator has • Response: BSEE does not agree. The MAWHP, or the RWP of the sealing retained to perform these functions on commenter provided no explanation or preventer above the uppermost shear its behalf—confers any law enforcement support for its opinion or its ram, whichever is lower. authority on the BAVO. recommended changes to the rule.

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Therefore, BSEE has no basis to adopt • Response: The proposed rule did • Response: BSEE does not agree with the commenter’s recommended change. not, and the final rule does not, state the recommended changes to the that an operator must provide training requirements for the alternative cutting Comments Related to Proposed to BOP personnel that meets OEM device specified in paragraph § 250.732(d)—MIA Report training recommendations or § 250.733(a)(1). This provision will be a Summary of comments: Multiple requirements that do not exist; nor does substantial improvement over the comments stated that the requirement in BSEE intend that provision to be current regulations, which do not proposed § 250.732(d) for an annual interpreted in that way. Accordingly, impose any requirements for cutting any MIA report for subsea BOPs, BOPs used BSEE has modified final § 250.732(d)(6) electric-, wire-, or slick-line. BSEE is in HPHT environments, and surface to clarify that training must include evaluating additional shearing rams for BOPs on floating facilities would be ‘‘any applicable’’ OEM requirements. surface BOPs and other advanced redundant and unnecessary and would technology that may be capable of What are the requirements for a surface not increase the safety or reliability of severing everything in the hole; BOP stack? (§ 250.733) BOP equipment. The comments asserted however, more research and data are that each item to be included in the MIA As provided for in the proposed rule, needed before BSEE decides whether report is already covered by the this section combines and revises technology such as that recommended operators’ SEMS plans, as required by several sections of the former by the commenter should be added to BSEE’s SEMS rules, or by operators’ regulations that established technical the rules. If research or study reports or compliance with API Standard 53 requirements for surface BOP stacks and other information becomes available to requirements. Commenters also noted related equipment. Paragraph (a) of this BSEE that warrants additional that the proposed rule requires section specifies the point at which the requirements, BSEE may propose such a adherence to OEM training surface BOP stack must be installed, sets revision in a future rulemaking. recommendations that do not exist. minimum requirements for numbers Comments Related to Proposed • Response: BSEE does not agree that and types of key surface stack § 250.733(a)—Prescriptiveness of the MIA reporting requirement is components and equipment (e.g., Requirements redundant or unnecessary. As remote-controlled BOPs that include Summary of comments: Two previously discussed, although some of annulars, blind shear rams, and pipe commenters claimed that the proposed the technical issues that must be rams), and specifies the shearing or requirements in § 250.733(a) would be covered in an MIA report under closing and sealing capabilities that too prescriptive; i.e., that ram § 250.732(d) are related to certain issues such equipment must have. If the blind placements and configurations should that must be addressed in SEMS plans, shear ram could not cut electric-, be established by the operator based on there are also many differences between wire-, or slick-lines under MASP an a risk assessment. the contents of the MIA reports and alternative cutting device must be on • Response: BSEE does not agree with SEMS plans. The primary purpose of the rig floor during operations that can the suggested changes to paragraph the MIA report is to provide BSEE with cut the wire before closing the BOP. § 250.733(a). This provision does not the technical information that BSEE Paragraph (b) sets additional specify where the rams are to be placed needs to carry out its responsibilities requirements and related compliance and how they should be configured. under OCSLA and part 250. By contrast, dates for surface BOPs on floating Moreover, this paragraph simply the purpose of the SEMS plans is to production facilities. Paragraphs (c) and restates the longstanding requirements help the OCS industry and workforce to (d) establish requirements for choke and of prior § 250.441(a), which describes build a stronger safety culture and to kill lines. BSEE has revised certain the type of BOP components that must improve safety and environmental provisions in proposed § 250.733 in the be in the BOP stack, but not how they performance through compliance with final rule as discussed in the comment must be configured. the policies and procedures in those responses for this section and in part plans. V.C of this document. Comments Related to Proposed Similarly, while there are some § 250.733(a)—Compliance Timing Comments Related to Proposed matters covered in an MIA report that § 250.733(a)—Risks of Manual Cutting Summary of comments: A commenter are also covered under API Standard 53, Device recommended that BSEE revise the there are significant differences and compliance dates for implementation of certain types of information required in Summary of comments: A commenter the requirements under paragraph (a), the MIA report are not covered by API was concerned that BSEE may have suggesting 3 years (rather than the Standard 53. underestimated the risks (of a fire or proposed 3 months) to comply and The comment that the proposed rule explosion) associated with using a recommending that an annual status would require compliance with non- separate manual cutting device as an report be submitted to BSEE until the rig existent OEM training recommendations alternative cutting device, under is in compliance. does not warrant any change to the final proposed § 250.733(a)(1), during an • Response: BSEE agrees that an regulation. It is already clear that emergency well-control situation where extension of the proposed 3-month § 250.732(d)(6) only requires hydrocarbon vapors may be present on (from publication of the final rule) compliance with any OEM training the rig floor. This commenter was also compliance date for § 250.733(a)(1) is requirements that actually exist. concerned that the speed and warranted for certain elements, although Summary of comments: Some effectiveness of closing-in a well would the 3 years recommended by the comments asserted that proposed be compromised by using a single blind commenter is unnecessary. As § 250.732(d)(6)—regarding verification shear ram and manual cutting device. previously discussed (see part III of this in the MIA report that training for BOP Thus, this commenter asked that BSEE preamble), BSEE is aware that some personnel meets OEM requirements— consider requiring a more robust, current technology is available to shear would require adherence to OEM automated redundant blind shear ram tubing with exterior control lines; training recommendations that do not closure system for all surface BOP accordingly, the effective date for exist. systems. shearing such tubing has been extended

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to 2 years (from publication of the final required that the ram be capable of Comments Related to Proposed rule) in order to allow operators to shearing any possible line. However, the § 250.733(a)—Pipe Rams and MASP acquire and install (and, if necessary, to proposed (and final) regulatory text Summary of comments: Another develop new or alternative) equipment simply refers to the electric-, wire-, or commenter recommended removing the to meet the requirements. However, the slick-line ‘‘that is in the hole,’’ not to requirement from § 250.733(a) that pipe commenter provided no support for hypothetical lines that are not in the rams must be able to close and seal modifying the compliance date for any hole. under MASP, since § 250.730(a) already other elements of § 250.733(a), nor is Comments Related to Proposed establishes that the BOP (including pipe BSEE aware of any basis for doing so. and variable bore rams) must have an Therefore, BSEE has not revised the § 250.733(a)(1)—Shear Rams RWP greater than MASP, and thus the compliance date for the remainder of Summary of comments: Another two provisions would effectively be § 250.733(a). commenter recommended adding redundant. Comments Related to Proposed language to paragraph § 250.733(a)(1) to • Response: BSEE is not revising § 250.733(a)(1)—Shearing Requirements the effect that if the BOP stack has dual paragraph (a) as the commenter Summary of comments: Commenters shear rams, and the lower shear ram can suggested. The capability of pipe rams asked BSEE to confirm that it intended shear all drill pipe, then the upper shear to close and seal under MASP is to propose the exclusions from the blind ram only needs to seal against MASP, important because the MASP predicts shear ram shearing requirements in not to exceed the RWP of the preventer the highest pressure to be encountered proposed § 250.733(a)(1) for ‘‘tool joints, located directly above the shear ram. at the surface of the well and is used in bottom hole tools, and bottom hole • Response: BSEE does not agree with ensuring that BOPs can function as assemblies that include heavy-weight adding the language the commenter intended. Although § 250.730(a)(3) pipe or collars.’’ Although excluded in suggested. Since § 250.733(a)(1) does establishes essentially the same the regulatory text, the exclusions were not require dual shear rams to be used requirement for all BOPs, reiterating the not discussed in the preamble to the in a surface BOP stack, the commenter’s requirement in § 250.733(a)(2) for proposed rule. suggested language appears to involve a surface BOPs emphasizes the • Response: BSEE understands that hypothetical scenario outside the scope importance of this capability without there is no such technology currently of the rule. imposing any additional burden on the available that can shear such operator. equipment. Additionally, if all of the Comments Related to Proposed § 250.733(a)(2)—Exterior Control Lines Comments Related to Proposed shearing capability requirements of this § 250.733(b)—Surface Dual Shear Rams rule are met, there is no need for the Summary of comments: Commenters equipment to be able to shear Summary of comments: Several recommended adding more exclusions commenters asserted that BSEE should equipment at the bottom of the hole. to the proposed requirement that the Accordingly, the proposed and final not require dual shear rams on surface pipe rams be able to close and seal on BOPs on any floating production regulatory text for paragraph (a)(1) the tubular body of any drill pipe, correctly excluded shearing facility. Other commenters requested workstring, and tubing under MASP. that BSEE conduct a full risk assessment requirements for tool joints, bottom hole Specifically, the commenters asked that tools, and bottom hole assemblies that of the impact of such a dual shear ram BSEE exclude pipe bodies with exterior requirement before making it part of a include heavy-weight pipe or collars control lines. Commenters emphasized from shearing requirements was final rule. They asserted that the that closing a ram preventer on tubing negative consequences (related to intended and was correctly included in and exterior control lines (e.g., flat the proposed rule, as well as in the final weight, height and other structural packs) is not currently achievable, nor is limits on the facility) of adding such rule. The omission of any discussion of it a realistic expectation for the near those exclusions in the preamble capabilities might increase rather than future. The commenters claimed that reduce risks. description of proposed § 250.733(a)(1) since it is not possible to comply with was inadvertent. Other comments stated that the rule is this provision, the industry would be not clear about the requirements for Comments Related to Proposed shut down in the Gulf of Mexico. existing floating production facilities § 250.733(a)(1)—Shearing Under MASP Commenters suggested use of a risk with surface BOP stacks. Some Summary of comments: A commenter assessment to identify additional recommended that BSEE allow was concerned about the proposed mitigation measures or requiring the ‘‘grandfathering’’ for existing and under- requirement that if the blind shear rams shear ram to be able to shear and seal construction facilities, since the are unable to cut ‘‘any electric-, wire-, the tubular with the items attached to proposed requirements could create or slick-line under MASP,’’ an the outside of the pipe. feasibility issues or additional costs that alternative cutting device must be used. • Response: As previously discussed, could make continued activity on such The commenter asserted that the word BSEE agrees that pipe rams currently rigs economically unviable. Some ‘‘any’’ in that context is open-ended. cannot completely seal around tubing commenters also recommended that The commenter suggested that the with exterior control lines. An annular BSEE allow operators to submit a risk operator should be able to demonstrate is the only BOP component able to seal assessment for each existing floating that its blind shear rams can cut the around tubing with exterior control facility to determine whether the facility lines intended for use rather than ‘‘any’’ lines and is only used for a low pressure needs dual shear rams to reduce risk possible lines. situation, which is usually the case and allow those facilities to ‘‘opt-out’’ of • Response: BSEE does not agree with when running tubing with exterior the requirement (as provided in API the commenter’s apparent concern control lines. Accordingly, BSEE has Standard 53). about paragraph § 250.733(a)(1). The revised final paragraph (a)(2) to clarify • Response: BSEE disagrees with the commenter did not fully explain its that pipe rams are not required to seal suggestions that the dual shear ram concerns, but BSEE assumes the tubing with exterior control lines and requirement for surface BOPs on commenter believed the provision flat packs. floating production facilities be

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eliminated from the final rule after the rule is published.19 This 3-year configuration’’ to better align with the altogether. As indicated in the proposed compliance period will give the terminology used in industry. rule, § 250.733(b) is consistent with industry adequate time to plan, design, • Response: BSEE does not agree that BSEE policy that surface BOPs on and develop surface BOP equipment it is necessary to revise the dual bore floating production facilities (like that can meet the dual shear ram riser requirements in paragraph subsea BOPs) generally present higher requirement on new floating production § 250.733(b)(2). The commenters’ risks than surface BOPs on fixed facilities. concerns apparently are based on the facilities. (See 80 FR 21522.) In Final § 250.733(b)(1) reasonably misinterpretation that BSEE intended to addition, BSEE believes that overall balances the practical concerns related require that all single bore risers be performance of shearing equipment to requiring dual shear rams on BOPs at converted to a dual bore riser must improve over the longer term to existing floating facilities, or those to be configuration. That was not BSEE’s ensure that the equipment can constructed in the near-term, with the intention, as is evident from a careful successfully shear a drill stem in an importance of improving the reading of the proposed rule. The emergency. (See 80 FR 21509.) BSEE capabilities of surface BOPs on such language in proposed, and now final, also believes that the industry is already facilities in the longer term. In fact, § 250.733(b)(1) applies only to risers moving toward eventual use of dual existing floating production facilities installed after the effective date of the shear rams in surface BOPs on new generally are less likely to have an event final rule (i.e., 90 days from the date the floating production facilities. requiring a dual shear ram BOP, given final rule is published). If any operator For the same reasons, BSEE disagrees that the majority of such facilities are already has existing plans to install a with the recommendation that BSEE do located in depleted fields, with lower single bore riser after the final rule takes a risk assessment to justify the dual pressures due to ongoing production effect, the operator should contact BSEE shear ram requirement or allow from those fields.20 and, if necessary, may request approval operators with surface BOPs on floating for alternative compliance under facilities to opt-out of the requirement if Comments Related to Proposed § 250.141. they perform a risk assessment. BSEE § 250.733(b)(2)—Dual Bore Risers BSEE also has not made the requested change from ‘‘dual bore riser’’ to ‘‘dual already addressed the latter suggestion Summary of comments: Comments on casing’’ since ‘‘dual bore riser’’ is an in the proposed rule in connection with § 250.733(b)(2) focused on the meaning established and well-understood the dual shear ram requirement for of the proposed requirement for dual industry term. subsea BOPs, and stated that an operator bore risers on existing facilities. whose circumstances make the dual Commenters requested clarification that Comments Related to Proposed shear ram requirement infeasible can existing facilities currently using single § 250.733(b)(2)—Most Extreme seek approval for alternative equipment bore strings may continue to do so. They Conditions or procedures under current § 250.141. noted that there are currently many (See 80 FR 21509–21510.) Summary of comments: Another single bore risers being used commenter recommendation was to However, BSEE understands several successfully on existing facilities, which of the practical concerns related to change the requirement to design for the should not be required to install new ‘‘most extreme’’ conditions to a applying the dual shear ram dual bore riser systems. Some requirement to existing facilities. For requirement to design for ‘‘anticipated’’ commenters argued that this would operating and environmental example, BSEE agrees that the dual present significant feasibility issues, shear ram requirement, if applied to conditions. A commenter also requested with substantial economic that BSEE clarify that monitoring of the existing floating production facilities, or consequences, but without significant facilities under construction or in annulus between the risers means safety benefits. A commenter also monitoring for pressure during advanced stages of development, suggested that there are other safety potentially could have negative operations. precautions (such as dual barriers) that • Response: BSEE agrees with this personnel safety and structural impacts can improve safety without converting comment and has revised due to the added weight of the dual single bore risers to dual bore. In § 250.733(b)(2) by removing the term shear ram equipment and to the height addition, some comments recommended ‘‘most extreme’’ and replacing it with and structural limits of those facilities. changing the terminology from ‘‘dual ‘‘maximum anticipated,’’ and added to Accordingly, BSEE has revised final bore riser configuration’’ to ‘‘dual casing paragraph § 250.733(b)(2)(i) that the paragraph (b)(1) to apply the dual shear riser must be monitored for pressure ram requirements to surface BOPs that 19 The requirement that surface BOPs installed 3 during operations. are ‘‘installed’’ on floating facilities 3 or more years after publication of the final rule years after publication of the final must comply with the requirements of Comments Related to Proposed rule.18 In effect, this means that surface § 250.734(a)(1) does not extend the 5-year § 250.733(c)—Side Outlet Valves BOPs on floating production facilities compliance date for dual shear rams as specified in § 250.734(a)(1). Specifically, any surface BOP Summary of comments: A commenter that exist now, or facilities that are installed between 3 years and 5 years after recommended deleting the proposed installed on the OCS in the near-term, publication of the final rule must comply with the requirement for side outlet valves to dual shear ram requirement no later than 5 years will not need to meet the dual shear ram hold pressure in both directions, stating requirement unless those BOPs are after publication of the final rule; any surface BOP installed 5 or more years after publication of the that there is no scenario under which removed or replaced 3 or more years final rule must comply with the dual shear ram these valves would see pressure in a requirement when the surface BOP is installed. surface application. The commenter 18 The revised language of final § 250.733(b)(1) 20 In addition, there are large amounts of offset also clarifies that existing floating production well data for those existing facilities in depleted asserted that this requirement for two- facilities do not need to retrofit or replace their fields (due to the multiple wells previously drilled way valves should only apply to subsea BOPs in order to meet the dual shear requirement into the same geologic formations and reservoirs), BOPs and recommended that BSEE in 5 years, as the proposed language might have which allows for better prediction of drilling should revise the text for surface BOPs implied by its cross-reference to the dual shear ram parameters. Similarly, because of the prior requirement for subsea BOPs in proposed production of the reservoirs at such facilities, the to only require that side outlet valves be § 250.734(a)(1), which included a 5-year reservoir parameters and characteristics are able to hold pressure from the direction compliance date for those subsea BOPs. generally well established. of flow.

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• Response: BSEE does not agree with Commenters stated that, depending on equipment and capabilities. Paragraph these comments. BSEE understands that the timing of the requirement, (b) establishes procedural and testing side outlet valves are already in use and manufacturing, delivery, and requirements for resuming operations on surface BOPs are normally designed installation of this equipment could after operations are suspended to make to hold pressure from both directions. lead to downtime for drilling rigs with repairs to the subsea BOP system. Thus, there is no factual basis to revise surface BOPs. Commenters stated Paragraph (c) sets out APD requirements this provision. further that OEMs would not have the related to drilling a new well with a inventory on shelves to fulfill orders subsea BOP. BSEE has revised certain Comments Related to Proposed within 90 days. provisions in proposed § 250.734 in the § 250.733(d)—Remote-Controlled Valve Some commenters suggested an final rule as discussed in the comment Summary of comments: A commenter effective date 3 years after publication of responses for this section and in parts emphasized that, in an emergency case, the final rule, while others suggested V.B.2, V.B.5, and V.C of this document. a remote-controlled valve on a kill-line that 5 years would provide enough time is easier and faster to access and to design and manufacture any new Comments Related to Proposed operate. The commenter recommended components, procure and install, and § 250.734—Risk-Based Approach that BSEE require that the valve on such obtain testing and verification by a Summary of comments: Commenters lines be capable of both remote and BAVO. One commenter suggested that, stated that proposed § 250.734 uses manual operation if power for a if BSEE extends the compliance date, it overly prescriptive language, similar to remotely operated valve is not available, could require an annual status report to the language used in the proposed BOP instead of the proposed language BSEE until rigs are in compliance. surface stack requirements. They also allowing the operator to use either a • Response: BSEE has deleted asserted that the proposed rule would manual valve or remotely controlled proposed § 250.733(e) from the final increase the minimum equipment valve. rule, since final § 250.735(g) adequately requirements beyond API Standard 53 • Response: BSEE disagrees with the addresses the locking requirements for and seek to introduce one-size-fits-all suggested change. Due to the functions surface BOPs, and the circumstances configurations. Commenters suggested and intended use of the kill line, remote covered by proposed § 250.733(e) do not re-writing the proposed rules with a operation is not necessary, although the warrant an additional requirement at risk-based approach that would enable operator has the option to use both this time. As described later in this BSEE to create a set of rules that could manual and remote operated valves. document, BSEE has also revised final meet the desired intent without creating Comments Related to Proposed § 250.735(g) based on comments a number of unintended side effects. § 250.733(e)—Hydraulically Operated concerning both proposed § 250.733(e) They assert that a risk-based approach Locks and proposed § 250.735(g). would also be more suited to the constant evolution of drilling processes Summary of comments: Commenters Comments Related to Proposed and would encourage technological raised several concerns about the § 250.733(f)—BOP Repair Certification innovation and efficiency. proposed requirement to install Summary of comments: One • Response: BSEE recognizes the hydraulically operated locks on surface commenter objected to the proposed advantages and disadvantages of both BOP stacks. Some commenters requirement that a BAVO certify that it approaches and understands that each suggested deleting the requirement has reviewed repairs to a surface BOP in approach can be effective and altogether; others suggested only an HPHT environment and that the BOP appropriate for specific circumstances. requiring hydraulic locks on all surface is fit for service, pointing out that this As explained in the proposed rule, this BOPs on HPHT wells. Commenters provision is redundant with proposed rulemaking uses a hybrid approach asserted that this technology is not § 250.738(b). Other commenters raised incorporating prescriptive requirements, available for a majority of surface BOP other concerns with, and requested where necessary, as well as many systems and that there is no technical other changes to, proposed § 250.733(f), performance-based requirements. (See, basis to require hydraulically operated including claiming that the proposed e.g., 80 FR 21509.) BSEE believes that locks on all surface BOPs. Commenters regulation inappropriately places the this provision, as promulgated in the suggested, as an alternative, revising the primary responsibility for verifying final rule, strikes the appropriate requirement to ensure that BOP ram repairs on the BAVOs, instead of the balance between prescriptive and locks are in working order and operator. performance-based requirements. The accessible. Some commenters asserted • Response: BSEE agrees that final provision is intended to ensure that, while hydraulically operated locks proposed § 250.733(f) would be that subsea BOP systems include, at a remove the operator from the vicinity, redundant with § 250.738(b); therefore, minimum, certain types of components and thus may provide more protection BSEE has deleted paragraph (f) from and processes that, based on BSEE’s for some rig personnel than manually § 250.733 in the final rule. experience and analyses of past operated locks, they are not as reliable incidents, will help prevent future as manual locks, which are simpler in What are the requirements for a subsea blowouts. However, § 250.734(a) does design. BOP system? (§ 250.734) not mandate a one-size-fits-all approach. Commenters also pointed out that, in As described in the proposed rule, To the contrary, the final rule allows a catastrophic well-control incident, the this section combines and revises operators to exceed the prescribed ability to charge or recharge the provisions of former sections that requirements (e.g., to use more than the hydraulic closing unit may be lost. In established requirements for subsea required 5 remotely-controlled, addition, commenters also raised BOP systems. Paragraph (a) requires hydraulically operated BOPs) if the concerns regarding the timing and costs dual shear rams and specifies the operators wish to do so. Nor does this related to the proposed requirement, shearing requirements as well as provision mandate the use of any stating that compliance within 3 months requirements for the BOP control manufacturer’s equipment or otherwise would not be achievable for rigs that do system, subsea accumulator capacity, discourage the development of new and not already have hydraulically operated ROV intervention capabilities, better technology that will meet or locks and the necessary control systems. personnel training, and certain BOP exceed the requirements of the rule.

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BSEE expects equipment manufacturers, lack of technology needed for shearing stressed that given the importance of operators and others to continue flat packs, slick-line, and other exterior dual blind shear rams to offshore exploring and developing new, more control lines; procurement of additional drilling safety, all current and future efficient ways to meet these accumulators needed for the closure of blowout preventers should be equipped requirements. dual shear rams; installation of ram with these devices, and BSEE should position indicators; and pipe centering reduce the time required for compliance Comments Related to Proposed capabilities. Although many with this provision. § 250.734(a)—Device Connections commenters suggested that a 5-year • Response: As provided in the Summary of comments: A commenter implementation timeframe would be proposed rule (see 80 FR 21509–21510), asserted that the table in § 250.734(a)— acceptable, others suggested longer BSEE agrees that the dual shear ram listing requirements for operating with a timeframes for certain provisions. requirements are important to subsea BOP—does not address • Response: BSEE agrees that there improving safety and environmental connections between devices in the BOP are some provisions in § 250.734(a), and protection, consistent with stack, or methodologies for other sections of this rule, for which recommendations arising from the disconnection and/or reassembly or operators will need more time for Deepwater Horizon incident. However, capping or containment points on those compliance than proposed. the existing regulations did not require devices. The commenter stated that Accordingly, the final rule extends the dual shear rams. BSEE believes that BSEE must address points of connection compliance dates for specific operators generally follow API Standard between the devices and capping and requirements under paragraph (a)(1) as 53 regarding when dual shear rams containment points to reduce the well as for the specific requirements should be used, based on the BOP uncertainty of the procedures used in under paragraphs (a)(1)(ii), (a)(3)(iii), classification. BSEE is aware that not all the event of failure. The commenter (a)(15), and (a)(16)(i). More detailed subsea BOPs have dual shear rams yet, recommended that BSEE include a new discussion of the extended compliance and that acquiring and installing such section describing equipment and/or timeframes is provided in part III of this equipment presents significant devices used to connect each preamble. practical, technical and economic challenges. Accordingly, as discussed component in the BOP stack, and a Comments Related to Proposed previously in the proposed rule (see 80 separate section describing capping and § 250.734(a)—Surface Casing Setting FR 21511) and this document, BSEE containment points and methods at all Point such locations on the BOP stack. determined that 5 years is an • Response: BSEE disagrees with the Summary of comments: A commenter appropriate timeframe for operators to commenter that capping or containment stated that proposed § 250.734(a) was obtain and install the necessary points should be included in this unclear as to what conditions would equipment for all subsea BOPs. section and has not made the suggested lead the District Manager to require an operator to install a subsea BOP before Comments Related to Proposed changes to paragraph (a). Containment § 250.734(a)(1)—Dual Shear Rams requirements are covered adequately reaching the surface casing setting under proposed and final § 250.462. point. This commenter asserted that Summary of comments: Commenters prematurely installing a subsea BOP and raised various concerns about the Comments Related to Proposed shutting in on a kick before installation proposed requirement for dual shear § 250.734(a)—MASP of surface casing would increase the risk rams and the placement of BOPs. A Summary of comments: Some of broaching to the seafloor. commenter stressed that OEM commenters questioned BSEE’s use of • Response: BSEE clarified final equipment limitations restrict shear and MASP in this section, asserting that § 250.734(a) by stating that the subsea seal capability of blind shear rams, and MASP is not the appropriate industry BOP system must be installed before suggested that the regulations follow term for subsea BOPs. They conducting operations if the well is section 7.6.11.7.11 of API Standard 53, recommended using MAWHP, as already deepened beyond the surface which states that ‘‘[i]f a single ram is defined in API RP 96 and API Standard casing setting point. Other situations incapable of both shearing and sealing 53. that might require installation of the the drill pipe or tubing in use, the • Response: As previously explained BOP below the conductor casing will be emergency and secondary systems shall in connection with similar comments on decided on a case-by-case basis by the be capable of closing two rams; one that § 250.730, MASP must be defined for District Manager. It would be premature will shear and one that will seal the specific operation, and for a subsea to speculate on specific circumstances wellbore pressure.’’ BOP, the MASP must be taken at the that would warrant such a decision, but • Response: BSEE does not believe mudline, as explained in § 250.730(a). the District Manager would certainly that one shear ram can ensure the ability For subsea BOPs, MASP taken at the take into account whether installation of of a subsea BOP to shear a drill string mudline is the same as MAWHP. BSEE the BOP is likely to cause a broach or in the event of a potential emergency. uses the term MASP in its existing other increased hazard. If an operator The various investigations of the regulations and disagrees with the has any concerns or questions about a Deepwater Horizon incident suggestion that it would cause specific factual scenario, it may contact recommended increasing the shearing confusion in this context. the appropriate District Manager for capabilities of the BOP, including the assistance. use of dual shear rams on subsea BOPs. Comments Related to Proposed BSEE determined that use of dual shear § 250.734(a)—Compliance Timing Comments Related to Proposed rams would increase the likelihood that Summary of comments: Multiple § 250.734(a)(1)—Compliance Timing a drill string can be sheared, and commenters expressed concerns about Summary of comments: A commenter ensures the well can be shut in and the compliance dates associated with observed that while BSEE proposed secured, by requiring that a shearable this section and provided examples of requiring a second blind shear ram for component is opposite a shear ram. why an extended compliance date is some BOPs, the rule would also allow BSEE also determined that merely necessary. The aspects of the provisions 5 years for operators to implement this requiring compliance with API Standard that were of most concern included the critical safeguard. Another commenter 53, which includes a procedure for

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‘‘opting-out’’ of the dual shear ram after shearing with non-sealing shear to ‘‘[h]ave a fully redundant subsea provision, cannot provide the same rams. The pipe can fall in the hole if not control system to ensure proper and level of assurance. (See 80 FR 21510– hung off, or the pipe can be lifted independent operation of the BOP 21511.) If there are unique clearing the upper sealing ram. system.’’ circumstances that prevent the use of Accordingly, BSEE has revised final • Response: BSEE agrees with the dual shear rams, operators would be paragraph (a)(1)(ii) to read ‘‘[a]ny non- comments suggesting that the proposed able to apply for the use of alternative sealing shear ram(s) must be installed requirement for dual-pod controls could procedures or equipment under existing below a sealing shear ram(s).’’ have proven unduly restrictive, and that § 250.141. However, BSEE is not requiring a risk requiring redundant pod controls would assessment by the operator as the provide more flexibility and room for Comments Related to Proposed method for determining the order of the improvement while providing at least as § 250.734(a)(1)—Existing Wells minimum requirements for one blind much protection as the proposed Summary of comments: A commenter shear ram and one shear ram. If multiple language. Accordingly, BSEE has remarked that the requirements in this redundant shearing rams are included, revised final § 250.734(a)(2) by replacing section are reasonable for new wells, but BSEE recommends a risk assessment, ‘‘dual pod control system’’ with that it may be appropriate to allow but one is not required. If there are ‘‘redundant pod control system.’’ This 4-ram BOPs on some existing wells with unique circumstances that indicate that change will also align the pod older wellheads. The commenter also some configuration other than those requirement in the regulations with the said that the use of heavier/taller BOP specified in this paragraph may be language of API Standard 53. stacks may potentially induce higher warranted, operators would be able to Comments Related to Proposed bending moments on the wellhead and apply for the use of alternative § 250.734(a)(3)—Fast Closure of BOP BOP stack that will reduce the overall procedures or equipment under existing Components safety provided by the BOP. § 250.141. • Response: BSEE disagrees with the Summary of comments: Commenters comment about allowing a 4-ram BOP Comments Related to Proposed asked BSEE to clarify the requirements on existing wells with older wellheads. § 250.734(a)(1)(i)—Exterior Control under proposed paragraph BSEE determined that a 5-ram BOP is Lines § 250.734(a)(3), related to ‘‘fast closure appropriate due to the high potential of Summary of comments: Some of the BOP components’’ and ‘‘operate a significant well-control event, commenters recommended adding an all critical functions.’’ They indicated including at facilities with older exclusion from the pipe ram sealing that BSEE did not define the terms ‘‘fast wellheads. However, if there are unique requirement in paragraph (a)(1)(i) for closure’’ and ‘‘critical functions’’ in the circumstances (such as a concern with sealing on pipe with exterior control rule, noting that these terms are defined potentially higher bending moments on lines and umbilicals attached. in API Standard 53. some older wellheads) that might • Response: As discussed previously • Response: Although the API warrant the use of a 4-ram BOP for a in this document, BSEE agrees with the Standard 53 definition of ‘‘fast closure’’ specific well, operators would be able to comment about pipe rams not being able is one appropriate way to understand apply for the use of alternative to seal around tubing with exterior this term, it is not the only possible procedures or equipment under existing control lines and flat packs. An annular appropriate way. Thus, BSEE does not § 250.141. is the only BOP component able to seal believe it is necessary to limit the around tubing with exterior control meaning of ‘‘fast closure’’ in the Comments Related to Proposed lines and an annular is usually used for regulations to the API Standard 53 § 250.734(a)(1)—Shear Ram Placement a low pressure situation, which is definition. However, BSEE agrees with Summary of comments: Commenters usually the case when running tubing the commenter about the possibility of asserted that the proposed requirement with exterior control lines. Thus, BSEE confusion and the need to define for the placement of non-sealing shear revised paragraph (a)(1)(i) in the final ‘‘critical functions.’’ Accordingly, BSEE rams below the sealing shear rams rule to exclude tubing with exterior revised final § 250.734(a)(3)(i) to specify conflicts with API Standard 53. Some control lines and flat packs from the that the critical functions are to comments suggested that BSEE revise pipe ram sealing requirement, but ‘‘[o]perate each required shear ram, ram paragraph (a)(1) to provide that any non- requiring that (within 2 years) the shear locks, one pipe ram, and disconnect the sealing shear ram must be installed rams be able to cut and seal the tubing LMRP.’’ These critical functions are the below at least one sealing shear ram. with exterior control lines in the hole. same as those defined in API Standard Others recommended that the operators 53. use a documented risk assessment to Comments Related to Proposed establish the fixed ram configuration as § 250.734(a)(2)—Dual-Pod Control Comments Related to Proposed provided by API Standard 53. A System § 250.734(a)(3)(i)—Subsea Accumulator commenter noted that there are rigs Summary of comments: Commenters Capacity where 3 shear rams with casing shears stated that the proposed rule Summary of comments: Commenters are installed between two blind shear prescriptively dictates that all subsea also questioned the proposed rams and in many instances the casing BOPs must have a dual-pod control requirement in § 250.734(a)(3)(i) for shear in the middle is the best system. They asserted that API Standard additional subsea accumulator capacity configuration. Another commenter 53 adequately addresses redundancy of in case of the loss of power fluid noted that it may be preferable to have these systems without requiring all connection to the surface. They a casing shear ram in between two sets subsea BOPs to have dual-pod controls. emphasized that if there is a loss of the of blind shear rams. A commenter also asserted that this power fluid connection to the surface, • Response: BSEE agrees with the provision would tie the industry to the then there also will probably be a loss commenter about requiring that any prescribed current methodology without of control from the surface. In that case, non-sealing shear ram must be installed room to change or improve, and there would be no logical reason to below at least one sealing ram. This suggested that BSEE revise require accumulator capacity to operate provides flexibility for sealing the well § 250.734(a)(2) to require subsea BOPs all choke and kill outlet valves.

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• Response: BSEE agrees with the dedicated to, but may be shared capable of receiving the fluid from the comment and has removed the reference between, autoshear and deadman accumulator, but BSEE is not restricting to choke and kill side outlet valves, functions. The final rule does not the use of other options, such as sand replacing it with a reference to ram require dedicated capacity for the EDS. units. The rule simply requires that the locks, in final § 250.734(a)(3). This These clarifications would eliminate subsea BOP have the capability of change is also consistent with the most of the concerns about having to delivering the fluid to each ROV operations of critical functions. locate additional bottles subsea. BSEE function. also agrees that the proposed timeframe Comments Related to Proposed for compliance would be inadequate, Comments Related to Proposed § 250.734(a)(3)(iii)—Dedicated even for the revised subsea accumulator § 250.734(a)(4)—ROV Intervention Independent Accumulator Bottles requirements, given the need to design, Capability Summary of comments: Commenters develop, and implement solutions to the Summary of comments: Commenters requested clarification of the intent and potential structural and engineering raised several concerns with the scope of the requirement in proposed problems associated with acquiring, proposed requirement that subsea BOPs § 250.734(a)(3)(iii) for ‘‘dedicated storing, and installing new accumulator independent’’ accumulator bottles, bottles and related equipment. must have ROV intervention capability. located subsea for the autoshear, Accordingly, after review of the Some commenters emphasized that the deadman, and EDS systems. comments, BSEE has revised the primary purpose of ROV intervention Commenters asserted that this is a major compliance date for the accumulator capability (hot stab) should be to secure deviation from API Spec. 16D and API requirements in paragraph (a)(3)(iii) to 5 the well and unlatch the LMRP, if Standard 53, which allow surface years after publication of the final rule, required. The commenters claimed that accumulator bottles to contribute to the as suggested by several commenters. the proposed new requirements for EDS sequence. Complying with the This change also corresponds to the ROVs will require considerably more proposed requirement would mean proposed (now final) 5-year compliance ROV panels and functions. This will locating additional accumulator bottles date for the final dual shear ram add leak points and test points, thus on the subsea BOP stack, which requirements, which likely would be the reducing the overall reliability of the commenters stated would pose practical first time that the new subsea system, reducing the availability of ROV and technical concerns due to inherent accumulator requirements would be access, reducing access for maintenance space limitations for subsea BOP needed in the event of an emergency. activities on the stack, and increasing systems, and could also exceed the Thus, extending the compliance date for the complexity of the BOP system. The capacities of the BOP crane, BOP frame, § 250.734(a)(3)(iii) would not adversely commenters asserted that this will lead rig substructure, and BOP carts. Also, affect safety or the environment to increased maintenance costs. They commenters asserted that more subsea compared to the proposed rule. For a also indicated that it will result in extra accumulator bottles could both impede more detailed discussion of the time and safety risks for ROV operators the ROV from seeing areas of the stack accumulator revisions, see part V.B.2 of (i.e., from firing the wrong function due critical to troubleshooting during this document. to the increased number of ROV abnormal situations and create functions). Commenters also asserted Comments Related to Proposed additional leak paths. In addition, that, due to likely equipment delivery § 250.734(a)(3)(ii)—Subsea Accumulator commenters noted that the extra delays, implementation of this Capability accumulator bottles would have to be regulation would require extended removed each time the BOP is serviced, Summary of comments: Commenters periods of downtime for operating rigs. increasing safety risks from handling the requested clarification of the Commenters noted that this paragraph bottles. As an alternative to the requirement in proposed exceeds the critical functions provisions proposed requirement, commenters § 250.734(a)(3)(ii) for subsea in API Standard 53. These commenters suggested that BSEE require one subsea accumulator capability to deliver fluid recommended that BSEE revise this accumulator bank, to be shared by to each ROV function. A commenter provision to refer to API Standard 53 for autoshear, deadman, EDS, acoustic and recommended that BSEE allow defining critical functions for ROV other critical functions, as provided by alternative options, such as independent capabilities. API Standard 53. accumulator bottles to supply the • Commenters also expressed concerns hydraulic power. Commenters noted Response: BSEE agrees with the about the proposed timeframe (3 months that these systems can be used in comment that the proposed rule would from publication of the final rule) for conjunction with the ROV flying leads. require adding significant new ROV complying with the new accumulator Commenters also suggested that, instead functions, and that API Standard 53 requirements, given design and of being required for ROVs, the primary provides an appropriate description of engineering issues and potential purpose of subsea accumulator bottles critical ROV functions (such as opening problems with acquiring and installing should be to deliver fluid under and closing each shear ram, and LMRP sufficient accumulator bottles and pressure to provide fast closure of the disconnect). Limiting the number of related equipment. Most of those components in an emergency situation. functions required for the ROVs will commenters stated that 5 years would Also, commenters asserted that ROVs significantly decrease the possibility of be an appropriate timeframe for themselves should be able to recharge creating new leak paths, help reduce overcoming those problems. the bottles to perform other functions if complexity of the BOP system, and • Response: BSEE agrees with many necessary. minimize any rig downtime for of the commenters’ concerns, and has • Response: BSEE does not agree that equipment changes. Accordingly, BSEE revised final § 250.734(a)(3) to clarify the suggested changes to revised final § 250.734(a)(4) to limit the that subsea BOP accumulators must § 250.734(a)(3)(ii) are necessary. This ROV functions to the critical functions have enough capacity to provide provision does not specify or limit the which are now specified in that pressure for critical functions, as methods or devices that could be used paragraph, and which is consistent with specified in final § 250.734(a)(3)(i), and to provide the necessary fluid to each the definition of critical functions in must have accumulator bottles that are ROV function. The ROVs must be API Standard 53.

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Comments Related to Proposed proposed requirement that the ROV However, another commenter supported § 250.734(a)(5)—ROV Crew Training crew must ‘‘examine all ROV related the proposed requirement to close a Summary of comments: A commenter well-control equipment’’ to requiring minimum of two shear rams, one of requested that BSEE clarify whether the that the ROV crew ‘‘must be familiar which must seal the well, stating that it proposed requirement for maintaining with all ROV related equipment’’; will increase the availability of all the revising the requirement that the ‘‘ROV ROVs and having a trained ROV crew emergency BOP functions. Another crew must be in communication with on each rig is intended to impose commenter also supported the proposed designated rig personnel’’ to the ‘‘ROV requirements over and above those of requirement and stated that the crew must be able to be in constant the existing requirements of subparts O sequencing will help ensure that at least communication with designated rig and S of part 250. one of the shear rams will seal. personnel’’; and changing ‘‘shutting in • Response: The personnel training the well during emergency operations’’ • Response: BSEE disagrees with the requirements of § 250.734(a)(5), which to ‘‘carrying out appropriate tasks comment about removing the include applicable training during emergency operations.’’ requirement that each emergency requirements for subparts O and S, • Response: BSEE agrees with the function must close two shear rams. The apply to the ROV crew training required comment suggesting that the phrase autoshear/deadman systems are used as by § 250.734(a)(5). Section 250.734(a)(5) ‘‘shutting in the well during emergency a ‘‘last case’’ scenario to operate specific potentially goes go beyond subpart O, operations’’ be changed to ‘‘carrying out BOP components, are not performed by however, in that it also requires that appropriate tasks during emergency rig personnel, and are set to activate personnel authorized to operate an ROV operations,’’ and made that revision in must have a comprehensive knowledge independently under certain operating the final rule. This will ensure that the criteria. BSEE is requiring both shear of BOP hardware and control systems. ROV crew is able to conduct many The training provisions for SEMS under rams to close for these emergency different tasks, instead of just shutting functions in order to increase the § 250.1915 require operators to establish in the well, during emergency effectiveness of those emergency BOP a training program so that all personnel operations. The other suggested changes systems. are trained in accordance with their would not substantively change or duties and responsibilities to work improve the requirements for ROV crew Comments Related to Proposed safely and are aware of potential capabilities. § 250.734(a)(6)(iv)—Emergency environmental impacts. This provision Functions sets out specific training requirements Comments Related to Proposed § 250.734(a)(6)(iv)—Emergency for the ROV crew. There are no Summary of comments: Commenters Functions inconsistencies between § 250.734(a)(5) stressed that requiring that each and subparts O and S. Accordingly, Summary of comments: Commenters emergency system must always close BSEE made no changes to the final rule suggested that the emergency functions dual shear rams in sequence will reduce based on this comment. requirement in proposed the operating capability of the rigs due § 250.734(a)(6)(iv) should be operations- Comments Related to Proposed to the reduced operating radii induced specific and not a blanket order to close § 250.734(a)(5)—ROV Crew Training by such a rule. They stated that the both casing shear and blind shear rams purpose of the EDS is to release the Summary of comments: While several in all situations. Some commenters vessel from the well to save lives; if this commenters supported the proposed recommended using an operational risk requirements for maintaining an ROV assessment to determine the optimum can be done without polluting, that is a and training the ROV crew, some emergency sequence for the specific bonus, but the focus is on saving lives recommended that training of ROV operation, stating that the sequential first. Commenters asserted that the pilots on stabbing into an ROV shearing requirement is too prescriptive operations at the time, together with the intervention panel should not be limited and the prescribed method in the weather conditions, etc., should dictate to simulators, as suggested by the proposed rule may not be the safest what EDS sequence is used, not a proposed rule; real-world, on-the-job approach. prescriptive rule. • training is also valuable. Thus, one Response: BSEE does not agree that • Response: BSEE agrees that the commenter also suggested changing any changes to § 250.734(a)(6)(iv) are primary focus of the EDS, and many ‘‘simulator training’’ to ‘‘competence needed based on this comment. The other well control systems, is to save training.’’ only requirement for sequencing in • lives in addition to preventing Response: BSEE agrees with the paragraph (a)(6)(v), does not specify any environmental harm. The sequencing of comment about the value of on-the-job particular sequencing of emergency the dual shear rams should be set by the training, but notes that § 250.734(a)(5)’s functions; it only requires a sufficient operator to function in a reasonable requirement for simulator training does delay after beginning closure of the timeframe. If the emergency functions not preclude other, additional training lower shear ram before the upper ram are being activated, then the well- methods, including on-the-job training; begins closure. The specific sequencing thus, no change to regulatory language of emergency functions should be control situation has been analyzed by is warranted in this regard. Nor did the developed by the operator based on the rig personnel and the options to commenter provide any other reason to safety considerations. control the well have become limited to replace simulator training with Summary of comments: One the emergency functions. These ‘‘competence training.’’ commenter recommended that BSEE provisions are intended to ensure the remove the requirement that each safety of the crew and prevent pollution, Comments Related to Proposed emergency function must close dual and therefore require that the emergency § 250.734(a)(5)—ROV Crew shear rams. The commenter stated that functions utilize all of the appropriate Requirements since the sealing shear ram is required components to assist in securing and Summary of comments: A commenter to shear the same tubulars as the non- moving off the well. Thus, no revision recommended several revisions to shearing ram, closing both rams in all to the rule is needed in response to this § 250.734(a)(5), including: Changing the cases does not provide an advantage. comment.

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Comments Related to Proposed consequences of this provision, which operation of the critical functions. They § 250.734(a)(6)(v)—Sufficient Delay requires demonstration that an acoustic also noted that API Standard 53 Summary of comments: Commenters control system will function in the addresses two-handed operation, but requested that BSEE specify the longest proposed environment and conditions, not enable buttons. The commenter period that will be considered asserting that if a failure of the acoustic recommended that BSEE remove the system results in mandatory repairs for proposed requirement for enable ‘‘sufficient delay’’ for closing the upper the BOP stack, then operators will be buttons from this section or add ram, and suggested that ‘‘sufficient encouraged to reduce the emergency references to the relevant provisions in delay’’ should be the time required to capability of the rig by removing the API Standard 53. detect the failure of the lower shear ram acoustic system. Commenters • Response: BSEE agrees with the to hold pressure. The upper shear ram recommended that, if operators install comment that there are other options, should then be required to close as soon an acoustic system, it should be treated besides enable buttons, to ensure two- as possible upon the failure to close the as a redundant system allowed under handed operation for critical functions lower shear ram. § 250.738(o) or that BSEE should allow on the control panels. Accordingly, • Response: BSEE does not specify the operators to assess the risks of BSEE has revised final § 250.734(a)(8) to the timing associated with the continuing without the acoustic system state that ‘‘[y]ou must incorporate sequencing in paragraphs (a)(6)(iv) and act accordingly. A commenter noted enable buttons, or a similar feature, on through (vi). The precise sequencing that acoustic systems have good control panels to ensure two-handed and timeframes for each BOP potential for secondary, emergency operation for all critical functions.’’ This component to function should be set by control of the BOP, but that their change would provide the flexibility to the operator based on the specific reliability is not fully established. Thus, allow for other options besides enable circumstances (e.g., an operator may according to the commenter, there is a buttons. choose to use a risk assessment to need to conduct a trial of the acoustic determine the optimal timeframes). Comments Related to Proposed systems to evaluate their full potential § 250.734(a)(11)(ii)—Critical BOP Comments Related to Proposed and BSEE should not penalize the Equipment § 250.734(a)(6)(vi)—Emergency Control operator if the system fails to perform. • Systems Response: BSEE agrees that the Summary of comments: Commenters operator should not be penalized if it recommended that BSEE revise this Summary of comments: A commenter has already voluntarily decided to proposed provision to clarify the noted that this paragraph would result install an acoustic system on the rig but meaning of ‘‘critical BOP equipment’’ in additional complexity due to the does not use the system; however, if the consistent with API Standard 53. The necessary addition of a timing circuit; operator chooses to use an acoustic commenters also noted that the term this results in less reliability and control system, the operator must meet ‘‘competent person’’ is defined in API possibly more failures of the shearing the requirements of § 250.734(a)(7) to Standard 53 as: ‘‘person with circuit. It also requires more stack demonstrate that the system is characteristics or abilities gained mounted accumulators, which are also functional. Accordingly, BSEE has through training, experience, or both, as more likely to fail and render the shear revised final § 250.734(a)(7) by replacing measured against the manufacturer’s or rams inoperable. A commenter the word ‘‘install’’ with ‘‘use,’’ which equipment owner’s established suggested that BSEE revise paragraph will clarify that an operator need not requirements.’’ These commenters also (a)(6)(vi) by adding, ‘‘[e]mergency demonstrate the functionality of the recommended changing the language in disconnect systems are allowed to be acoustic system unless the operator uses proposed paragraph (a)(11)(ii), requiring activated manually, but once activated that system as an additional emergency a ‘‘comprehensive knowledge of BOP must lead to a failsafe state.’’ control measure (in addition to the hardware and control systems,’’ to ‘‘a Commenters asked for clarification of required autoshear, deadman and EDS knowledge of BOP hardware and control the intent of paragraph (a)(6)(vi) and systems). In any case, the commenter’s systems commensurate with their raised concerns about the reference to concern that a failure to demonstrate the responsibilities.’’ A commenter also the ‘‘logic’’ of the emergency system functionality of the acoustic system suggested that established guidelines are potentially preventing the next step in would result in mandatory repairs to the needed for measuring comprehensive the sequence. BOP stack (and thus would encourage knowledge of BOP hardware and control • Response: BSEE agrees with the removal of the acoustic system) is systems, and that additional time commenter that the control system for unfounded; nothing in this provision beyond the proposed 90 days for the emergency functions should be fail- requires or suggests that the BOP stack compliance is needed if testing or safe once activated, and has revised would need to be pulled for repairs if certain training classes are required. final paragraph (a)(6)(vi) by removing that demonstration cannot be made. Another commenter advocated that the phrase ‘‘and the logic must provide Additionally, an operator may contact BSEE require the equipment owner to for the subsequent step to be the appropriate District Manager, who establish minimum requirements for independent from the previous step can address any questions about the use personnel authorized to operate critical having to be completed’’ and replacing of an acoustic control system on a case- BOP equipment. it with the phrase ‘‘once activated.’’ by-case basis. • Response: BSEE does not agree that This change would allow the systems to any changes to this paragraph are be fail-safe without the addition of a Comments Related to Proposed appropriate based on the comments. timing circuit as suggested by this § 250.734(a)(8)—Enable Buttons Section 250.734(a)(11) is essentially a comment. Summary of comments: Commenters performance-based requirement, and observed that not all BOP control panels several of the changes suggested by Comments Related to Proposed use enable buttons. Many older surface commenters would unnecessarily § 250.734(a)(7)—Acoustic Control and subsea control systems are confine operators in deciding how best Systems manually controlled, which does not to meet the goals established by this Summary of comments: Commenters permit the use of enable buttons; provision. Thus, BSEE has decided not raised concerns about unintended however, these require two-handed to define the term ‘‘critical BOP

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equipment;’’ however, the discussions volumetric visual control systems to Comments Related to Proposed of critical BOP equipment in API observe fluid gains and losses. § 250.734(a)(15)—Gas Bleed Line Standard 53 could be used by an • Response: BSEE is not revising Summary of comments: Regarding the operator as a guide to understanding the paragraph (a)(12). BSEE expects that proposed requirement to install a gas scope of critical equipment. operators will plan for riser bleed line with valves for the annular Similarly, BSEE does not agree that displacement as appropriate and based preventer, commenters noted that many the other suggested changes to on safety factors. BSEE expects the existing annular BOPs do not have a paragraph (a)(11)(ii) are appropriate operator to take whatever appropriate side outlet. They asserted that every because such changes could action is needed in an emergency valve and every outlet added to the BOP unnecessarily limit the scope of the situation to ensure safety of workers and systems increases potential leak paths required personnel knowledge. BSEE protection of the environment. and reliability concerns. A commenter does not expect that the proposed that, if BSEE did not remove ‘‘comprehensive knowledge’’ required Comments Related to Proposed this section, it should be re-worded to by § 250.734(a)(11)(ii) would necessarily § 250.734(a)(13)—Well Cellars pertain only to the uppermost annular include knowledge of BOP hardware Summary of comments: Commenters preventer. and control systems that are so far Another commenter emphasized that, requested clarification of the proposed outside the scope of an individual’s because the upper annular is requirement to install a BOP stack in a current or potential responsibilities that traditionally the working annular, the well cellar when in an ice scour area. there is no reasonable possibility that bleed valves are typically installed The commenters seek to ensure that this the individual would ever be called on below the upper annular. Other would only require that the well cellar to operate such equipment; however, commenters asserted that adding be deep enough to ensure that the lower BSEE believes it is important that all another set of gas bleed valves under the BOP stack—but not the lower stack and personnel operating critical BOP lower annular would require additional LMRP—is enclosed. Another equipment understand how their pilot lines and valves per pod, and that commenter observed that this proposed specific responsibilities fit within the spare pilot lines and valves are limited requirement is addressed in, and would BOP system as a whole. Overly narrow and may be needed for higher priority understanding of the whole system, conflict with, the proposed Arctic OCS pipe ram or shear ram functions. This including hardware and controls, could rule; thus, it should be removed from commenter requested that BSEE clarify result in personnel not understanding this rulemaking. the technical reason for adding a set of the importance of their own duties to • Response: BSEE has not made any gas bleed valves under the lower the success of the system in preventing changes to § 250.734(a)(13). The annular in this situation. a blowout. commenter did not specify how this Commenters also requested additional BSEE also does not agree that the provision conflicts with the proposed time to install the gas bleed line and compliance timeframe for this Arctic OCS rule. It is BSEE’s expectation valves. Commenters asserted that the paragraph should be changed. that the top of the BOP stack (not lead times for engineering, component Commenters provided no factual basis including the LMRP) must be set below procurement and installation of an for such a change. In addition, BSEE the deepest possible ice scour depth. additional valve for gas relief under the expects BOP operating personnel to be The LMRP can be disconnected from the lower annular would preclude familiar with their responsibilities and BOP stack and would be removed if the compliance with the rule within 90 to be trained in accordance with the rig has to move off location, leaving just days. applicable requirements of 30 CFR part the BOP stack in place. • Response: BSEE agrees with several 250, subparts O and S (e.g., of these comments, and has revised final 250.1503(a)). Ensuring the competency Comments Related to Proposed § 250.734(a)(15) to clarify that if a of rig personnel to perform their § 250.734(a)(14)(iii)—Fail-Safe Valves subsea BOP has dual annulars, the gas assigned duties is also consistent with and Side Outlets bleed line must be installed below the current industry standards (see, e.g., API Summary of comments: Commenters upper annular. BSEE has also removed RP 75). recommended adding to the proposed the proposed requirement to install gas BSEE also does not agree with the provision in paragraph (a)(14)(iii)— bleed lines on each annular. These suggestion that the responsibility for regarding valves used in side outlets for revisions should eliminate or minimize compliance with § 250.734(a)(11) choke lines and kill lines—that the commenters’ concerns about space should be transferred from the facility valves must be fail-safe. Another issues, reliability, and addition of operator to some ‘‘equipment owner’’ commenter recommended revising possible failure points. BSEE also agrees who may not be familiar with the paragraph (a)(14)(iv) to require that it will take more than the proposed specific circumstances under which the installation of the side outlet below the 90 days to install the required gas bleed BOP equipment will be used. lines and valves, and revised the lowest sealing shear ram instead of compliance date for paragraph (a)(15) to Comments Related to Proposed below each sealing shear ram. 2 years after publication of the final § 250.734(a)(12)—Riser Fluid • Response: No changes to Displacement rule. Extending the compliance date § 250.734(a)(14)(iii) are necessary will provide adequate time for Summary of comments: Commenters regarding the valves being fail-safe. installation of the gas bleed line and noted that the proposed requirement BSEE understands that these valves are valves while avoiding any rig that fluid in the riser be displaced with already fail-safe closed. However, BSEE downtime. seawater before the riser is removed did agrees with the comment about not include an exception for emergency paragraph § 250.734(a)(14)(iv) and has Comments Related to Proposed or unplanned LMRP disconnects in revised final paragraph (a)(14)(iv) by § 250.734(a)(16)—BOP System which the fluid in the riser would not replacing ‘‘each’’ sealing ram with ‘‘the Capabilities be displaced. Commenters suggested lowest’’ sealing ram to allow more Summary of comments: Commenters displacing the riser fluid using a closed flexibility for component placement. criticized the prescriptive language in

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proposed § 250.734(a)(16)(i) through • Response: BSEE has not made any Comments Related to Proposed (iii), and questioned whether the intent changes to § 250.734(a)(16)(ii) based on § 250.734(b)(2)—BOP Testing is to require that shear rams must be the comment. Mitigating the Summary of comments: Regarding the able to sever the pipe, and seal the pipe, compression of the pipe stub would proposed requirement to re-test the regardless of where the pipe is within allow for the pipe stub to be accepted BOP, including the deadman or lower the bore. The commenters said that if between the shear rams and would not stack ROV intervention functions, upon this is what BSEE wants to achieve, then interfere with the shearing functions. relatch after subsea BOP repairs, a the regulation should state that. Comments Related to Proposed number of commenters stressed that Commenters also asked why, if the § 250.734(a)(16)(iii)—Batteries when the LMRP is retrieved, it is not pipe does not need to be centralized to necessary to re-test those functions. shear it, require centralization of the Summary of comments: Commenters They asserted that the deadman and pipe? Commenters noted that not all suggested revising this paragraph to ROV systems were tested on the surface OEMs require a mechanism for require ‘‘subsea control system and subsea upon initial installation and centering tubulars, and that batteries’’ instead of ‘‘subsea electronic that, after repair, if the systems are centralization can be achieved via the module batteries in the BOP control tested on the surface before geometry of the blade design. pods,’’ noting that there are other redeployment, a re-test after re-latching A commenter suggested that the batteries used in BOP equipment (e.g., should not be required. They also stated proposed text steers technology an acoustic pod, a deadman system). that API Standard 53 does not specify • development in a specific direction Response: BSEE has not made any re-testing under such circumstances. which may inhibit development of other changes to § 250.734(a)(16)(iii) based on The commenters stated that subsea technologies. On the other hand, the comment. BSEE understands that testing of the deadman system with a another commenter stated that BSEE the subsea electronic module is an dynamically-positioned rig is a high explicitly notes that this requirement is important component to ensure consequence operation, and the more designed to encourage further operability of the subsea BOP. However, times the test is performed, the higher technological development, driving the commenter did not provide any the probability a station-keeping safety improvements beyond current support for its requested change, and incident will occur. They also stated industry practice. BSEE currently lacks enough that these tests would lead to additional • Response: No changes to information to justify such a change. unnecessary wear on blind shear rams § 250.734(a)(16) are necessary based on Comments Related to Proposed and reduction of overall system these comments. BSEE understands that § 250.734(b)(1)—BAVOs reliability. some rams may be capable of shearing Some commenters agreed, however, on the rams’ cutting edges, without Summary of comments: Commenters that if any part of the deadman or ROV centralizing the pipe. However, it is observed that, since this section requires systems is dismantled, repaired, or safer to have the pipe centered while a verification report from a BAVO affected as part of the BOP repair, then shearing in order to optimize shearing ‘‘documenting the repairs to the BOP it would be prudent to verify capabilities and reduce risk by ensuring and that the BOP is fit for service,’’ it functionality of these systems upon re- that the pipe to be sheared is across the cannot be implemented until BSEE latching. Commenters recommended shearing surfaces. It is not BSEE’s approves a suitable number of that BSEE revise this section to change intention to inhibit applicable organizations to serve as BAVOs. re-testing of the deadman and ROV technological advancements, however; Commenters also asserted that the intervention functions to re-testing of in fact, BSEE believes this performance- operator should have primary any functions affected during the repair. based requirement will encourage responsibility for certifying the required • Response: BSEE intends that, if the development and use of technology to documentation, and that the BAVO BOP stack is pulled for repair to any center the pipe while shearing. should support such certification by part of the BOP system, testing must be Moreover, nothing in this requirement verifying the information provided by completed before resuming operations. expressly or implicitly discourages the operator. Other commenters However, BSEE agrees with several of development of other new technologies recommended changing the requirement the points made by the comments; thus, to improve shearing capabilities and to use a BAVO to a requirement to use BSEE has revised final § 250.734(b)(2) to decrease risk. Any operator that wishes an ‘‘independent third-party.’’ state that, upon relatch of the BOP, an to do so, may seek approval from the • Response: As previously discussed, operator must perform an initial subsea District Manager or Regional Supervisor BSEE has revised the compliance date BOP test in accordance with under § 250.141 for use of any for the use of a BAVO to one year after § 250.737(d)(4), including testing the alternative equipment or procedures BSEE publishes a list of BAVOs. Part III deadman. If repairs take longer than 30 that are at least as protective as this of this document provides a more days, once the BOP is on deck, you must requirement. detailed discussion of this compliance test in accordance with the date. requirements of § 250.737. These Comments Related to Proposed In addition, as previously discussed, revisions will effectively limit the scope § 250.734(a)(16)(ii)—Ability To Mitigate this and the other BAVO-related of the re-testing requirement—and Compression provisions do not eliminate or transfer therefore the potential negative Summary of comments: A commenter the operator’s regulatory responsibilities consequences from excessive wear asserted that the proposed requirement to the BAVO; the operator is responsible caused by re-testing—by requiring that the subsea BOP have the ‘‘ability to for ensuring compliance with comprehensive re-testing of all BOP mitigate compression’’ of the pipe stub § 250.734(b). As explained earlier in this components, including ROV functions, is too vague. The commenter asserted document, BSEE has decided that it is only when repairs exceed 30 days. For that the critical factor is the ability of necessary that BSEE review and all repairs lasting 30 days or less, this the BOP to accept the pipe stub and determine the qualifications of revised provision would require less suggested that BSEE revise the rule to organizations that will perform this extensive re-testing; for example, re- reflect that. verification function. testing under this situation would not

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need to cover all ROV intervention accumulator system controls, and would document, BSEE has made several functions and would require retesting of significantly increase costs. Also, the revisions to final § 250.735(a) to align only one set of rams (instead of all commenters asserted that the extra the rule more closely with API Standard rams). weight from additional bottles, given 53. In addition, the commenters’ concern limited deck space availability, could Comments Related to Proposed about the possibility that re-testing cause structural issues with the rig. § 250.735(a)—Surface Accumulator would increase the probability of a Further, the commenters asserted that System dynamically-positioned rig going off- this additional equipment would station is minimized by the fact (as require additional maintenance and Summary of comments: Multiple discussed later in this document with potentially render the systems less commenters expressed concern with the regard to proposed § 250.737(d)(13)) that reliable. For certain older rigs, the requirement in proposed § 250.735(a) many rigs already have updated BOP commenters stated that the additional that the accumulator system be able to control systems that allow power to requirements could force the removal of supply pressure to operate all BOP other systems, including dynamic the rigs from service. functions, and to shear pipe as the last positioning systems, to remain on For such reasons, multiple step in the BOP sequence, without during deadman testing. commenters recommended deleting the assistance from a charging unit. They proposed 1.5 times volume capacity asserted that this provision would What associated systems and related requirement and requiring instead that increase the number of accumulator equipment must all BOP systems surface accumulator sizing meet the bottles needed and would require include? (§ 250.735) specifications of API Standard 53 or API upgraded accumulator system controls As provided for in the proposed rule, Spec. 16D (since the methods discussed and that costs associated with the this section combines and revises in API Spec. 16D are also included in additional bottles would be significant. provisions from several sections of the API Standard 53). The commenters also stated that the existing regulations and consolidates • Response: BSEE agrees with several extra weight from additional bottles, system and equipment requirements of the commenters’ concerns. BSEE has given limited deck space availability, applicable to all BOPs. Those decided to revise final § 250.735(a) by could cause structural issues with the requirements cover accumulator deleting the 1.5 times volume capacity rig. systems, control station locations, choke requirement for all surface accumulators • Response: BSEE agrees with the and kill line installation, and remotely- and instead requiring that all commenters’ concerns about the operated locking devices for sealing accumulator systems (including those proposed requirement that the rams on surface BOPs (except pipe or servicing subsea BOPs) meet the sizing accumulator system be able to operate variable bore rams that already have specifications of API Standard 53. This all BOP functions, with the blind shear non-hydraulically operated locks). BSEE revision will not degrade safety or ram being last in the sequence, and still has revised certain provisions of environmental protection compared to have enough pressure to shear pipe and proposed § 250.735 in the final rule as the proposed requirement. BSEE has seal the well. Accordingly, BSEE has discussed in the comment responses for determined that the methods for revised § 250.735(a) by replacing ‘‘all this section and in parts V.B.2 and V.C calculating the necessary fluid volumes BOP functions’’ with ‘‘the BOP of this document. and pressures in API Standard 53 functions as defined in API Standard provide an acceptable amount of usable 53.’’ Revising the BOP functions in Comments Related to Proposed fluid and pressure to operate the response to the comments to align with § 250.735(a)—Surface Accumulator required components, while still API Standard 53, in conjunction with System ensuring—as required by § 250.735(a)— the revisions to the fluid capacity Summary of comments: Multiple that accumulators have enough charge volume requirements previously commenters suggested that the to remain at least 200 psi above the pre- discussed, will eliminate or accumulator system volume capacity charge pressure, without recharging, significantly reduce the commenters’ requirements of proposed § 250.735(a) even after operating all BOP functions. concerns about the costs associated with contradict the analogous provisions of This provides a sufficient margin of the additional bottles. In particular, API Standard 53 and API Spec. 16D, error to prevent any safety or because the final rule requires that the that the proposed capacity requirements environmental harm from failure of accumulator bottles be able to operate are not achievable, and that the pressure to the BOP and is also the BOP functions as defined by API proposed language is so ambiguous that consistent with API Standard 53. Standard 53, fewer accumulator bottles operators could not understand the should be needed (as compared to the rule’s intent. Multiple commenters Comments Related to Proposed proposed requirement), as the stated that the proposed requirement § 250.735(a)—API Standard 53 commenters indicated. This, in turn, that surface accumulators must provide Summary of comments: Some will minimize (as compared to the 1.5 times the volume of fluid capacity comments stated that § 250.735(a) is proposed rule) the potential impacts on necessary to close and hold closed all inconsistent with API Standard 53 in the rig structure that could have BOP components against MASP (the 1.5 other ways; for example, API Standard resulted from the extra weight of times volume capacity requirement) 53 does not require accumulator additional bottles as well as the could effectively force the elimination regulators on subsea BOP stacks to be potential impacts on operations and of some BOP components from existing supplied by rig air. safety from storage of the bottles in the BOP systems, and thus either reduce the • Response: This regulation does not limited deck space available. number of redundant controls or require require that subsea accumulators be For the same reasons, BSEE has also operators to install additional supplied by rig air. It merely imposes removed the phrases ‘‘with the blind equipment. certain requirements ‘‘if’’ subsea shear ram being the last in the Several commenters asserted that the accumulators are supplied by rig air. sequence’’ and ‘‘enough pressure to proposed requirements would increase BSEE understands that rig air is used for shear pipe and seal the well with . . .’’ the number of accumulator bottles surface accumulators and not subsea. In from final § 250.735(a). Removing these needed, would require upgraded addition, as discussed elsewhere in this phrases will eliminate the impression

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that the proposed language would have delete paragraph (b) altogether and proposed requirement for hydraulic mandated that the blind shear ram be instead simply reference API Standard locks with a requirement for remotely- the last step in the BOP sequence. In 53 and API Spec. 16D. operated locks. addition, BSEE agrees that the proposed • Response: No changes to the • Response: BSEE agrees with several language regarding sequencing of the requirements for an automatic backup to of the observations made by the blind shear ram is not necessary, as long the primary accumulator charging commenters. In particular, BSEE agrees as the accumulator is able to provide system in § 250.735(b) are necessary. In that the purpose of the proposed rule— sufficient volume to operate all the fact, the requirements in § 250.735(b) to ensure that sealing rams on surface required BOP functions under MASP. have been in place—in former BOPs, as well as subsea BOPs, can be § 250.443(a)—for years, and BSEE is not locked promptly and with minimal risk Comments Related to Proposed aware of any problems occurring to rig personnel—can be effectively § 250.735(a)—Surface Accumulator because of confusion about the achieved with various kinds of locking System automatic backup to the primary devices appropriate to each type of BOP Summary of comments: A commenter accumulator charging system. Nor is it (surface or subsea) and to each type of recommended changing ‘‘surface necessary to incorporate API Spec. 16D sealing ram. For subsea BOP sealing accumulator system’’ to ‘‘main into paragraph (b). This regulation rams, hydraulic locks will continue to accumulator system.’’ The commenter requires minimum capabilities, and if be appropriate, since those rams are asserts that this will ensure that other compliance with API Spec. 16D or other already required to be hydraulically surface accumulators (e.g., for the industry standards meets these operated (under both former diverter system) are not included and minimum requirements, there is no § 250.442(a) and new § 250.734(a)(1)) will allow for subsea accumulators that reason why an operator could not follow and since existing locking devices for are used by the main control system that standard. those rams are also hydraulically (e.g., LMRP mounted) to be included on operated. subsea stacks. Comments Related to Proposed For surface BOPs, however, other • Response: BSEE agrees that § 250.735(e)—Kill Line locking devices can achieve the same proposed § 250.735(a) could have Summary of comments: Multiple purpose as hydraulic locks with no resulted in confusion about the types of commenters stated that the placement of incremental loss of personnel safety or accumulator systems to which the the term ‘‘kill line’’ in proposed environmental protection. As suggested requirements applied. Accordingly, § 250.735(e) was confusing and by one of the commenters, other types BSEE has revised final § 250.735(a) by recommended that BSEE refer to the of remotely-controlled locks could also replacing ‘‘surface accumulator system’’ language in API Standard 53 instead. ensure that sealing rams can be locked with ‘‘[a]n accumulator system (as • Response: BSEE agrees that without exposing rig personnel to specified in API Standard 53).’’ This proposed § 250.735(e) was not clear. unnecessary risk. BSEE has determined revision will help clarify that the Accordingly, BSEE has revised that any remotely-controlled lock accumulator system requirements of § 250.735(e) to clarify that the kill line (whether or not hydraulically operated) paragraph (a) are applicable to either a must be installed beneath at least one is appropriate for blind shear rams on surface or subsea BOP system (as well-control ram, and may be installed surface BOPs. This requirement will discussed in API Standard 53). below the bottom ram. This clarification help prevent potential blowouts and will avoid confusion related to the fact reduce the risk of personnel having to Comments Related to Proposed that many BOP stacks use a test ram be in or near a potentially hazardous § 250.735(b)—Automatic Backup to the (which is not a well-control ram) in the area during an emergency event by Primary Accumulator Charging System bottom-most part of the BOP. making it unnecessary for them to Summary of comments: Commenters Comments Related to Proposed manually operate manual locks. stated that this proposed paragraph— By contrast, pipe rams and VBRs on § 250.735(g)—Hydraulically Operated which would require ‘‘an automatic surface BOPs can be safely and Locking Devices backup to the primary accumulator- effectively locked manually, as they charging system’’—was unclear. They Summary of comments: Multiple have been under former § 250.443(f), or requested clarification on the meaning commenters urged that this provision— remotely. BSEE is not aware of any well- of the phrase ‘‘automatic backup to the regarding hydraulically operated locks control incident that was directly primary accumulator charging system.’’ installed on BOPs with sealing rams related to failure of a surface BOP They asked BSEE to answer several (i.e., pipe rams/VBRs or blind shear manual lock; nor is BSEE aware of any questions about the meaning of this rams)—distinguish between surface and personnel safety incident resulting from phrase in several specific factual subsea BOP stacks. Some commenters operation of a manual lock on pipe rams situations; e.g., whether, assuming a noted that locking devices for ram-type or VBRs. Thus, given the past charging system is an electric-driven BOPs are already addressed in effectiveness of manual locks, BSEE has pump, the automatic backup § 250.733(e). Some commenters determined that it is not necessary at requirement would apply if the electric- indicated that surface stacks can use this time to require hydraulic or other driven pump is also capable of being manual locks, while subsea BOP stacks remotely-controlled locks on surface powered from the emergency bus should use hydraulic locks. Other BOP pipe rams/VBRs. instead of the primary power generation commenters observed that since most Accordingly, BSEE has revised final from the rig. surface stacks do not use hydraulic § 250.735(g) to distinguish between Commenters also claimed that, if the rams, installation of hydraulic locks in surface and subsea BOPs, and to provide proposed requirement for an automatic compliance with this provision would operators with more flexibility in their power source is intended to require a require 3 years from publication of the choice of locking mechanisms for second complete pumping unit, the time final rule, while other commenters sealing rams on surface BOPs. needed to procure and install such stated that the proposed requirement Specifically, the final rule will require equipment would preclude compliance (and proposed § 250.733(e)) would be hydraulic locks for all subsea BOP within the proposed 90 days. Other unduly costly. One commenter sealing rams, remotely-operated locks commenters recommended that BSEE recommended that BSEE replace the for surface BOP blind shear rams, and

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manual or remotely-controlled locks on § 250.736(b), that all choke manifold Comments Related to Proposed surface BOP pipe rams/VBRs. components, including valves § 250.736(d)(4)—Top-Drive Systems In addition, BSEE understands that downstream of the chokes, be rated for Summary of comments: Commenters the requirement to install remotely- the full working pressure of the BOP stated that proposed paragraph (d)(4)— controlled locks (whether or not stack. requiring a strippable kelly-type valve hydraulically operated) on surface BOP • on a top-drive system with a remote- blind shear rams would take Response: BSEE disagrees with the controlled valve—is more specific than significantly more time than 90 days recommended revisions to § 250.736(a) API Standard 53, and that BSEE should from publication of the final rule, due through (c). These paragraphs describe simply reference API Standard 53. to the need to procure enough of the general requirements for the choke • Response: BSEE disagrees with the necessary equipment as well as to manifold. Nearly identical requirements practical and logistical problems with have been in place for many years comments suggesting changes to installation. For example, as implied by (formerly in § 250.444), and BSEE is not § 250.736(d)(4). This provision has been the commenters, installation of aware of industry raising any prior in the existing regulations for many hydraulic locks on BOP surface stacks concerns with implementing those years (i.e., in former § 250.445(d)) and that do not have hydraulic rams would longstanding requirements. With regard BSEE does not believe that take substantially more time because to paragraph (b), the need to ensure that incorporating API Standard 53 would hydraulic systems to control the locks in all choke manifold components are able improve safety or environmental those cases will also need to be added to withstand the wellbore pressures that protection as compared to the former to the BOP stack. BSEE also agrees that they will encounter is as important regulations and this final rule. In failure to install hydraulic or other under this final rule as it was under the addition, BSEE is unaware of prior remotely-controlled locks by the existing regulation. Nonetheless, if an industry concerns associated with the proposed compliance date could result operator has any questions about the equipment required by this in significant rig downtime. meaning of this longstanding longstanding requirement. Thus, there is Accordingly, BSEE has determined that requirement, it can ask the District no need to add the reference to API Standard 53 suggested by the 3 years after publication of the final rule Manager for assistance. is an appropriate timeframe for commenter. Comments Related to Proposed acquiring and installing all of the What are the BOP system testing necessary systems and equipment to § 250.736(d)—Kelly Valves requirements? (§ 250.737) meet the requirement for surface BOP Summary of comments: Commenters blind shear rams, and has revised the As provided for in the proposed rule, recommended that BSEE revise this compliance date in final § 250.735(g)(2) this section combines and revises paragraph to clarify that it only applies accordingly. various BOP testing requirements from to rigs that operate with kelly valves. the existing regulations. Paragraph (a) What are the requirements for choke One commenter asserted that proposed reorganizes and consolidates the manifolds, kelly-type valves, inside § 250.736(d)(1) requires the use, ‘‘during pressure testing frequency requirements BOPs, and drill string safety valves? all operations,’’ of ‘‘a kelly valve for drilling, workovers, completions, (§ 250.736) installed below the swivel’’ even though and decommissioning. Paragraph (b) As provided for in the proposed rule, kelly valves are no longer in widespread requires certain pressure test procedures this section reflects a combination of use in offshore drilling operations. while paragraph (c) clarifies the provisions from several sections of the Similar comments claimed that kelly duration of the pressure tests. Paragraph existing regulations that established valves are seldom used and have limited (d) further clarifies testing procedures technical requirements for choke applications in OCS operations because for various situations and equipment manifolds, kelly valves, inside BOPs, almost every rig on the OCS now uses (e.g., stump testing, initial subsea and drill string safety valves. This final drill pipe instead of kelly valves. For testing, ram and annular testing). BSEE rule makes several revisions to the that reason, one commenter has revised certain provisions of former requirements with respect to recommended that BSEE delete proposed § 250.737 in the final rule as choke manifolds and kelly-type valves. proposed paragraphs (d)(2) and (3), discussed in the comment responses for BSEE has revised certain provisions of since these provisions are obsolete. this section and in parts V.B.6 and V.C proposed § 250.736 in the final rule as Similarly, some commenters asserted of this document. discussed in the comment responses for that the methodology required in Comments Related to Proposed this section and in part V.C of this proposed paragraph (d)(3) has been § 250.737(a)(1)—Installation BOP Test document. rendered obsolete by the proven use and operation of top drives. Summary of comments: A commenter Comments Related to Proposed requested clarification that proposed • §§ 250.736(a) Through (c)—API Response: BSEE agrees with the § 250.737(a)(1) only requires a full BOP Standard 53 comments about the limited application pressure test upon an initial installation, Summary of comments: A commenter of kelly valves and has revised final not subsequent installations following recommended that BSEE revise § 250.736(d)(1) by replacing the repairs or unplanned pulls. The proposed § 250.736(a) to rely on API references to kelly valves with the commenter mentioned that studies have Standard 53 for the design and phrase ‘‘applicable [k]elly-type valves as demonstrated that most faults are operation of the choke manifold. The described in API Standard 53.’’ For the discovered during function testing; commenter also suggested that BSEE same reason, BSEE has deleted based on these findings, function testing delete proposed paragraphs (b) and (c) paragraphs (d)(2) and (3) from final is more valuable than pressure testing in because the matters they cover would § 250.736. BSEE has determined that the measuring operability of the system. already be covered by the reference to reference to API Standard 53 • Response: The language requiring a API Standard 53 in paragraph (a). specifications for kelly-type valves in pressure test when a BOP is installed is Another commenter asked whether it paragraph (d)(1) renders paragraphs the same as the longstanding language was BSEE’s intent, in proposed (d)(2) and (3) unnecessary. in former § 250.447(a) and requires no

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clarification at this time. There is no Comments Related to Proposed • Response: BSEE has not made change in the meaning or intent of that § 250.737(a)(4)—District Manager changes to proposed § 250.737(b)(2), requirement, now located in Directed BOP Pressure Test which is largely based on the § 250.737(a)(1). In addition, BSEE is Summary of comments: BSEE longstanding requirements for BOP aware that BOP failures during pressure received one comment on proposed testing in the current rules (former testing happen, and therefore it is paragraph (a)(4), objecting to the BSEE § 250.448(b)), including blind shear ram important to pressure test to help verify District Manager having the authority to testing. BSEE does not agree that the the integrity of the BOP system to increase BOP testing frequency. clarification requested by the ensure it can function as intended. • Response: Like similar provisions commenter is necessary. BSEE discusses throughout 30 CFR part 250, the additional testing requirements for Comments Related to Proposed § 250.737(a)(4) is intended to give subsea BOPs in more detail later in § 250.737(a)(2)—14-Day BOP Pressure District Managers the necessary response to comments on proposed Test flexibility and discretion to require § 250.737(d). If an operator has any Summary of comments: BSEE actions as needed in specific cases to questions about testing specific received a number of comments on the fulfill the purposes of the regulation, components, it may contact the proposed requirement in § 250.737(a)(2) and BSEE is therefore not making any appropriate District Manager for that BOP pressure tests be conducted changes to proposed paragraph (a)(4). In guidance. before 14-days have elapsed since the any case, this provision is identical to the longstanding language in the current Comments Related to Proposed prior test, and no later than 30 days after regulations (i.e., former § 250.447(b)), § 250.737(b)(3)—Annular BOP High since the last blind shear ram BOP and BSEE is unaware of any significant Pressure Test pressure test. One commenter supported concerns raised by operators in more frequent BOP pressure tests of 7 connection with District Managers Summary of comments: A commenter days for all BOPs used in Arctic OCS exercising this authority. suggested that the words ‘‘lesser of the’’ operations. However, other commenters are missing from this paragraph, noting supported less frequent BOP pressure Comments Related to Proposed that hydrostatic pressure should also be testing. Commenters cited the § 250.737(b)—BOP Pressure Test accounted for in subsea tests by provisions of API Standard 53, which Procedures deducting that pressure from the surface recommends a 21-day BOP test cycle for Summary of comments: Another applied pressure. shear ram BOPs, as well as international commenter recommended that BSEE • Response BSEE has not made any industry best practices, in support of require an additional ram low pressure changes to § 250.737(b)(3). That longer pressure test intervals. Multiple test after the completion of the high provision allows the operator to choose commenters pointed out that less pressure test. The recommended ram between 70 percent of the RWP or 500 frequent testing would mitigate wear testing sequence would be, in this case, psi greater than the calculated MASP for low pressure, high pressure, and low and tear on the equipment from the its high pressure test. The operator is pressure. The commenter stated that it testing itself, and wear and tear free to use the lesser of those pressures is possible to tear the packing element adversely affects long-term reliability of if it so chooses, and no changes to the the equipment and thus increases the elastomer seal during high pressure test such that it might not seal again during regulatory language are required to risks from equipment failure. allow that. In addition, the hydrostatic • a low pressure test. Response: BSEE has not made any • Response: The pressure test pressure is already accounted for in the changes from the 14-day testing procedures reflected in the rule have subsea BOP test, because it is added to requirement in the proposed and been in place for many years (formerly the applied surface pressure to equal the existing regulations. BSEE did not in § 250.448), and BSEE is not aware of MASP at the mudline. receive any new supporting data with issues created by, or operators raising Comments Related to Proposed any comments that would support any concerns with, those procedures. § 250.737(b)(3)—Annular BOP High changes to the existing 14-day testing BSEE is also unaware of any new data Pressure Test interval at this time. Although BSEE is supporting a change in the procedures aware of concerns that the more and is therefore not revising Summary of comments: Another frequently BOPs are tested, the more § 250.737(b) as suggested. commenter recommended that the likely the equipment is to wear out Comments Related to Proposed pressure test on the annular should be prematurely, and thus to fail to operate § 250.737(b)(2)—BOP High Pressure Test to a minimum of 70 percent of the RWP, properly when needed, further study, stating that at times the annular is tested research, and discussions with subject Summary of comments: Commenters in excess of 70 percent of the working matter experts is needed for BSEE to noted that this provision does not pressure, while not exceeding the RWP. differentiate between initial and make a determination that it is • Response: BSEE has not made any appropriate to change the general 14- subsequent testing, noting that proposed § 250.737(d) requirements for subsea changes to § 250.737(b)(3). That day testing requirement. An operator BOPs differentiate between stump, provision requires testing to either 70 that believes a different interval is initial and subsequent testing, all of percent of the RWP or 500 psi greater warranted by special circumstances, which utilize different test pressures. than the MASP. However, if an operator however, may seek approval from the Another commenter asked BSEE to believes there are situations where District Manager or Regional Supervisor clarify proposed paragraph (b)(2) to testing to higher than 70 percent of the to use an alternative procedure in confirm that the blind shear rams will RWP is prudent and no less protective accordance with § 250.141. More details only be tested to the high-pressure for than this regulatory requirement, it may concerning this issue are contained in the well at initial installation, and that seek approval for alternative test part V.B.6 of this document. subsequent tests will be performed to pressures from the appropriate District the casing test pressure. Manager under § 250.141.

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Comments Related to Proposed test of a surface BOP, but asserted that • Response: BSEE has not made any § 250.737(c)—BOP Pressure Test after the initial test, the use of mud is changes to § 250.737(d)(3)(iv), because Duration acceptable. Commenters suggested that the relevant ROV capabilities were Summary of comments: Commenters BSEE revise the final rule to allow the revised in final § 250.734(a)(4) to reduce suggested that pressure testing regimes operator to select test fluid appropriate the scope of ROV intervention function capability to critical operations only are clearly defined in API Standard 53, for the well conditions. • Response: BSEE agrees with the (e.g., operation of each shear ram, ram and that BSEE should align the rule comments about initially testing surface locks, one pipe rams, and LMRP with API Standard 53 or at least BOPs with water, then allowing other disconnect), similar to API Standard 53 reference that standard. A commenter appropriate fluids to be used for and those specified by the commenter. also suggested that BSEE remove the use subsequent testing. Accordingly, BSEE of predictive-type technology from the Comments Related to Proposed has revised final § 250.737(d)(2) by rule. A commenter also suggested that §§ 250.737(d)(4)(i) and (v)—API clarifying that water must be used for BSEE follow API Spec. 6A guidance on Standard 53 the initial test of a surface BOP system, pressure stabilization. but that subsequent tests may use Summary of comments: Other • Response: BSEE has not made any drilling, completion, or workover fluids. commenters asserted that the additional changes to § 250.737(c), which is The revised requirement would address requirements for subsea BOP testing identical in most respects to the comments raised about the use of proposed in § 250.737(d)(4)(i) and (v) longstanding requirements in the water for post-initial testing while still conflict with API Standard 53. Under existing regulations (formerly preserving well integrity by not paragraph (d)(4)(i), there is not a § 250.448(c)). The comment does not reducing the hydrostatic column. specified timing requirement between identify or explain the type of conducting the stump testing and the predictive-type technology to which it Comments Related to Proposed on-bottom installation test; the time objects; however, if it refers to the use § 250.737(d)(2)(ii)—72-Hour Surface between these tests is a risk-based of charts or digital recorders, BSEE BOP System Test Notification operational decision and is determined notes that the existing regulations also Summary of comments: A commenter by the operator and equipment owner. refer to charts and recorders. BSEE is also suggested that the initial test of The commenter says that API Standard unaware of any concerns regarding surface BOPs should be the only 53 discusses initial subsea testing and conflicts with API Standard 53 or Spec. applicable test requiring 72-hour notice specifies blind shear ram or pipe rams 6A for pressure testing durations or to BSEE; subsequent testing must only need to be functioned by an ROV, pressure stabilization. If there are any comply with the test frequency required and not pressure tested, and that they concerns surrounding the duration and by the rules, so notification to BSEE of only have to be tested annually. • method of pressure testing, operators subsequent tests should not be required. Response: BSEE has not made any may contact the appropriate District • Response: BSEE agrees with the changes to § 250.737(d)(4). Operators are Manager for guidance. comment and has revised final aware and test according to the 30 day Comments Related to Proposed § 250.737(d)(2)(ii) by clarifying BSEE’s timeframe, as it is based on current § 250.737(c)—BOP Pressure Test intent that the notice requirements for § 250.449(b). The timeframe between the Duration this paragraph apply only to the initial initial test and the stump test under test. § 250.449(b) provides adequate time Summary of comments: Other conduct each test. Furthermore, BSEE commenters noted that proposed Comments Related to Proposed wants to minimize time between these § 250.737(c) will result in a large § 250.737(d)(3)(iii)—72-Hour Stump tests to help ensure the components and number of new chart recorders being Test Notification BOP system as a whole can function as ordered concurrently by industry, and Summary of comments: Multiple intended and tested. BSEE does not that lead times for new equipment may commenters recommended deleting agree with the commenter about only exceed the proposed 90 days for § 250.737(d)(3)(iii), which requires the testing certain components annually as compliance and put rigs out of operator to notify the BSEE District this does not provide an acceptable compliance. These commenters Manager at least 72 hours before the level of confidence that the component requested 12 months to obtain and stump test so BSEE representative(s) can would function as intended. install the necessary equipment across witness the testing. all rigs. • Response: BSEE has not made any Comments Related to Proposed • Response: BSEE has not made any changes to § 250.737(d)(3)(iii). BSEE § 250.737(d)(5)—API Standard 53 changes to the compliance date for this requires notification to help ensure Summary of comments: Multiple provision. If an operator has any compliance with the approved permits. commenters expressed several concerns specific concerns about availability of with requirements in proposed equipment to meet the compliance date, Comments Related to Proposed § 250.737(d)(5), including: The it may contact the District Manager for § 250.737(d)(3)(iv)—BOP Stump Test differences between API Standard 53 guidance or request approval to use ROV Functions and this section regarding pod and alternative technology or procedures Summary of comments: Two control station testing; absence of a under § 250.141. commenters recommended adding more definition of ‘‘function testing;’’ specific details to paragraph (d)(3)(iv), confusion about the pod testing rotation; Comments Related to Proposed which requires testing and verification and unnecessary testing of remote § 250.737(d)(2)—Surface BOP Test With of all ROV intervention functions on stations used in emergency situations. Water subsea BOP stacks during stump testing. • Response: BSEE agrees with some Summary of comments: Commenters The commenters suggested replacing of the concerns raised by the comments, expressed concerns about the proposed ‘‘all ROV . . . function’’ with specific and BSEE has revised final requirement to use water to test a functions (i.e., the shear ram close, one § 250.737(d)(5)(i)(C) by deleting the surface BOP system. Commenters agreed pipe ram close, and the LMPR unlock/ phrase ‘‘and the pod used for pressure that water should be used for the initial unlatch intervention). testing must be alternated between

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pressure tests’’ and inserting in its place use is a new requirement. Commenters for all rigs to make upgrades to existing ‘‘and 14-day pressure testing.’’ This recommended that BSEE require control systems that would allow low change will simplify and align the pod pressure testing of the annular-type probability/low risk deadman testing to testing rotation with the required 14-day BOPs against the largest and smallest be performed on all rigs. A commenter BOP pressure testing under the final drill pipe in use during the stump test; stated that testing the deadman circuit rule and improve consistency between then, for subsea BOP pressure tests, is desirable, but doing such testing at paragraphs (d)(5)(i)(A) and (B). Thus, it pressure testing the annular BOPs present would put many operations at will resolve or minimize the concern against the smallest outside diameter risk because they would have to cut off raised by the comments regarding drill pipe used in the hole section. rig power to simulate a deadman test potential confusion over pod testing • Response: BSEE agrees with the and would not have access to power on rotation and potential differences commenters and has revised final the rig if an incident occurred. between the proposed requirement and § 250.737(d)(6) and (7) by replacing • Response: After considering the API Standard 53. ‘‘against the largest and smallest sizes of comments, BSEE has revised final In addition, BSEE has revised final the pipe in use’’ with ‘‘against pipe sizes § 250.737(d)(12) to allow the function § 250.737(d)(5)(ii) by replacing the according to API Standard 53.’’ This tests for the autoshear/deadman to be phrase ‘‘any additional control stations revision would help reduce wear of the combined. Many rigs have already must be function tested every 14 days’’ equipment and thus improve overall voluntarily updated the BOP control with ‘‘remote panels where all BOP integrity of the system and limit rig systems with an autoshear/deadman functions are not included (e.g., life boat personnel’s risks from hazardous testing circuit to reduce the risk of not panels) must be function tested upon operations such as tripping in and out having component operability during the initial BOP tests and monthly of the hole. the testing. thereafter.’’ This revision addresses the BSEE does not agree, however, with commenters’ concerns regarding Comments Related to Proposed the comment about adopting API unnecessary testing of remote stations § 250.737(d)(9)—BOP Function Test Standard 53’s testing timeframe or used in emergency situations by Summary of comments: Commenters schedule. The final rule will require the ensuring that the EDS panels are not suggested adding to § 250.737(d)(9) that initial on-bottom test to verify operated every 14 days, which could pressures tests qualify as function tests. component operability on the well. This increase risk to the rig crew due to the • Response: No changes to test provides assurance that the system functions that those panels operate. The § 250.737(d)(9) are necessary. Function was not damaged while running and additional time provided by the revised testing must occur every 7 days. During latching the BOP on the well, and that language to test these remote panels will a pressure test, the component will have it will operate under the conditions that also provide more flexibility to conduct to function to close and seal before a it might confront in an emergency. the tests at optimum times in order to pressure test can be completed on that These requirements are consistent with limit risks to the rig crew. component. Therefore, it would also established longstanding practice, and These changes to final qualify as a function test without the operators do not need additional time to § 250.737(d)(5)(i)(C) and (d)(5)(ii) also need for any additional language in this comply. improve consistency with API Standard provision. 53 and help reduce any potential Comments Related to Proposed confusion related to testing of the pods Comments Related to Proposed § 250.737(e)—BOP Shear Test and control stations. BSEE requires pod § 250.737(d)(12)—ROV Intervention Summary of comments: A commenter and control station testing, to ensure Functions suggested that the OEM should perform proper use of the safety equipment and Summary of comments: Multiple the shear testing at the OEM test facility to reduce the risk of non-functioning comments raised concerns with and not on the unit using the drilling equipment, because all control stations § 250.737(d)(12), including confusion contractor’s BOP stack. The commenter have the potential to become critical about the ROV capabilities and testing, stressed that there is a risk of damaging control mechanisms during well-control compatibility with the BOP stack, and equipment when carrying out shear events. ROV closing timeframes. A commenter tests. Equipment manufacturers should BSEE does not agree that there is any proposed moving the requirements to be responsible for demonstrating need to define ‘‘function testing’’ in the § 250.737(d)(3) and deleting shearing capability as well as providing rules. The term has been used in the § 250.737(d)(12). shearing data that would allow for a existing regulations for many years and • Response: As suggested by the better understanding of the equipment the industry is familiar with its commenter, BSEE deleted proposed shearing capability. meaning. § 250.737(d)(12) from the final rule. • Response: BSEE has not made any ROV testing is sufficiently covered changes to § 250.737(e). BSEE agrees Comments Related to Proposed under final § 250.737(d)(3) which that testing to actually shear pipe § 250.737(d)(6) and (7)—API Standard requires testing of all ROV functions. should be done at a test facility. BSEE 53 does not intend for, nor require, the Comments Related to Proposed Summary of comments: Commenters shear testing to be done on the rig. observed that § 250.737(d)(6) conflicts § 250.737(d)(13)—API Standard 53 with API Standard 53, which requires Summary of comments: Multiple What must I do in certain situations testing both the largest and smallest commenters had concerns with involving BOP equipment or systems? pipe sizes during the stump test, and proposed § 250.737(d)(13), including (§ 250.738) then subsequently testing the smaller concerns about possible inconsistency As described in the proposed rule, pipe. Commenters recommended between the rule and API Standard 53 this section combines and revises aligning this provision with API with regard to testing frequency and requirements from former §§ 250.451 Standard 53. testing autoshear and deadman systems and 250.517 for actions that must be Commenters also noted that the separately. A commenter stated that if taken when specific situations involving requirement to pressure test annular API Standard 53 is not adopted, BSEE BOP systems arise (e.g., failure of a BOP type BOPs against the smallest pipe in should consider a 3-year grace period to hold pressure during a test; needed

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repairs to a BOP system). The required • Response: BSEE disagrees with the Comments Related to Proposed actions include correction of problems comment about the need to change the § 250.738(e)—Tapered String (e.g., repair or reconfiguration of the term ‘‘BOP system’’ in § 250.738(b) to Summary of Comments: Commenters BOP), retesting the affected equipment ‘‘BOP stack,’’ because there are many generally supported requirements in or system, and installation of barriers other important components of a BOP § 250.738(e) for operations with a prior to removal of a BOP, depending on system (e.g., the subsea wellhead tapered string. Comments were the situation. BSEE has revised certain connector, the LMRP connector, the submitted on the requirement to install provisions of proposed § 250.738 in the choke and kill lines on the LMRP and two sets of pipe rams to seal around the final rule as discussed in the comment on the marine riser system) that are smaller pipe. Commenters did not see responses for this section and in part typically not considered part of the BOP the need for a redundant ram on the V.C of this document. stack. Therefore, no changes are smaller size pipe provided the pipe is Comments Related to Proposed necessary to paragraph (b) in this regard. not across the BOP stack while drilling. § 250.738(a)—BOP Equipment Does Not BSEE also does not agree that it is They stated that the annular provides a Hold the Required Pressure During necessary to change the word redundant means to seal against the Testing ‘‘certifying’’ to ‘‘verifying’’ in paragraph smaller pipe. Commenters suggested (b)(3). BSEE wants to ensure the BOP is Summary of Comments: Commenters revising the provision to say: ‘‘. . . two appropriate for use and the BAVO generally supported requirements in sets of rams must be capable of sealing certifying report provides BSEE with § 250.738(a) for situations when BOP around the larger-size drill string and important information to consider in its equipment does not hold the required two sets of pipe rams must be capable pressure during testing. Several approval for resuming operations. of sealing around the smaller size pipe commenters requested a change to the Comments Related to Proposed in the event that this smaller pipe is requirement to exclude minor issues § 250.738(d)—BOP Control Station or across the BOP stack when drilling, or which are easily solved or remediated. Pod one set capable of sealing on the smaller The proposed revisions are as follows: size pipe if the pipe will not be across ‘‘You must report any equipment Summary of Comments: Commenters the BOP while drilling . . . .’’ • failures, including leaks that cannot be generally supported requirements in Response: BSEE agrees with the remedied, to the District office and on § 250.738(d) for a BOP control station or comment about only requiring one set of the daily report as required in pod that does not function properly. pipe rams to seal on the smaller size § 250.746.’’ One commenter suggested One commenter suggested revisions for pipe and has revised final § 250.738(e) that in addition to reporting the problem clarity by suggesting the following by replacing the requirement to install and retesting the affected equipment, change to paragraph (d): ‘‘A BOP control ‘‘two’’ sets of pipe rams capable of the well must be secured and operations station or pod does not function sealing around the smaller size pipe suspended until the BOP is successfully properly or no longer provides the with ‘‘one’’ set. This change does not pressure tested, or repaired, or replaced required minimum level of decrease the sealing capabilities of the in accordance with § 250.738. redundancy.’’ Another commenter BOP stack because many BOP stacks use • Response: BSEE agrees with the stated that the term ‘‘[function] VBRs, that can seal around a greater comment about limiting the reporting properly’’ is vague and misleading and variety of pipe sizes and, as the requirements, and BSEE has revised that paragraph (d) seems to conflict with commenter stated, the annular is also § 250.738(a) by removing the paragraph (o). used to seal around the smaller pipe requirement for reporting to the District sizes. • Response: BSEE disagrees with the Manager. The reporting to the District comment about making any changes to Comments Related to Proposed Manager is unnecessary because the the pod requirements of § 250.738(d). § 250.738(f)—Casing Rams or Casing information will still be included in the The suggested phrase ‘‘or no longer Shear Rams on a Surface BOP Stack daily report, and the report is available provides the required minimum level of for BSEE review. BSEE has not made Summary of Comments: Multiple redundancy’’ is unnecessary. BSEE any other changes to this paragraph. The commenters had concerns about the expects both control pods to be commenter’s suggestions about what to requirements in proposed § 250.738(f) functional to ensure there is continuous do if you have to repair or replace the for installing casing rams or casing shear BOP operability and control in case of BOP if leaks are observed are covered rams in a surface BOP stack. The emergency situations. When one of the under § 250.738(b). comments stated that the proposed pods is damaged or fails, the other pod requirement conflicts with API Standard Comments Related to Proposed must still be able to operate the BOP 53 and implies that casing (not just drill § 250.738(b)—Repair, Replacement, or stack. Therefore, BSEE has not made pipe) has to be sheared. Commenters Reconfiguration of the BOP System any changes to paragraph (d). noted that API Standard 53 does not Summary of Comments: Commenters BSEE disagrees with the commenters’ specify a need to shear casing. generally supported requirements in concerns about the term ‘‘[functions] Commenters also recommended § 250.738(b) for repair, replacement, or properly’’ in § 250.738(d). BSEE requires revisions to the language regarding reconfiguration of a surface or subsea two pods so they are not considered testing the ram bonnets before running BOP system. Several commenters redundant equipment under casing, as follows: ‘‘. . . Test the ram requested a change from the term ‘‘BOP § 250.738(o). BSEE needs to ensure that bonnets’ seals before running casing to system’’ to ‘‘BOP stack,’’ so that a BOP the pods can operate the required the RWP or MASP\‘MAWHP’ plus 500 surface component does not affect components of the BOP stack in an psi.’’ operations and can be replaced without emergency situation. Therefore no • Response: BSEE agrees with the having to put the well in a safe changes are necessary to this paragraph. concerns related to the reference to controlled condition. Other comments If there are any concerns about a shearing casing, not just drill pipe and suggested changing the word specific operational limit of your pod revised final § 250.738(f) by removing ‘‘certifying’’ in § 250.738 (b)(3) to functionality, contact the appropriate the sentence ‘‘[t]he BOP must also ‘‘verifying.’’ District Manager for guidance. provide for sealing the well after casing

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is sheared.’’ BSEE recognizes that this two barriers in place prior to BOP Testing the wellhead/BOP connection to statement is not necessary in this removal be revised to require two the maximum MASP plus 500 psi for location, as there are shearing capability independent tested and verified the well upon installation; or pressure requirements covered in more detail barriers. testing each casing to the MASP plus throughout this subpart (e.g., • Response: BSEE does not agree with 500 psi for the next hole section; or § 250.732(b)). the suggested changes. It is not some combination of those two tests. BSEE also agrees with the necessary to revise § 250.738(j) given These changes align the regulations commenters’ concern about testing the that barriers must be independently with current BSEE policy and practice ram bonnets and has revised paragraph tested, to ensure integrity before related to testing the wellhead/BOP (f) by replacing ‘‘ram bonnets’’ with removing the BOP stack. Nor is any connections. These changes provide ‘‘affected connections.’’ BSEE change needed to clarify that the clarity to BSEE’s testing requirements. recognizes that testing the ram bonnets barriers must be tested before moving BSEE also agrees, in part, with the need does not properly address the necessary off location. Section 250.720(b) to remove the hydraulically operated testing to ensure BOP system integrity. effectively requires that the barriers be BOP components language of paragraph Testing the affected connections is a tested before removing mud from the (l). BSEE removed this provision in this better indicator of proper ram riser in preparation for removing the paragraph because it is sufficiently installation that shows system pressure BOP stack. covered under § 250.737(d)(4). integrity. Comments Related to Proposed Comments Related to Proposed Comments Related to Proposed § 250.738(k)—Deadman or Autoshear § 250.738(o)—Redundant Components § 250.738(g)—Annular BOP Activation Summary of comments: Multiple Summary of Comments: One Summary of Comments: One comments were submitted on the comment was received on the comment was submitted on the proposed § 250.738(o) requirements for requirements in § 250.738(g) for use of proposed requirement in § 250.738(k) installation of redundant components an annular BOP with a RWP less than requirements related to deadman or for well control in BOP systems. The the anticipated surface pressure. The autoshear activation. The commenter comments suggested that BSEE revise commenter points out that paragraph (g) described the requirements as too the paragraph (o) to require a one-time would allow an operator to use an prescriptive and suggested that BSEE identification and certification annular BOP with an RWP less than the revise paragraph (k) by replacing the submitted with documentation under anticipated surface pressure, with BSEE phrase ‘‘place the blind shear ram proposed § 250.731, including approval; yet for safe operations, the opening function in the block position identification of all additional annular BOP should have an RWP to prior to re-establishing power to the redundant components and certification match or exceed the anticipated surface stack’’ with the phrase ‘‘Then you must using failure modes analysis by a BAVO pressure. Commenters suggest that DOI address that possibility prior to re- that the failure of those additional should provide further justification for establishing power to the stack.’’ redundant components will not impact this practice and include limitations on • Response: BSEE disagrees that the the BOP in a way that will make it unfit when this practice would be safe. language should only require the for well-control purposes. One other • Response: BSEE disagrees with the operator to address the possibility of the commenter suggested that the comment. Annulars are typically used BSR opening upon re-establishing requirement to submit a report each with wellbore pressures less than power to the BOP stack. BSEE is aware time a redundant component fails can MASP. An annular does not have any of situations where the BSR opened actually be a deterrent to operators who locking mechanisms to keep it closed, as upon re-establishing power to the BOP would otherwise want to achieve higher do pipe and blind shear rams, and an stack, and BSEE wants to ensure that the safety levels by incorporating annular will relax and not seal if the well is not unsecured prematurely and redundancy beyond the required levels. hydraulic pressure is lost. Thus, a single that the operator is prepared for the use • Response: BSEE disagrees with the annular is not commonly used for well of well-control measures if necessary. commenters’ concerns about the failure control purposes; rather, annulars are Therefore, no changes to § 250.738(k) of redundant components. If redundant commonly used in conjunction with are necessary. components are installed and planned other MASP-rated components, such as to be used as necessary, they need to be pipe rams or blind shear rams, that can Comments Related to Proposed able to fully function and operate seal the well under MASP. The annular § 250.738(l)—BOP Test Ram (similarly to the required components) is used for quick closing and spacing of Summary of comments: Multiple as intended. The operator has the option the joint so the well-control rams can comments were submitted on the to utilize the redundant systems without close on a desired section of pipe. proposed § 250.738(l) requirements that having to pull the stack, as long as the Because of the annular design, it is used would apply if a test ram is used. A failure does not interfere with the differently than well-control rams; its commenter had concerns about the required functionality. Therefore, no design allows for pipe to be pulled maximum pressure for the approved changes to § 250.738(o) are necessary. through it, such as in stripping ram test for the well. Commenters also Comments Related to Proposed operations, and for piping spaceout in requested that hydraulic connectors, § 250.738(p)—Bottom Hole Assembly the BOP. Therefore, no changes are wet-mate connectors, and all stabs be needed to paragraph (g). exempted from the test. Summary of comments: Comments • Response: BSEE agrees with most of were submitted on the proposed Comments Related to Proposed the commenters’ concerns and has requirements in § 250.738(p) for § 250.738(j)—Removing the BOP Stack revised final § 250.738(l) by replacing tripping the BOP and bottom hole Summary of Comments: One that entire paragraph with a requirement assembly positioning. Most commenters comment was submitted on the that the wellhead/BOP connection must raised concerns about the requirement proposed requirement in § 250.738(j) to be tested to the MASP plus 500 psi for to ensure well stability for 30 minutes remove the BOP stack. The commenter the hole section to which it is exposed, prior to positioning the bottom hole requested that the requirement to have and providing that this can be done by: assembly. They stated that determining

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stable well conditions should not be present during the inspection. In paragraph (a) to satisfy the BOP regulated to a prescribed time addition, the final rule requires frequent maintenance and inspection requirement, and that other methods visual inspections of all BOPs, and that requirements of this provision. should be permitted, such as flow personnel who maintain, inspect, or Comments Related to Proposed checks, tripping volumes, or well repair BOPs or other critical § 250.739(b)—BOP Breakdown and monitoring. Comments were also raised components meet certain training Inspection about the using the term ‘‘immediate’’ criteria. BSEE has revised proposed with regard to removing the bottom hole § 250.739 in the final rule as discussed Summary of comments: Multiple assembly from across the BOP in the in the comment responses for this commenters expressed concerns with event of a well control or emergency section and in part V.C of this the 5-year testing provision in proposed situation. The commenters’ suggestions document. § 250.739(b), which would have for revision to paragraph (p) included required complete breakdown and Comments Related to Proposed deleting the word ‘‘immediate’’ and inspection of the BOP system and every § 250.739(a)—Critical Components and stating in the well-control plan that associated component at one time. Most Recognized Engineering Practices removing non-shearables from across industry commenters did not object to a the BOP stack is to be done as efficiently Summary of comments: Several 5-year inspection requirement for each as possible without jeopardizing the commenters requested clarification of BOP component, provided that the safety of personnel. The comment the phrases ‘‘critical components’’ and inspections could be staggered, or recommended that this removal occur ‘‘recognized engineering practices and phased, over time, as provided in API prior to positioning the bottom hole industry standards’’ in proposed Standard 53. Commenters expressed assembly into the BOP. Another § 250.739(a), stating that the terms are concern that requiring all components comment recommended that this vague and open to inconsistent to be inspected at one time would put provision require a minimum 5-minute interpretation. They also requested a too many rigs out of service, potentially flow check on the trip tank to confirm description of what the deliverables for long periods of time, with that the well is not flowing, after which would be for conformance to API substantial economic impacts. • the bottom hole assembly may be Standard 53. Several commenters Response: BSEE agrees with the tripped through the BOP. requested that BSEE revise paragraph (a) commenters’ concerns about performing • Response: BSEE agrees with most of to require that operators maintain and the 5-year major inspection of the entire the commenters’ suggestions and has inspect their BOP systems, as defined in BOP system and all components at one revised final § 250.738(p) by removing API Standard 53 1.1.2, to ensure that the time. Accordingly, BSEE has revised the reference to the 30 minute equipment functions as designed. The final § 250.739(b) by: Allowing the timeframe and deleting the word commenters also suggested that all BOP complete breakdown and inspection to ‘‘immediate’’ before ‘‘removal of the maintenance and inspections must meet be performed in phased intervals; bottom hole assembly.’’ BSEE the equipment owner’s preventative adding clarification that all system and recognizes there are many suitable maintenance program, and that component inspection dates must be methods to ensure that a well is stable, operators must: Document how they met tracked, documented, and available on as the comments suggested. BSEE or exceeded the provisions of API the rig; and including new paragraphs understands that, for every well, the Standard 53; maintain complete records (b)(1), (2), and (3) describing the types bottom hole assembly will be across the to ensure the required traceability of the of actions that could be used as start BOP stack, and it is BSEE’s intention to equipment; and record the results of the dates for the inspection intervals. The ensure that there are procedures in inspections and maintenance actions; final regulatory language will allow a place to limit this exposure across the and make all records available to BSEE phased approach, as long as there is BOP stack at some point. BSEE removed upon request. proper documentation and tracking to ‘‘immediate’’ from the regulatory text to • Response: BSEE agrees with the ensure that BSEE can verify that each enable appropriate actions to be taken to comment about defining all critical applicable component has had a major make sure the well is secure and to components and has revised final inspection within the preceding 5 years. ensure safety. § 250.739(a) by replacing ‘‘all critical Proper documentation will improve components’’ with ‘‘BOP stack BSEE oversight, as compared to current What are the BOP maintenance and equipment.’’ However, BSEE does not practice, while a phased approach inspection requirements? (§ 250.739) agree with the commenters’ would avoid the possibility of long shut As provided for in the proposed rule, recommendation for revisions to downs. BSEE added the list of actions this section combines and revises paragraph (a) concerning the references that can be used to start the 5-year requirements from several sections of to API Standard 53 and owners’ timeframe, which are consistent with the existing regulations regarding preventative maintenance programs. API Standard 53, to provide additional maintenance and inspection of BOPs. This section already requires the BOP clarity. This section now requires BOP maintenance and inspections to meet or maintenance and inspection procedures exceed API Standard 53. Thus, the Comments Related to Proposed to meet or exceed OEM commenters’ proposed reference to the § 250.739(d)—Personnel Training recommendations, recognized owner’s preventative maintenance Summary of comments: Several engineering practices, and industry program would not be appropriate. commenters raised concern with the standards incorporated by reference into BSEE is aware of major differences proposed § 250.739(d) training the regulations. It also establishes between different owners’ preventative requirements, stating that: BOP procedures for a complete breakdown maintenance programs. BSEE realizes equipment OEMs do not specify and inspection of the BOP and that such programs are useful to help qualification and training criteria; OEM associated components every 5 years, plan and ensure maintenance and training courses do not address every which can be done in phased intervals inspections are completed. But due to aspect of maintenance and (a change from the proposed rule), and the differences between company- troubleshooting that is encountered in requires that the inspection be specific programs, BSEE cannot rely on the field; and training is covered under documented and that a BAVO be a reference to such programs in the SEMS program requirements.

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Commenters suggested revisions to the equipment owner may have design reference to real-time monitoring data, proposed § 250.739(d), including modification records. BSEE understands ‘‘as required by § 250.724.’’ requiring: Personnel who maintain, that the equipment schematics are BSEE also disagrees with the inspect, or repair BOPs or other critical usually made available by OEMs. Under suggestion that paragraph (a) be limited components to meet the qualifications the revised language, the operator is to ‘‘well data’’ (presumably because the and training criteria specified by the only responsible for ensuring that the commenter believed that the revision equipment owner; consideration of schematics and other specific records would eliminate the need to retain OEM guidelines; and performing are located onshore (given that records records onshore related to ‘‘remote’’ maintenance, inspection, and repair in located on the rig unit may become RTM). Section 250.724 requires that accordance with API Standard 53. inaccessible or lost in the event of an RTM data be gathered offshore to be • Response: BSEE agrees with several emergency), whether or not the onshore transmitted to an onshore location. of the suggestions in these comments location for each of the relevant records BSEE may need to review the RTM data and has revised final § 250.739(d) by is the operator’s, equipment owner’s, or at the onshore location if there is an requiring that personnel be trained in the OEM’s. incident. Similarly, BSEE may need to accordance with all applicable training Records and Reporting review the retained RTM data onshore requirements in subpart S, any after an incident, in order to verify applicable OEM criteria, recognized What records must I keep? (§ 250.740) conditions at the time of the incident engineering practices, and industry and to assist in an incident standards incorporated by reference in As provided for in the proposed rule, investigation. If the commenter’s final subpart G. These revisions, made this section incorporates and clarifies suggested revision was intended to limit in response to the comments, clarify recordkeeping requirements from former the data BSEE can review onshore, then BSEE’s intent to ensure that all § 250.466 applicable to all operations BSEE rejects that suggestion. personnel are trained properly for the covered under final subpart G. This equipment that they will maintain, section requires that well records, Comments Related to Proposed inspect, or repair. including a daily report for each well, § 250.740(d)—Kind, Weight, Size, Grade, must be kept onsite during well and Setting Depth of Casing Comments Related to Proposed operations. Well records must include, § 250.739(e)—Retention of Equipment Summary of comments: Commenters among other things, complete Design Records recommended that BSEE clarify the information on: Well operations, all Summary of comments: Several information required by proposed tests conducted, and RTM data; oil, gas § 250.740(d), regarding records on kind, commenters raised concerns with the and mineral deposits encountered; retention of equipment design records weight, size, grade, and setting depth of casings; and significant malfunctions or casing. The comments suggested that proposed in § 250.739(e) and suggested problems. BSEE has revised proposed alternative language. Commenters stated BSEE revise paragraph (d) to read: § 250.740 in the final rule as discussed ‘‘Information relative to casing and that equipment designs are proprietary in the comment responses for this information of the OEM; therefore, the cementing such as weight, size, grade, section and in part V.C of this and setting depth of casing and volume design records can only be retained by document. the OEM. Further, commenters stated and type of cement pumped along with that retention of this information is Comments Related to Proposed cementing pressures and required by the OEM to meet API § 250.740(a)—RTM and Well Data displacements.’’ manufacturing specifications. • Response: BSEE does not agree that Summary of comments: A commenter Commenters also stated that the revision suggested by the modifications to the functional design of contested the RTM aspects of the rule in commenters is necessary or would the stack are maintained by the proposed § 250.740(a). This commenter provide any additional clarity for this equipment owner; therefore, it should indicated that BSEE uses ‘‘real-time recordkeeping requirement. The scope be the responsibility of the equipment monitoring’’ to encompass both well- of these records is already clarified by owner to maintain all required records. site and remote monitoring at an the detailed requirements in final • Response: BSEE agrees with the onshore location, which are two § 250.415(a)(3) regarding information commenters’ concerns about retention separate activities. The commenter about cementing and casing programs of equipment design records and has stated that well-site monitoring is a that must be provided in APDs. BSEE revised the last sentence in final standard practice, whereas remote expects that records specified in § 250.739(e) to require that the operator monitoring is not. The commenter § 250.740(d) will include the ensure that all equipment schematics, recommended replacing ‘‘real-time information specified in § 250.415(a)(3). maintenance, inspection, and repair monitoring data’’ with ‘‘well data.’’ Comments Related to Proposed records are located at an onshore Another commenter asked whether this § 250.740(f)—Any Significant location for the service life of the provision would require additional Malfunction or Problem equipment. BSEE understands that the RTM (presumably beyond what equipment OEMs may retain proprietary proposed § 250.724 would require). Summary of comments: A commenter design documents that are not available • Response: BSEE disagrees with the asserted that the requirement in to others. Therefore, BSEE replaced suggestion to remove the reference in proposed § 250.740(f) regarding ‘‘design’’ with ‘‘schematics’’ and revised paragraph (a) to the RTM data. BSEE is recordkeeping for ‘‘any significant the operator’s responsibility from requiring RTM data in final § 250.724, malfunction or problem’’ is ambiguous. ‘‘maintaining’’ design records to and § 250.740(a) is intended to require This commenter recommended that ‘‘ensuring’’ that the equipment operators to preserve the RTM data BSEE provide some examples of what schematics, and other specified records, collected pursuant to § 250.724. BSEE is type of malfunction or problem for are kept at an onshore location. These not imposing additional RTM which it suggests keeping records, revisions will address the commenters’ obligations beyond those required in noting that there is already a concerns that only the OEM may have § 250.724. To clarify that point, BSEE requirement for equipment failure the original design records and that only has added to final § 250.740(a), after the reporting, and that well-control events

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and other drilling-related problems are the specific well and operations, its and liner pressure tests, diverter tests, documented in the daily well reports. geological conditions and related and RTM data—for 2 years is not • Response: BSEE does not agree that circumstances, and any significant necessary on a decommissioning this provision is ambiguous or that the problems or malfunctions. Accordingly, operation after the well has been recordkeeping required by § 250.740(f) BSEE has revised final § 250.740(g) to plugged, although the commenter is duplicative of other reporting clarify the scope and purpose of the acknowledged that the information may requirements in this rule. Although District Manager’s authority. need to be kept longer in the event of there are several specific reporting a re-drill or sidetrack. Another How long must I keep records? requirements in this rule for subjects commenter recommended that BSEE (§ 250.741) similar to the records required by revise paragraph (b) to require the § 250.740(f) (e.g., § 250.738(a) requires As provided for in the proposed rule, operator to retain BOP RTM data while reporting of irregularities or problems this section incorporates the same conducting operations on the well, and resulting from pressure testing), there requirements as former § 250.467 require the owner of the equipment to are no specific record keeping regarding how long records related to retain the BOP data for a period of 2 requirements for all significant drilling, casing and liner pressure tests, years. malfunctions or problems. BSEE needs diverter and BOP tests, and completion • Response: The record retention to ensure that records of all significant and workover activities must be kept. requirements in final § 250.741(b) are malfunctions or problems are This section also requires that records well established under former § 250.467, maintained so that BSEE can review the related to RTM data must be kept for 2 and BSEE is unaware of any problems records as needed to assist in the years after completion of operations. with those record retention investigation of any incident or There are no changes to this proposed requirements with respect to significant problem. The requirements section in the final rule. decommissioning operations. In addition, the commenter that suggested for reporting specific events to BSEE, or Comments Related to Proposed for keeping other records, does not revising the proposed requirement for § 250.741—Electronic Recordkeeping duplicate the recordkeeping under retention of RTM data did not provide § 250.740(f) since copies of reports or Summary of comments: A commenter any support for that suggestion. And records under other provisions can be recommended that BSEE revise BSEE, based on its experience with the used to satisfy § 250.740(f). Therefore, §§ 250.467 and 250.741 to require longstanding records retention BSEE has not made any changes to that records to be kept in electronic form for requirements for the test data specified paragraph. the life of the well. Longer record in former § 250.467(b), sees no reason retention periods will ensure that Comments Related to Proposed why the operator should not retain RTM important records are maintained and data for 2 years. Therefore, BSEE has not § 250.740(g)—Information Required by available to the operator and BSEE for the District Manager made the suggested changes to final future work on the well or during an § 250.741. Summary of comments: Commenters investigation. requested that BSEE revise proposed • Response: BSEE disagrees with the What well records am I required to § 250.740(g) to clarify what additional commenter that all of the records submit? (§ 250.742) information may be required and to identified in § 250.741 (which replaces This section contains requirements define the scope of the District former § 250.467) should be required to from former § 250.468 regarding Manager’s authority to request be kept for the life of the well. BSEE submission to BSEE of records related to additional records. These commenters already requires that certain data be well-logging operations, certain well suggested defining the scope of retained for the life of the well, as in surveys, velocity profiles, and core information requests as information final § 250.741(c). BSEE determined that analyses. The remainder of the sought ‘‘in the interests of resource the specific retention timeframes for the requirements from former § 250.468, evaluation, waste prevention, information listed in § 250.741(a) regarding well activity reporting, are conservation of natural resources, and through (c) are reasonable and included in final § 250.743. BSEE the protection of correlative rights, appropriate for the purpose of allowing received no substantive comments on safety, and environment.’’ BSEE to review the information in the this provision of the proposed rule and • Response: Like similar provisions event of an incident or investigation or made no changes to the proposed throughout 30 CFR part 250, to determine compliance with language. § 250.740(g) is intended to give District requirements of this subpart. Those Managers the necessary flexibility and timeframes are identical to those in the What are the well activity reporting discretion to require additional former § 250.467 (with the exception of requirements? (§ 250.743) information as needed in specific cases the new requirement for RTM data), As provided for in the proposed rule, to fulfill the purposes of the regulation. which has been in effect for many years, this section includes requirements from Of course, the District Managers must and BSEE is not aware of any instances former § 250.468(b) and (c) regarding exercise that discretion in a manner in which those timeframes have proven submission of WARs for drilling consistent with BSEE’s statutory inadequate. Accordingly, BSEE does not operations in the GOM and Pacific or authority and responsibility under see a need at this time for expanding Alaska regions, respectively. It also OCSLA, including—as the commenter those timeframes as suggested by the codifies reporting procedures contained suggested—conservation of natural commenter. in BSEE NTL 2009–G20, Standard resources and protection of safety and Reporting Period for the Well Activity the environment on the OCS. In Comments Related to Proposed Report, and BSEE NTL 2009–G21, addition, the District Manager must § 250.741(b)—Casing and Liner Pressure Standard Conditions of Approval for exercise the discretionary authority of Tests, Diverter Tests, BOP Tests, and Well Activities. paragraph (g) in a way that serves the RTM Data BSEE will rescind any NTLs that are purpose of § 250.740; i.e., the Summary of comments: A commenter superseded by this section in the final maintenance of records for each well asserted that retention of the identified rule. BSEE received no substantive that provide relevant information about records under § 250.741(b)—i.e., casing comments on this provision of the

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proposed rule and made no changes to pressure testing required in final in the Gulf region and on a daily basis the proposed language. § 250.737(c). in the Alaska region. What are the end of operation reporting Comments Related to Proposed BSEE also agrees with the comment requirements? (§ 250.744) § 250.746(d)—Identification on the that it is not necessary, and in some Daily Report of the Control Station and cases may be imprudent, to suspend As described in the proposed rule, Pod Used During a BOP Test operations for ‘‘any problems’’ and this section combines provisions from Summary of comments: Commenters revised § 250.746(e) to state that ‘‘[i]f several sections of the existing any problems that cannot be resolved regulations, codifies certain procedures observed that the requirement in proposed § 250.746(d)—requiring promptly are observed during from NTL 2009–G21, Standard testing. . .’’ you must suspend Conditions of Approval for Well identification on the daily report of the operations. This change will limit the Activities, and clarifies the contents of control station and pod used during a amount of shut-ins that might have the EOR (Form BSEE–0125). This BOP test—apparently applies to all occurred under the proposed language information provides BSEE with types of operations; however, pods are even though the problem could have important well data and a better not found on equipment (such as been resolved before posing any understanding of the well operations surface stacks, coiled tubing units, and and conditions. BSEE received no snubbing units) associated with certain significant risk. The problem should be substantive comments on this provision operations. The commenters suggested evaluated first, and then, if it is of the proposed rule and made no that BSEE revise this paragraph to determined that repairs or other changes to the proposed language. address this concern. resolution are necessary and cannot be • Response: BSEE disagrees with the completed promptly, operations must be What other well records could I be comment. It is BSEE’s intention that the suspended. required to submit? (§ 250.745) requirement to identify the pod used BSEE has also deleted the phrase ‘‘are during testing applies only to testing As provided for in the proposed rule, considered problems or irregularities that actually uses a pod; in fact the this section incorporates the and’’ from final § 250.746(e) because not proposed and final § 250.746(d) provide requirements of former § 250.469 examples of equipment (i.e., coiled all leaks are considered problems and regarding well records that a District tubing and snubbing units) that would some leaks may not affect BOP system Manager or Regional Supervisor may not require identification of a pod. operability. require an operator to submit. BSEE BSEE is not specifically defining what received no substantive comments on Comments Related to Proposed a BOP ‘‘control system’’ consists of, § 250.746(e)—Notifying the District this provision of the proposed rule and however, BSEE does not want to limit Manager of Leaks has made no changes to the proposed an operator that may have elements in language. Summary of comments: Commenters its control system that are not typically What are the recordkeeping stressed that the proposed requirement found in other BOP control systems. In requirements for casing, liner, and BOP under § 250.746(e) to immediately general, however, BSEE expects that tests, and inspections of BOP systems notify the District Manager of any leaks most BOP control systems will be and marine risers? (§ 250.746) associated with BOP or control system consistent with API Standard 53’s testing is unnecessary, especially for description of that term. As described in the proposed rule, equipment failures during BOP testing. this section combines and clarifies Other commenters asserted that the Comments Related to Proposed requirements from several sections of proposal to suspend operations when § 250.746(f)—Record Retention the existing regulations regarding any problems or irregularities are Summary of comments: A commenter recordkeeping for testing of casings, observed during testing may be unsafe, recommended that, under proposed liners and BOPs and for BOP and and that operators need to be able to § 250.746(f), BSEE not require the marine riser inspections. It also handle minor problems and issues records for pressure testing to be kept on specifies information that must be internally. Commenters requested that included in the daily report. BSEE has BSEE clarify under what circumstances the rig/facility after the operation has made certain revisions to proposed leaks are considered problems. A concluded. Rather, the operator should § 250.746 in the final rule as discussed commenter also requested that BSEE keep these records at an alternative in the comment responses for this clarify what components are included in location (office, records storage facility). section and in part V.C of this ‘‘BOP Control Systems’’ and • Response: BSEE has not made the document. recommended rewording the commenter’s suggested revision to this Comments Related to Proposed requirement for reporting ‘‘any leaks’’ section because the documentation may §§ 250.746(a) and (b)—Test Pressure associated with BOP or control system be necessary and must be available on Records and Pressure Charts testing to require reporting of the rig for incident investigation and ‘‘unresolved leaks’’ associated with such auditing purposes. Summary of comments: A commenter testing. recommended revising § 250.746(a) and • Response: BSEE agrees with the Subpart P—Sulfur Operations (b)—regarding test pressure records and commenters’ suggestion regarding the Well-Control Drills (§ 250.1612) pressure charts—to allow the use of requirement for ‘‘immediate’’ digital recorders as these are also an notification to the District Manager of As provided for in the proposed rule, acceptable method for recording any leaks and revised final § 250.746(e) this section updates the references for pressure tests. by removing that requirement. This the drilling crew requirements under • Response: BSEE agrees with the proposed notification is unnecessary final § 250.711. BSEE received no commenter and revised final because the same information must be substantive comments on this provision § 250.746(a) and (b) to include digital documented in the WAR, which former of the proposed rule and has made no recorders. This change also aligns these § 250.468 and final § 250.743 require to changes to the proposed language in the provisions more closely with the digital be submitted to BSEE on a weekly basis final rule.

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Subpart Q—Decommissioning updating the applicable citations. Also How must I permanently plug a well? Activities paragraph (h) clarifies when operators (§ 250.1715) must submit an EOR rather than an What are the general requirements for As provided for in the proposed rule, APM. BSEE received no substantive decommissioning? (§ 250.1703) BSEE proposed to revise paragraph comments on this provision of the (a)(3)(iii)(B) of existing § 250.1715 to As provided for in the proposed rule, proposed rule and made no changes to require that ‘‘casing’’ bridge plugs must paragraph (b) of existing § 250.1703 the proposed language in the final rule. includes a new requirement that all be set 50 to 100 feet above the top of the permanent packers and bridge plugs What BOP information must I submit? perforated interval. After consideration must comply with API Spec. 11D1. It (§ 250.1705) of comments on the proposed rule, also requires that decommissioning BSEE has made no changes to the As provided for in the proposed rule, proposed language in the final rule. operations must follow all applicable this section is removed and reserved. requirements in new Subpart G. BSEE The content of this former section is Comments Related to Proposed has revised paragraph (b) in the final moved to final §§ 250.731 and 250.732. § 250.1715—Abandonment and rule as discussed in the comment BSEE received no comments on the Isolating Zones responses for this section and in part proposed removal and reservation of V.C of this document. Summary of comments: A commenter this section and the final rule suggested revising § 250.1715 to add Comments Related to Proposed implements that action. new regulatory requirements for § 250.1703(b)—Temporary Packers and Coiled Tubing and Snubbing Operations abandonment and isolating zones. Bridge Plugs (§ 250.1706) • Response: This comment and the suggested revision to § 250.1715 are Summary of comments: Commenters This section of the existing regulation stated that, under proposed § 250.1703, outside the scope of this rulemaking, was titled ‘‘What are the requirements and the suggested changes are not compliance with API Spec. 11D1 should for blowout prevention equipment?’’ As not be required for temporary packers necessary or appropriate for provided for in the proposed rule, this consideration at this time. and bridge plugs (i.e., those used for section is re-titled and moves well servicing). Commenters stressed paragraphs (a) through (e) of the former After I permanently plug a well, what that API Spec. 11D1 does not apply to section to final §§ 250.730, 250.733, information must I submit? (§ 250.1717) temporary packers and bridge plugs. 250.734, and 250.735. Remaining • Response: BSEE agrees with the This section is removed and reserved. paragraphs (f) through (h) of the existing commenters that this section should The content of this former section is regulation are redesignated as apply only to permanently installed moved to final § 250.744. BSEE received paragraphs (a) through (c). BSEE packers and bridge plugs and has no comments on the proposed removal received no substantive comments on revised final § 250.1703 accordingly. and reservation of this section and the this provision of the proposed rule and final rule implements that action. Comments Related to Proposed made no changes to the proposed § 250.1703(f)—Well Abandonment language in the final rule. If I temporarily abandon a well that I plan to re-enter, what must I do? Summary of comments: A commenter What are the requirements for blowout (§ 250.1721) noted that § 250.1703(f) adds a reference preventer system testing, records, and to the requirements of new subpart G, drills? (§ 250.1707) As provided for in the proposed rule, which would make subpart G applicable paragraph (g) is removed from existing to decommissioning. The commenter This section is removed and reserved. § 250.1721 and former paragraph (h) is noted that well abandonments are As described in the proposed rule, the redesignated as paragraph (g). The normally considered as part of the plan content of this former section is moved content of former paragraph (g)— only for exploration programs and not to final §§ 250.711, 250.736, 250.737, regarding submission of an APM within development programs. and 250.746. BSEE received no 30 days after temporarily plugging a • Response: BSEE does not agree with comments on the proposed removal and well—has been moved to final this comment, and has not made the reservation of this section and the final § 250.744. BSEE received no substantive suggested changes to § 250.1703 in the rule implements that action. comments on this provision of the final rule, because some of the What are my BOP inspection and proposed rule and made no changes to equipment used in drilling, workover, maintenance requirements? (§ 250.1708) the proposed language in the final rule. and completion operations is also used for decommissioning (e.g., MODUs and This section is removed and reserved. VII. Derivation Tables BOPs). That equipment must meet the As provided for in the proposed rule, The following tables are intended to requirements necessary to ensure safety the content of this former section is provide information about the and environmental protection without moved to final § 250.739. BSEE received derivation of new requirements in regard to the types of well operations in no comments on the proposed removal subparts A, B, D, E, F, G, P, and Q of which the equipment is used. and reservation of this section and the part 250. These tables illustrate: final rule implements that action. When must I submit decommissioning — The destination of various current applications and reports? (§ 250.1704) What are my well-control fluid requirements. requirements? (§ 250.1709) — The organization and content of the As provided for in the proposed rule, revisions. paragraph (g) of existing § 250.1704 is This section is removed and reserved. revised by removing current paragraphs As provided for in the proposed rule, These tables do not provide definitive (g)(2), (4), and (6) and the associated the content of this former section is or exhaustive guidance, and should be instructions in the third column, as well moved to final § 250.720. BSEE received used as reference material and in as by revising the numbering of current no comments on the proposed removal conjunction with the section-by-section paragraphs (g)(3) and (5) to paragraphs and reservation of this section and the discussion and regulatory text of this (g)(2) and (3), respectively, and by final rule implements that action. rule.

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The following sections in 30 CFR part [Removed and/or Reserved] according to 250, subparts D, E, F, and Q have been the following table.

Subpart Removed and/or reserved in 30 CFR part 250

D ...... 401, 402, 403, 406, 417, 424, 425, 426, 440 through 451, 466 through 469. E ...... 502, 506 through 508, 515 through 517. F ...... 602, 606 through 608, 615, 617, 618. Q ...... 1705, 1707 through 1709, 1717.

The rule makes changes as outlined in the following table: BILLING CODE 4310–VH–C

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Prior Regulations New Rule Section Nature of Change Section (k) to help ensure the well's structural integrity and submission of any additional information required by the District Manager. 250.415(a) 250.415(a) Revised paragraph (a) for casing information in all sections for each casing interval. 250.416 250.416(a), (b); Revised to remove only the BOP 250. 730; 250.731; descriptions in the regulatory text 250.732 and section heading. 250.417 250.713 Removed - similar language found in new subpart G. 250.418(g) 250.418(g) Revised to include a description of how far below the mudline the operator proposes to displace cement in the request for approval; revised citation. 250.420 250.420 Revised the introductory paragraph to include applicable casing and cementing requirements in subpart G; added new paragraph (a)(6) to require adequate centralization to ensure proper cementation; added new paragraph (b)(4) requiring District Manager approval before installing a different casing than what was approved in the APD; modified paragraph (c) requiring the use of a weighted fluid. 250.421 250.421(b) and (f) Revised paragraph (b) so casing would have to be set immediately and set above the encountered zone, even if it is before the planned casing point if oil or gas or unexpected formation pressure arises. Revised paragraph (f) to no longer allow liners to be installed as conductor casing. 250.423 250.423 Revised the section heading and removed the pressure testing and negative pressure testing requirements; added clarification about latching mechanisms. Edited the remaining paragraphs of

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Prior Regulations New Rule Section Nature of Change Section § 250.423 for organization. 250.423(a) and (c) 250.721 Removed - similar language found in new subpart G. 250.424 250.722 Removed - similar language found in new subpart G. 250.425 250.721 Removed - similar language found in new subpart G. 250.426 250.746 Removed - similar language found in new subpart G. 250.427(b) 250.427(b) Revised paragraph (b) to clarify that operators must maintain a safe drilling margin. 250.428 250.428 Revised paragraphs (b) through (d). Paragraph (b) requires approval for hole interval drilling depth changes greater than 100 ft. TVD, and the submittal of aPE certification that the certifying PE reviewed and approved the proposed changes; paragraph (c) clarifies requirements when there is any indication of an inadequate cement job; and paragraph (d) clarifies that if there is an inadequate cement job, the District Manager has to review and approve all remedial actions; that the changes to the well program are reviewed, approved, and certified by a PE; and any other requirements of the District Manager. New paragraph (k) adds requirements concerning the use of valves on drive pipe during cementing operations. 250.440 250.730 Removed - similar language found in new subpart G. 250.441 250.733; 250.735 Removed - similar language found in new subpart G.

250.442 250.734 Removed - similar language found in new subpart G. 250.443 250.734; 250.735 Removed - similar language found in new Subpart G.

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Prior Regulations New Rule Section Nature of Change Section 250.443(c) and (d) 250.733 Removed - similar language found in new subpart G. 250.444 250.736 Removed - similar language found in new subpart G. 250.445 250.736 Removed - similar language found in new subpart G. 250.446 250.739 Removed - similar language found in new subpart G. 250.447 250.737 Removed - similar language found in new subpart G. 250.448 250.737 Removed - similar language found in new subpart G. 250.449 250.737 Removed - similar language found in new subpart G. 250.450 250.746 Removed - similar language found in new subpart G. 250.451 250.738 Removed - similar language found in new subpart G. 250.456(k) 250.456(i) Redesignated. 250.456G) 250.720 Removed - similar language found in new subpart G. NEW 250.462 New section heading and requirements to demonstrate deepwater well containment. 250.462 250.710 and 250.711 Removed heading and requirements for well-control drills - similar language found in new subpart G. 250.465(b)(3) 250.465(b)(3) This paragraph was revised to update the citation for the EOR form, BSEE-0125. 250.466 250.740 Removed - similar language found in new subpart G. 250.467 250.741 Removed - similar language found in new subpart G. 250.468(a) 250.742 Removed - similar language found in new subpart G.

250.468(b) and (c) 250.743 Removed - similar language found in new subpart G. 250.469 250.745 Removed - similar language found in new subpart G. Subpart E 250.500 250.500 Revised section heading and

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Prior Regulations New Rule Section Nature of Change Section requirements to encompass General Requirements and direct compliance with new subpart G where applicable. 250.502 250.723 Removed - similar language found in new subpart G. 250.506 250.710 Removed - similar language found in new subpart G. 250.514(d) 250.720 Removed - similar language found in new subpart G. 250.515 250.731; 250.732 Removed - similar language found in new subpart G. 250.516 250.730; 250.733; Removed - similar language found 250.734; 250.735; in new subpart G. 250.736 250.517 250.711; 250.737, Removed - similar language found 250.738, 250.739; in new subpart G. 250.746 250.518 250.518(e), (f) Removed paragraph (b) and redesignated the remaining paragraphs. Added new paragraphs (e) and (f) to add API Spec. 11D1, packer and bridge plug requirements, and a description of calculations of packer setting depth. 250.518(b) 250.722 Redesignated and revised to include additional requirements for prolonged operations. Subpart F 250.600 250.600 Revised section heading and requirements to encompass General Requirements and direct compliance with new subpart G where applicable.

250.602 250.723 Removed - similar language found in new subpart G. 250.606 250.710 Removed - similar language found in new subpart G. 250.614(d) 250.720 Removed - similar language found in new subpart G. 250.615 250.731; 250.732 Removed - similar language found in new subpart G.

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Prior Regulations New Rule Section Nature of Change Section 250.616(a) through (e) 250.730; 250.733; Removed - similar language found 250.734; 250.735; in new subpart G. 250.736 250.616(f) through (h) 250.616(a) through (c) Redesignated with no changes made to regulatory text. 250.617 250.711; 250.737; Removed - similar language found 250.746 in new subpart G. 250.618 250.739 Removed - similar language found in new subpart G. 250.619 250.619 Removed paragraph (b) and redesignated the section. Added new paragraphs (e) and (f) to add packers and bridge plug requirements, API Spec. llDl, and a description of calculations of packer setting depth. 250.619(b) 250.722 Redesignated and revised to include additional requirements for prolonged operations. New Subpart G General requirements NEW 250.700 New section describing what operations and equipment are subject to the requirements. 250.408 250.701 Similar language pertaining to alternative procedures or equipment. 250.409 250.702 Similar language pertaining to departures. 250.401 250.703 Similar language containing requirements to keep wells under control.

Rig Requirements 250.462; 250.506; 250.710 Similar language was revised and 250.606 incorporated into this section about instructions for rig personnel. 250.462; 250.517; 250.711 Similar language was revised and 250.617; 250.1707 incorporated into this section about well-control drills. 250.403 250.712 Similar language was revised and incorporated into this section about rig movement notifications.

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Prior Regulations New Rule Section Nature of Change Section 250.417 250.713 Similar language was revised and incorporated into this section about MODUs or lift boat requirements for well operations. NEW 250.714 New section about dropped objects plans. NEW 250.715 New section about GPS for MODUs and jack-ups. Well Operations 250.402; 250.4560); 250.720 Similar language was revised and 250.514(d); incorporated into this section about 250.614(d); 250.1709 securing a well. 250.423(a), (c); 250.721 Similar language was revised and 250.425 incorporated into this section about pressure testing casing and liners. 250.424; 250.518; 250.722 Similar language was revised and 250.619 incorporated into this section pertaining to prolonged well operations. 250.406; 250.502; 250.723 Similar language from§§ 250.406, 250.602 250.502, and 250.602 was revised and incorporated into this section relating to safety measures on a platform producing wells or other hydrocarbon flow. NEW 250.724 New section relating to RTM requirements. Blowout Preventer (BOP) System Requirements 250.416; 250.440; 250.730 Similar language was revised and 250.516; 250.616(a) incorporated into this section about through (e); 250.1706 general requirements for BOP systems and their components. 250.416; 250.515; 250.731 Similar language was revised and 250.615; 250.1705 incorporated into this section about submittal requirements for information about BOP systems and their components. 250.416; 250.515; 250.732 Similar language was revised and 250.615; 250.1705 incorporated into this section relating to third-party information for BOP systems and their components. 250.441; 250.443(c), 250.733 Similar language was revised and (d); 250.516; incorporated into this section and

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Prior Regulations New Rule Section Nature of Change Section 250.616(a) through (e); new language was added relating 250.1706 to requirements for a surface BOP stack. 250.442; 250.443(c), 250.734 Similar language was revised and (d); 250.516; incorporated into this section and 250.616(a) through (e); new language was added relating 250.1706 to requirements for a subsea BOP system. 250.441; 250.443; 250.735 Similar language was revised and 250.516; 250.616; incorporated to this section and 250.1706 new language was added relating to equipment and systems all BOPs must have. 250.444; 250.445; 250.736 Similar language was revised and 250.516; 250.616(a) incorporated into this section through (e); 250.1707 pertaining to requirements for choke manifolds, kelly valves, inside BOPs, and drill string safety valves. 250.447; 250.448; 250.737 Added new language and similar 250.449; 250.517; language was revised and 250.617; 250.1707 incorporated into this section relating to BOP system testing requirements. 250.451 and 250.517 250.738 Added new language and similar language was revised and incorporated into this section for situations arising involving BOP equipment or systems. 250.446; 250.517; 250.739 Similar language was revised and 250.618; 250.1708 incorporated into this section pertaining to BOP maintenance and inspection requirements. Records and Reporting 250.466 250.740 Redesignated and revised the types of records to keep. 250.467 250.741 Redesignated and added records relating to R TM data. 250.468(a) 250.742 Redesignated. 250.468(b) and (c) 250.743 Redesignated and revised to include more requirements for the well activity reporting. 250.465; 250.1712; 250.744 Redesignated and revised to 250.1717 include additional end of operation

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Prior Regulations New Rule Section Nature of Change Section reporting requirements. 250.469 250.745 Redesignated and revised to update references. 250.426; 250.450; 250.746 Similar language was revised and 250.517; 250.617; incorporated into this section 250.1707 pertaining to recordkeeping for casing, liner, and BOP tests. Subpart P 250.1612 250.1612 Revised to update references. Subpart Q 250.1703 250.1703 Revised paragraph (b) to have new packers and bridge plug requirements, including API Spec. 11D1. Revised paragraph (e); Redesignated existing paragraph (f) as (g); and added a new paragraph (f) to follow the applicable requirements of subpart G. 250.1704 250.1704 Revised paragraphs (g) and added new paragraph (h) about APMs and EORs. 250.1705 250.731,250.732 Removed - similar language found in new subpart G. 250.1706(a) through 250.730; 250.733, Removed - similar language found (e) 250.734, and 250.735 in new subpart G. 250.1706(±) through 250.1706(a) through (c) Revised the section heading; (h) redesignated. 250.1707 250.711, 250.736, Removed - similar language found 250.737, 250.746 in new subpart G. 250.1708 250.739 Removed - similar language found in new subpart G. 250.1709 250.720 Removed - similar language found in new subpart G. 250.1715(a)(3)(iii)(B) 250.1715(a)(3)(iii)(B) Added the word "casing." 250.1717 250.744 Removed - similar language found in new subpart G. 250.1721 (g) 250.744 Removed - similar language found in new subpart G. 250.1721(h) 250.1721(g) Redesignated and text remains unchanged.

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VIII. Procedural Matters 1. Need for Regulation were raised regarding the safety of offshore oil and gas operations and the Regulatory Planning and Review BSEE identified a need to amend the potential for another catastrophic event (Executive Orders (E.O.) 12866 and existing BOP and well-control with consequences similar to those of 13563) regulations to enhance the safety and environmental protection of offshore oil Deepwater Horizon. E.O. 12866 provides that the Office of and gas operations on the OCS. This Alternative 2 (changing the required Information and Regulatory Affairs in final rule creates 30 CFR part 250, frequency of BOP pressure testing to the Office of Management and Budget subpart G—Well Operations and once every 21 days for all operations) (OMB) will review all significant rules. Equipment. This new subpart was not selected because BSEE lacks To determine if this rulemaking is a consolidates equipment and operational critical data on testing frequency and significant rule, BSEE prepared an requirements that are contained in other equipment reliability to choose this economic analysis to assess the subparts of part 250 pertaining to alternative. BSEE has elected to move forward anticipated costs and potential benefits offshore oil and gas drilling, with Alternative 1—the final rule— of the rulemaking. completions, workovers, and which incorporates recommendations decommissioning. The rule also revises Changes to Federal regulations must provided prior to the proposed rule by existing provisions throughout subparts undergo several types of economic government, industry, academia, and D, E, F, and Q of part 250 to address analyses. First, E.O. 12866 and E.O. other stakeholders. However, as concerns raised in the investigations, 13563 direct agencies to assess the costs discussed in detail earlier in this BSEE’s internal reviews, the 2012 BSEE and benefits of regulatory alternatives preamble, the final rule does include public forum and other input from and, if regulation is necessary, to select certain revisions based on BSEE stakeholders and the public. The rule a regulatory approach that maximizes consideration of recommendations addresses and implements multiple net benefits (including potential contained in public comments on the recommendations resulting from various economic, environmental, public health, proposed rule, including incorporation investigations of the Deepwater Horizon and safety effects; distributive impacts; of relevant elements of API Standard 53 incident.21 The rule also incorporates and equity). Under E.O. 12866, an and related standards. In addition to guidance from several NTLs and revises agency must determine whether a addressing concerns and aligning with provisions related to drilling, workover, regulatory action is significant and, industry standards, BSEE is advancing completion, and decommissioning therefore, subject to the requirements of several of the more critical well-control operations to enhance safety and E.O. 12866, including review by OMB. capabilities beyond current industry environmental protection. Section 3(f) of E.O. 12866 defines a standards applicable to BOP systems ‘‘significant regulatory action’’ as any 2. Alternatives based on agency knowledge, experience regulatory action that is likely to result and technical expertise. The rule will in a rule that: BSEE has considered three regulatory alternatives: also improve efficiency and consistency —Has an annual effect on the (1) Promulgate the requirements of the regulations and allow for economy of $100 million or more, or contained in the proposed rule, flexibility in future rulemakings. adversely affects in a material way the including decreasing the BOP pressure economy, a sector of the economy, 3. Economic Analysis testing frequency for workover and productivity, competition, jobs, the BSEE’s initial economic analysis, for decommissioning operations from the environment, public health or safety, or the proposed rule, and final economic current requirement of once every 7 state, local, or tribal governments or analysis evaluated the expected impacts days to once every 14 days; communities (also referred to as of the rule as compared to the baseline, (2) Promulgate the requirements ‘‘economically significant’’); which includes current industry contained within the proposed rule with practices in accordance with existing —Creates serious inconsistency or a change to the required frequency of regulations, DWOPs, and industry otherwise interferes with an action BOP pressure testing from the existing standards with which operators already taken or planned by another agency; regulatory requirements (i.e., once every comply.22 Impacts that exist as part of 7 or 14 days depending upon the type —Materially alters the budgetary the baseline were not considered costs of operation) to once every 21 days for impacts of entitlement grants, user fees, or benefits of the rule. all operations; and loan programs, or the rights and The final analysis covers 10 years (3) Take no regulatory action and obligations of recipients thereof; or (2016 through 2025) to ensure it continue to rely on existing BOP —Raises novel legal or policy issues encompasses the significant costs and regulations in combination with permit arising out of legal mandates, the benefits likely to result from the rule.23 conditions, DWOPs, operator prudence, President’s priorities, or the principles We used a 10-year analysis period and industry standards as applicable to set forth in E.O. 12866. because of the uncertainty associated BOP systems. with predicting industry’s activities and BSEE determined that this rule is a By taking no regulatory action, BSEE significant rulemaking within the would leave unaddressed most of the definition of E.O. 12866 because the 22 BSEE considers compliance with permits, concerns and recommendations that DWOPs, and industry standards to be ‘‘self- estimated annual costs or benefits implementing,’’ as addressed in Section E.2 of OMB would exceed $100 million in at least 21 The DOI JIT report, September 14, 2011, Report Circular A–4, ‘‘Regulatory Analysis’’ (2003), and one year of the 10-year analysis period. Regarding the Causes of the April 20, 2010 thus includes these costs in the baseline for the Accordingly, OMB has reviewed this Macondo Well Blowout; The National Commission economic analysis. The industry standards relevant regulation. final report, January 11, 2011, Deep Water, The Gulf to this rule were developed by committees of Oil Disaster and the Future of Offshore Drilling; The industry members and others and subsequently The following discussion summarizes Chief Counsel for the National Commission report, approved by an industry standards development the economic analysis; for details, February 17, 2011, Macondo The Gulf Oil Disaster; organization (e.g., API). the National Academy of Engineering final report, 23 The initial economic analysis, which please refer to the final RIA, which can December 14, 2011, Macondo Well-Deepwater accompanied the proposed rule published in April be viewed at www.regulations.gov (use Horizon Blowout; May 22, 2012, BSEE Public 2015, also used a 10-year analysis period, from 2015 the keyword/ID ‘‘BSEE–2015–0002’’). Offshore Energy Safety Forum. through 2024.

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the advancement of technical including time savings, reductions in oil is too short, BSEE notes that the capabilities beyond 10 years. When spills, and reductions in fatalities. We uncertainty associated with predicting summarizing the costs and benefits, we estimated the benefits derived from time industry activities, the advancement of present the estimated annual effects, as savings associated with § 250.737 of the technical capabilities, and oil price well as the 10-year discounted totals rule, which streamlines BOP testing for volatility makes it difficult to predict using discount rates of 3 and 7 percent, workover. We also estimated time- costs that would accrue to industry for per OMB Circular A–4, ‘‘Regulatory savings benefits associated with a a timeframe much longer than 10 years. Analysis’’ (2003). change in the required frequency of BOP BSEE also received comments We sought to quantify and monetize pressure testing under Alternative 1 and suggesting that other aspects of the rule the costs of the following provisions: Alternative 2, both of which would should be considered, such as the (a) Additional information in the reduce the number of required BOP broader, indirect economic impacts that description of well drilling design pressure tests per year (by reducing test may occur as a result of the rule. BSEE frequency to once every 14 days and 21 criteria; considered and addressed these (b) Additional information in the days, respectively). In addition, we comments. More details on the public drilling prognosis; estimated the benefits derived from the (c) Prohibition of a liner as conductor reduction in oil spills and fatalities comments on the economic analysis, casing; using the incident-reducing potential of and BSEE’s responses to the comments (d) Additional capping stack testing the rule as a whole. are in part VI.B.6 of this document. requirements; BSEE received comments from the According to the analytical findings, (e) Additional information in the public on various aspects of the the time-savings benefits of the final APM for installed packers; economic analysis of the proposed rule. rule result in benefits greater than the (f) Additional information in the APM Some commenters expressed concerns costs of the rule. In other words, based for pulled and reinstalled packers; about costs that, to them, appeared to be on available data, the rule will be cost- (g) Rig movement reporting; underestimated or not included as beneficial even when only the benefits (h) Fitness requirements for MODUs; impacts of the proposed rule. BSEE resulting from time-savings are (i) Foundation requirements for reviewed these comments and any new considered. MODUs; cost information provided by (j) RTM of well operations for rigs commenters. BSEE then either revised The final rule will result in benefits under certain circumstances (e.g., rigs the analysis as appropriate to reflect this to society by reducing the probability of with a subsea BOP); new information, or retained the incidents involving oil spills. The (k) Additional documentation and original cost estimates and provided a provisions with the highest costs to verification requirements for BOP justification for doing so. With regard to industry (such as RTM requirements for systems and system components; costs that some commenters thought well operations and alternating BOP (l) Additional information in the APD, were missing from the initial economic control station function testing) would APM, or other submittal for BOP analysis, BSEE notes that many of these have the largest impact on reducing systems and system components; costs are actually for items that are spills. Benefits of the rule will result (m) Submission by the operator of an included in the regulatory baseline, and from the avoided costs associated with MIA Report completed by a BAVO; 24 thus are not impacts attributable to the oil spills related to personal injuries, (n) New surface BOP system rule. In addition, comments on costs natural resource damages, lost requirements; were received in reference to some hydrocarbons, spill containment and (o) New subsea BOP system specific requirements in the proposed cleanup, lost recreational opportunities, requirements; rule that have not been retained in the and impacts to commercial fishing. (p) New accumulator system final rule. As a result, many of the To estimate the potential benefits of requirements; comments regarding costs of the the rule associated with reducing the (q) Chart or digital recorders; proposed rule (including but not limited (r) Notification and procedures risk of oil spill incidents, we examined to the potential costs associated with the historical data from the BSEE oil spill requirements for testing of surface BOP proposed accumulator capacity database, which contains information systems; requirements and the proposed for spills greater than 10 barrels of oil (s) Alternating BOP control station mandatory 0.5 ppg safe drilling margin) for the GOM and Pacific regions. Based function testing; are no longer applicable to the (t) ROV intervention function testing; requirements of the final rule. upon an analysis of the BSEE oil spill (u) Autoshear, deadman, and EDS Another issue regarding the initial database during the period 1988 to function testing on subsea BOPs; economic analysis for the proposed rule 2010, BSEE identified LWCs associated (v) Approval for well-control related to requirements on various with oil spills greater than 10 barrels equipment not covered in Subpart G; topics that overlapped with each other. and used this data within the economic (w) Breakdown and inspection of BOP In these cases, a particular cost could be analysis.25 BSEE used 1988 as the systems and components; attributed to multiple topics. As a result, starting year of the analysis because DOI (x) Additional recordkeeping for RTM some comments identified certain costs undertook a comprehensive overhaul of data; as missing in the initial RIA, when, in its offshore regulatory program in that (y) Industry familiarization with the fact, the initial RIA did account for year, which thus provides the most new rule; and those costs under a related topic to relevant context for evaluating the (z) BAVO application costs. which the commenter may not have current state of risk that now exist in BSEE also quantified and monetized attributed the cost. In other cases, OCS offshore operations. The LWCs that the potential benefits of the rule, however, BSEE found comments on resulted in uncontrolled flow of gas, costs to be quite relevant, and made use damage to a rig, and/or harm to 24 A verification organization seeking BSEE’s of the information in those comments to personnel (but not oil spills over 10 approval to become a BAVO is required to submit documentation describing the organization’s revise the final economic analysis. applicable qualification and experience. (See In response to comments expressing 25 Source: http://www.bsee.gov/Inspection-and- § 250.732(a).) concern that the 10-year analysis period Enforcement/Accidents-and-Incidents/Spills/.

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barrels) are not reflected in this Program for 2012–2017’’ (hereafter benefits) in the valuation of an oil spill, analysis.26 referred to as the ‘‘BOEM Case including only selected costs of such a We reviewed the causes of risk Study’’),28 and includes costs associated spill. For example, although the analysis without the rule and how those causes with natural resource damages, the captures the environmental damage of risk would be affected by the rule. In value of lost hydrocarbons, and spill associated with a spill, the analysis is order not to overstate the potential risk cleanup and containment.29 We used a limited because it considers only the reduction, we assumed a 1 percent risk natural resource damage cost of $662 environmental amenities that reduction in the likelihood of all oil per barrel and a cleanup and researchers could identify and 27 spills. We multiplied the expected containment cost of $2,946 per barrel as monetize. Therefore, the resulting annual number of spilled barrels of oil estimated for the GOM in the Bureau of benefits of avoiding a spill should be (based on the observed average of Ocean Energy Management (BOEM) considered as a lower bound estimate of spilled oil per well) by 1 percent to Case Study (both values adjusted to the true benefit to society that results estimate the expected annual reduction 2014 dollars). We assumed a value of from decreasing the risk of oil spills. in barrels of oil spilled associated with lost output per barrel of $50. the rule. Exhibit 1 displays the net benefits of We then multiplied the annual In addition to the time-savings and the rule under the assumption that the reduction in spilled barrels of oil by the risk reduction benefits, the final rule has reduction in the risk of incidents is 1 social and private costs of a spilled other benefits. Due to difficulties in percent. Although BSEE believes the barrel of oil, which is estimated at measuring and monetizing these risk reduction of the rule to be at least $3,658 (in 2014 dollars) per barrel. This benefits, BSEE does not offer a 1 percent, and likely higher, there is estimate was derived from the quantitative assessment of them. BSEE uncertainty around the level of risk ‘‘Economic Analysis Methodology for has used a conservative approach (one reduction the rule would actually the Five Year OCS Oil and Gas Leasing that seeks to avoid over-estimating the achieve.

4. Sensitivity Analysis a. The level of risk reduction of oil of possible annual risk reduction levels spills achieved by the rule, and for oil spills from 0 to 20 percent. The This section presents a sensitivity b. The level of risk reduction of final rule is expected to have positive analysis of the potential benefits of the fatalities achieved by the rule net benefits across the full range of risk rule that could result from varying the Exhibit 2 presents the total 10-year reduction levels. following factors: benefits and net benefits under a range

26 Previous MMS data indicate that there were a M11PC000027), June 2013; ‘‘Improved Regulatory a result of the rule, although in BSEE’s expert total of 154 LWCs during well operations on the Oversight Using Real-Time Data Monitoring opinion, the actual risk reduction from the rule will OCS between 1988 and 2015. These LWCs resulted Technologies in the Wake of Macondo,’’ K. Carter, likely be substantially higher than 1 percent. in 14 fatalities, 55 injuries, damage to facilities and U, of Texas at Austin, 2014, published with E. van 28 U.S. Department of the Interior, BOEM, 2012, equipment, and the release of hydrocarbons. Oort and A Barendrecht, Society of Petroleum Economic Analysis Methodology for the Five Year Engineers, 2014; ‘‘Deepwater Horizon Blowout 27 Several recent studies have estimated the OCS Oil and Gas Leading Program for 2012–2017. Preventer Failure Analysis Report to the U.S. probabilities of blowout failures under a wide range Chemical Safety and Hazard Investigation Board,‘‘ BOEM OCS Study 2012–022. of circumstances. See, e.g., ‘‘Blowout Preventer Engineering Services, LP, 2014. Given this 29 The BOEM Case Study presents per-barrel costs (BOP) Failure Event and Maintenance, Inspection accumulated knowledge of failure likelihoods associated with a catastrophic event. We use this and Test (MIT) Data Analysis for the Bureau of under various circumstances, and analysis of how estimate because the BOEM Case Study represents Safety and Environmental Enforcement (BSEE).’’ those likelihoods would be reduced by the rule, a recent estimate for the costs associated with an American Bureau of Shipping and ABSG BSEE determined that 1 percent is a reasonable oil spill which includes data from the Deepwater Consulting Inc., (under BSEE contract lower-bound of risk reduction that could occur as Horizon incident.

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In addition to the time-savings and The benefits of occupational risk across a range of risk reduction values the prevention of oil spills benefits, the reduction are usually measured using from 0 to 20 percent. The exhibit also rule is anticipated to reduce fatalities the value of a statistical life (VSL). BSEE presents the undiscounted and among rig workers. The oil and gas used a VSL of $8.7 million to estimate discounted 10-year total net benefits extraction industry constitutes a the avoided costs associated with a when fatality risk reduction is relatively small percentage of the reduction in the fatality rate. This is the considered in addition to the benefits of national workforce, but has a fatality EPA-recommended estimate of $7.9 the rule included in the analysis rate that is higher than the rate for most million updated to 2014 dollars. presented above (assuming a 1 percent industries. Exhibit 3 presents the resulting total risk reduction in the probability of 10-year fatality risk reduction benefit incidents involving oil spills).30

30 Between 1964 and 2010, there were 27 LWcs resulted 4 and 11 fatalities, respectively. Based on value of fatalities is $2,691,423 per year. Therefore, resulting in oil spills greater than 10 barrels. Two the 47-year period from 1964 to 2010, the average each 1 percent reduction in the risk of a fatality of these events resulted in fatalities, a 1984 blowout number of fatalities was approximately 0.320 results in a risk reduction benefit of $26,914. and the 2010 Deepwater Horizon incident that annually. Using a VSL of $8,423,301, the average

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BSEE has concluded that, after with 7 percent discounting). (See is based on the amount of risk considering all of the impacts of the Exhibit 1.) reduction. In general, risk can be final rule, the societal benefits justify reduced in two distinct ways: By 5. Probabilistic Risk Assessment the societal costs. In fact, as previously decreasing the probability of the event, explained, BSEE estimates that, over the The benefits (and costs) of a and/or by decreasing the consequences 10-year economic analysis period, the regulation are based on the difference of the event. The evaluation of the quantifiable benefits of the rule (i.e., between the baseline (i.e., status quo) reduction in risk typically can be $1,147 million with 7 percent and the state of the world under the performed in either a deterministic or discounting) will substantially exceed regulation. In relation to safety, probabilistic approach. the quantifiable costs (i.e., $686 million environmental, and security benefits, Historically, BSEE has evaluated the one approach to estimating the benefits reduction of risk based on a

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deterministic approach. A probabilistic blowouts can result in catastrophic concerns raised in the investigations, approach, however, could enhance and consequences.31 The Federal BSEE’s internal reviews, the 2012 BSEE extend more traditional approaches by: government and industry conducted public forum, and other input from (1) Allowing consideration of a broader multiple investigations to determine the stakeholders and the public. The rule set of potential challenges; (2) providing causes of the Deepwater Horizon also incorporates guidance from several a logical means for prioritizing these incident; many of these investigations NTLs and revises provisions related to challenges based on risk significance; identified BOP performance as a drilling, workover, completion, and and (3) allowing consideration of a concern. BSEE convened Federal decommissioning operations to enhance broader set of resources to address these decision-makers and stakeholders from safety and environmental protection. challenges. Probabilistic risk the OCS oil and gas industry, academia, 2. Description and Estimated Number of assessments have been used in some and other entities at a public forum on Small Entities Regulated cases by certain Federal agencies offshore energy safety on May 22, 2012, including the U.S. Nuclear Regulatory to discuss ways to address this concern. Small entities, as defined by the RFA, Commission, DHS, and the National The investigations and the forum consist of small businesses, small Aeronautics and Space Administration. resulted in a set of recommendations to governmental jurisdictions, or other BSEE, however, does not currently improve BOP performance. (see small organizations. This analysis collect data that provides a proposed rule, 80 FR 21508–21511 focuses on impacts to small businesses comprehensive basis for a probabilistic (April 17, 2015).) (hereafter referred to as ‘‘small entities’’) risk model. In addition, BSEE is not As an agency charged with oversight because we have not identified any aware of any current industry-wide of offshore operations conducted on the impacts to small governmental efforts to collect data for such a purpose, OCS, BSEE seeks to improve safety and jurisdictions or to other small although BSEE has requested that the mitigate risks associated with such organizations. A small entity is one that Ocean Energy Safety Institute develop a operations. After careful consideration is independently owned and operated database related to equipment reliability of the various investigations conducted and which is not dominant in its field that might provide useful information after the Deepwater Horizon incident, of operation.32 The definition of small for the future development of a and of industry’s responses to the business varies from industry to probabilistic risk assessment. incident, BSEE has determined that the industry in order to properly reflect industry size differences. Regulatory Flexibility Act requirements contained in this rule are necessary to fulfill BSEE’s statutory The rule will affect operators and The Regulatory Flexibility Act (RFA) responsibility to regulate offshore oil holders of Federal oil and gas leases, as (5 U.S.C. 601 et seq.) requires agencies and gas operations and to enhance the well as right-of-way holders, on the to prepare a regulatory flexibility OCS. This includes 99 businesses with safety of offshore exploration, 33 analysis to determine whether a production, and development. (See 43 active operations. Businesses that regulation can be expected to have a U.S.C. 1347–1348; 30 CFR 250.101.) operate under this rule fall under the significant economic impact on a BSEE has also determined that the BOP SBA’s North American Industry substantial number of small entities. regulations need to be updated to Classification System (NAICS) codes Further, the Small Business Regulatory incorporate certain recommendations as 211111 (Crude Petroleum and Natural Gas Extraction) and 213111 (Drilling Oil Enforcement Fairness Act (SBREFA) at discussed in the preambles to the and Gas Wells). For these NAICS (5 U.S.C. 801 et seq.) requires that an proposed and final rules (e.g., 80 FR classifications, a small business is agency produce compliance guidance 21508–21511), while others are being defined as one with fewer than 501 for small entities if the rule will have a studied for consideration in future employees. Based on these criteria, 50 significant economic impact. For the rulemakings. The rule creates a new (50.51 percent) of the businesses reasons explained in this section, BSEE subpart G in 30 CFR part 250 to operating on the OCS are considered believes that this rule will likely have a consolidate the requirements for small, and the rest are considered large significant economic impact on a drilling, completion, workover, and businesses. BSEE considers that a rule substantial number of small entities decommissioning operations. and, therefore, a regulatory flexibility has an impact on a ‘‘substantial number Consolidating these requirements will of small entities’’ when the total number analysis is required by the RFA. This improve efficiency and consistency of Final Regulatory Flexibility Analysis of small entities impacted by the rule is the regulations and allow for flexibility equal to or exceeds 10 percent of the assesses the impact of the rule on small in future rulemakings. The rule also entities, as defined by the applicable relevant universe of small entities. revises existing provisions throughout Therefore, BSEE expects that the rule Small Business Administration (SBA) Subparts D, E, F, and Q to address size standards. will affect a substantial number of small entities. 1. Description of the Reasons for the 31 For example, any approximation of cost would BSEE is using the estimated 99 Actions Being Taken by the Agency incorporate catastrophic spills such as the Deepwater Horizon incident. The cost to BP of businesses based on activity at the time BSEE identified a need to amend the cleanup operations for the Deepwater Horizon this economic analysis was developed. existing Blowout Preventer (BOP) and incident has been estimated at more than $14 The 99 businesses represent the best billion. In addition to cleanup costs, BP has agreed assessment of the total businesses well-control regulations to enhance the to pay over $14 billion to Federal, state, and local safety and environmental protection of governments for natural resources damages, operating in this arena at the time the oil and gas operations on the OCS. In economic damage claims, or other expenses in a economic analysis was developed. BSEE particular, BSEE considers this rule proposed consent decree and proposed settlement recognizes that this number is a agreement that has been approved by the court. dynamic number and can fluctuate; necessary to reduce the likelihood of Source: Ramseur, J.L., Hagerty, C.L. 2014. any oil or gas blowout, which can lead ‘‘Deepwater Horizon Oil Spill: Recent Activities to the loss of life, serious injuries, and and Ongoing Developments,’’ Congressional 32 See 5 U.S.C. 601. harm to the environment. As was Research Office. Available at: http://www.fas.org/ 33 We used ReferenceUSA, a directory of business sgp/crs/misc/R42942.pdf. See summary of information for more than 14 million businesses in evidenced by the Deepwater Horizon settlement agreement regarding natural resources all zip codes of the United States, to identify the incident (which began with a blowout at damages at www.doi.gov/deepwaterhorizon and at list of offshore oil and gas operators and their the Macondo well on April 20, 2010), http://www.justice.gov/enrd/deepwater-horizon. numbers of employees.

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however, BSEE determined that this already incurred as a result of current (1) Promulgate the requirements number of businesses was appropriate industry practice in accordance with contained in the rule, including for this rulemaking. existing regulations, DWOPs, and API decreasing the BOP testing frequency for industry standards with which 3. Description and Estimate of workover and decommissioning operators already comply were not Compliance Requirements operations from the current requirement considered as costs of this rule because of once every 7 days to once every 14 BSEE has estimated the incremental they are part of the baseline.34 All costs days. The following chart identifies the costs for small operators, lease holders, are presented in 2014 dollars. BOP testing changes related to and right-of-way holders in the offshore As described in section 5 below, BSEE Alternative 1; oil and natural gas industry. Costs considered three regulatory alternatives:

BOP PRESSURE TESTING

Operation Current testing frequency New testing frequency

Drilling/Completions ...... Once every 14 days ...... Once every 14 days. Workover/Decommissioning ...... Once every 7 days ...... Once every 14 days.

(2) Promulgate the requirements regulatory requirements (i.e., once every identifies the BOP testing changes contained within the rule with a change 7 or 14 days, depending upon the type related to Alternative 2; to the required frequency of BOP of operation) to once every 21 days for pressure testing from the existing all operations. The following chart

BOP PRESSURE TESTING

New testing frequency Operation Current testing frequency (alternative 1) Alternative 2 testing frequency

Drilling/Completions ...... Once every 14 days ...... Once every 14 days ...... Once every 21 days. Workover/Decommissioning ...... Once every 7 days ...... Once every 14 days ...... Once every 21 days.

(3) Take no regulatory action and incorporates elements of API Standard (i) Foundation requirements for continue to rely on existing BOP 53 and related standards. In addition to MODUs; regulations in combination with permit addressing concerns arising from the (j) Monitoring of well operations with conditions, DWOPs, operator prudence, Deepwater Horizon incident and a subsea BOP; and industry standards as applicable to aligning with industry standards, the (k) Additional documentation and BOP systems. final rule advances several of the more verification requirements for BOP By taking no regulatory action critical well-control capabilities beyond systems and system components; (Alternative 3), BSEE would leave current industry standards applicable to (l) Additional information in the APD, unaddressed most of the concerns and BOP systems based upon agency APM, or other submittal for BOP recommendations that were raised knowledge, experience and technical systems and system components; regarding the safety of offshore oil and expertise. The final rule will also (m) Submission by the operator of an gas operations and the potential for improve efficiency and consistency of MIA Report completed by a BAVO; 35 another well control event with the regulations and allow for flexibility (n) New surface BOP system consequences similar to those of the in future rulemakings. requirements; Deepwater Horizon incident (see n. 9, We have estimated the costs of the (o) New subsea BOP system supra). following provisions of the final rule: requirements; Alternative 2 (changing the required (a) Additional information in the (p) New accumulator system frequency of BOP pressure testing to description of well drilling design requirements; once every 21 days for all operations) criteria; (q) Chart or digital recorders; was not selected because BSEE lacks (b) Additional information in the (r) Notification and procedures critical data on testing frequency and drilling prognosis; requirements for testing of surface BOP equipment reliability to justify such a (c) Prohibition of a liner as conductor systems; change at this time. casing; (s) Alternating BOP control station BSEE has elected to move forward (d) Additional capping stack testing function testing; with Alternative 1, the final rule, which requirements; (t) ROV intervention function testing; incorporates recommendations provided (e) Additional information in the (u) Autoshear, deadman, and EDS by government, industry, academia, and APM for installed packers; function testing on subsea BOPs; other stakeholders prior to the proposed (f) Additional information in the APM (v) Approval for well-control rule, as well as recommendations for pulled and reinstalled packers; equipment not covered in subpart G; contained in public comments on the (g) Rig movement reporting; (w) Breakdown and inspection of BOP proposed rule. The final rule also (h) Fitness requirements for MODUs; system and components;

34 Industry standards are developed by industry and are often incorporated into commercial BSEE describing the organization’s applicable members and technical experts in open meetings contracts between operators and contractors. qualification and experience. See discussion on based on a consensus process. They contain the 35 The approved verification organization will Third-party Verification in the final rule for further baseline requirements that the industry has deemed have to submit documentation for approval by information. necessary to operate in a safe and reliable manner

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(x) Additional RTM-related costs to industry. BSEE considers the (d) Additional Capping Stack Testing recordkeeping; and additional information required for the Requirements (y) Industry familiarization with the drilling prognosis (submitted as part of Section 250.462 addresses source new rule. the APD) to be readily available. We control and containment requirements. (z) BAVO application costs calculated the annual labor cost for this New paragraph (e)(1) details These requirements and their activity by multiplying the time requirements for testing of capping associated costs to industry and required to gather and document the stacks. New requirements include the government are discussed in the information by the average hourly function testing of all critical sections that follow. (Please note that compensation rate of the staff most components on a quarterly basis and the the descriptions of the rule provisions likely to complete this task. We then pressure testing of pressure containing presented in the RFA seek to mirror the multiplied the product of this critical components on a bi-annual language of the rule; however, only the calculation by the estimated number of basis. Under the former regulations, final regulatory text is legally binding.) wells drilled per year, resulting in an there is no testing requirement for (a) Additional Information in the estimated annual labor cost to industry capping stacks. These new requirements for this documentation requirement of Description of Well Drilling Design help ensure that operators are able to about $7,200.37 No additional costs to Criteria contain a subsea blowout. BSEE are expected as a result of this These new testing requirements will As discussed in detail in the preamble requirement. The requirement to result in new equipment and service to the final rule, § 250.413(g) requires include additional information in the costs to industry. We estimated the cost information on safe drilling margins to drilling prognosis (submitted as part of of testing for each capping stack, revised be included in the description of the the APD) results in an annual labor cost based on industry comments on the well drilling design criteria. Safe of about $70 per entity.38 proposed rule and initial RIA, and drilling margins are an important multiplied this cost by the total number parameter in avoiding a fracturing of the (c) Prohibition of a Liner as Conductor Casing of anticipated tests to be performed. formation or a compromise of the casing These calculations resulted in annual shoe integrity. Either of these factors Former § 250.421(f) is being revised to compliance costs to industry associated could lead to erratic pressures and no longer allow a liner to be installed with these requirements of about uncontrolled flows (e.g., formation as conductor casing. This will ensure $226,000, or $2,300 per entity.40 No kicks) emanating from a well reservoir that the drive pipe is not exposed to additional costs to BSEE are expected as during drilling. This information is wellbore pressures during drilling in a result of these requirements. necessary for BSEE to better review the subsequent hole sections. well drilling design and drilling This provision will result in an (e) Additional Information in the APM program. The requirement to include annual equipment and labor cost to for Installed Packers information on the safe drilling margins industry for wells that are currently In § 250.518, paragraphs (e) and (f) in the well drilling design criteria allowed to use a liner as conductor clarify requirements for installed results in an annual labor cost of about casing. We multiplied the average cost packers and bridge plugs and require $300 per entity.36 of the casing joints and wellhead per additional information in the APM, well by the number of affected wells in including descriptions and calculations (b) Additional Information in the order to calculate annual equipment Drilling Prognosis for determining production packer installation costs. To calculate the setting depth. These new provisions Section 250.414 requires industry to associated annual labor costs, we codify existing BSEE policy to ensure provide additional information in the multiplied the time required to install consistent permitting. BSEE expects that drilling prognosis. New paragraph (j) the equipment per well by the daily operators already comply with the requires the drilling prognosis to labor cost of rig crew time and by the design specifications included in this identify the type of wellhead system to number of wells on which the section, because they are based on an be installed with a descriptive equipment must be installed. We then established industry standard; i.e., API schematic, which should include summed the equipment and labor costs Spec. 11D1. Thus, the depth setting to estimate the average annual pressure ratings, dimensions, valves, calculation is the only requirement that equipment and labor cost to industry for load shoulders, and locking mechanism, imposes a new cost beyond the baseline. this requirement of $795,000. No if applicable. This information will The required calculations will be additional costs to BSEE are expected as provide BSEE with data to reference submitted for every well that is a result of this requirement. This during the approval process and will completed where tubing is installed. enable industry and BSEE to confirm provision will result in an annual that the wellhead system is adequate for equipment and labor cost of about 39 (approximately one percent of drilled wells the intended use. $8,000 per entity. currently) have a liner as conductor casing. We The requirement to include additional estimated an average cost of the casing joints and information in the drilling prognosis 37 We assumed that industry staff (a mid-level wellhead per well at $65,000. This resulted in an engineer) will spend 0.25 hours to include the average equipment cost of $195,000. We estimated will result in increased annual labor additional information in the drilling prognosis for that industry staff (rig crew) will spend one extra a well. We multiplied the number of industry staff day to install the new equipment on a well, and the 36 We estimated that industry staff (a mid-level hours per well by the average hourly compensation average labor cost for a rig crew per day is $200,000. engineer) will spend one hour per well (at a rate for a mid-level industry engineer ($89.42) and This resulted in an estimated average annual labor compensation rate of $89.42 per hour) to include the average number of wells drilled per year (320) cost to industry of $600,000. The annual equipment the additional information in the well drilling to obtain the average annual labor cost to industry and labor costs total $795,000 for the industry, or design criteria. Industry already complies with this of $7,153. $8,030 per entity. new requirement as part of its design practice for 38 We estimated that industry staff (a mid-level 40 BSEE estimated that the equipment and service most wells drilled. We assumed that this engineer) will spend 0.25 hours to include the costs of testing for capping stacks will be $14,138 requirement will result in a new cost for all wells additional information in the drilling prognosis for per test, based on industry input. Additionally, we drilled per year (320). This resulted in an average a well, resulting in an annual cost to industry of estimated that 4 capping stacks will be tested annual labor cost to industry of $28,614, or an $7,153, or $72 per entity. quarterly (or a total of 16 annual tests performed). annual labor cost per entity of $289 (assuming 99 39 Based on input provided in submittals to BSEE, This rendered a total annual equipment and service entities). we estimated that three wells per year cost to industry of $226,200, or $2,285 per entity.

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The requirement to include additional reporting requirements to all rig units (i) Foundation Requirements for information in the APM will result in a conducting operations covered under MODUs labor cost to industry and BSEE. We this subpart, including MODUs, Section 250.713(b) introduces based the industry labor cost associated platform rigs, snubbing units, and coiled foundation requirements for MODUs with this new requirement on the time tubing units. Paragraphs (c) and (e) are performing well operations. Operators required to add the new descriptions new and require notification if a MODU must provide information to show that and calculations to an APM and on the or platform rig is to be warm or cold site-specific soil and oceanographic number of wells with installed packers stacked and when a drilling rig enters conditions are capable of supporting the for which an APM will be submitted per OCS waters. Paragraph (f) is revised to rig unit.44 If operators provide sufficient year. We based the new annual labor clarify that, if the anticipated date for site-specific information in the cost to BSEE on the time that BSEE will initially moving on or off location Exploration Plan (EP), Development and spend reviewing the new information in changes by more than 24 hours, an Production Plan (DPP), or Development an APM and on the average hourly updated Movement Notification Report Operations Coordination Document compensation rate of the BSEE staff will be required. Currently, movement (DOCD) submitted to BOEM, operators most likely to complete this task. We reports are only required for drilling may reference that information. The estimated an average annual labor cost operations, but the rule requires regulations state that the District of about $5,800 to industry (or about operators to submit movement reports Manager may require operators to $60 per entity) and an average annual for other operations as well, including conduct additional surveys and soil labor cost of about $4,400 to BSEE.41 when rigs are stacked or enter OCS borings before approving the APD, if (f) Additional Information in the APM waters. These changes will allow BSEE additional information is needed to for Pulled and Reinstalled Packers to better anticipate upcoming make a determination that the operations, locate MODUs and platform conditions are capable of supporting the In § 250.619, new paragraphs (e) and rigs in case of emergency, and verify rig rig unit or equipment installed on a (f) clarify requirements for pulled and fitness. The requirement to notify BSEE subsea wellhead. For moored rigs, reinstalled packers and bridge plugs and of rig unit movement will result in operators must submit a plan of the rig’s require additional descriptions and annual labor costs to industry of about anchor patterns approved in the EP, calculations in the APM regarding $4,000 (or about $40 per entity) and to DPP, or DOCD in the APD or APM. production packer setting depth. These BSEE of about $3,100.43 This requirement will result in labor new requirements codify existing BSEE costs to industry and BSEE. To calculate policy to ensure consistent permitting. (h) Fitness Requirements for MODUs the industry labor cost, we multiplied BSEE expects that operators already the time required to record and report comply with the design specifications Section 250.713(a) adds a requirement the information by the average hourly included in this section, which that operators provide fitness compensation rate of the industry staff incorporate an established industry information for a MODU for well most likely to complete this task and by standard (i.e., API Spec 11D1). The operations. Operators must provide the number of APMs per year. To depth setting description and information and data to demonstrate the calculate the BSEE labor cost, we calculation is the only requirement that drilling unit’s capability to perform at multiplied the time that BSEE will will impose a new cost beyond the the new drilling location. This spend to review the information by the baseline. The required calculations will information must include the maximum average hourly compensation rate of the be submitted for every well that is environmental and operational BSEE staff most likely to complete this worked over where tubing is pulled and conditions that the unit is designed to task and by the number of APMs per then reinstalled. The requirement to withstand, including the minimum air year. The new requirements under include additional information in the gap (if relevant) that is necessary for § 250.713 to notify BSEE of rig unit APM will result in a labor cost of about both hurricane and non-hurricane movement and foundation requirement $23,000 to industry (or about $200 per seasons. If sufficient environmental for MODUs will result in labor costs to entity) and about $17,000 to BSEE.42 information and data are not available at industry and BSEE, based on the labor the time the APD or APM is submitted, required per report and the number of (g) Rig Movement Reporting the District Manager may approve the reports per year. We estimated these Section 250.712 lists requirements for APD or APM but require operators to annual labor costs to be about $208,000 reporting movement of rig units to the collect and report this information to industry (about $2,100 per entity) and BSEE District Manager. Revised during operations. Under this about $158,000 to BSEE.45 circumstance, the District Manager may paragraph (a) extends the rig movement (j) RTM for Well Operations revoke the approval of the APD or APM 41 We estimated that industry staff (a mid-level if information collected during Section 250.724 is a new section that engineer) will spend 0.25 hours to include the operations shows that the drilling unit establishes requirements for: additional information in the APM for a well, at a is not capable of performing at the new (1) RTM of well operations on rigs compensation rate of $89.42 per hour. We estimated that have a subsea BOP, floating that APMs will be submitted for an average of 260 location. These costs, in combination wells with installed packers per year. We estimated with the foundation requirements for facilities using surface BOPs, and rigs that BSEE staff (a mid-level engineer) will spend MODUs, are discussed at the end of the 0.25 hours to review the additional information in next section. 44 Soil sampling data is included in the the APM for a well, at a compensation rate of exploration plan and DWOP submissions, and $67.85. verified in the APD process, under existing 42 We estimated that industry staff (a mid-level 43 This is based on the assumption of an average regulations. engineer) will spend 0.25 hours (at $89.42 per hour) of 60 reports per year, of which 50 require about 45 These estimates were based on the assumption to include the additional information in the APM 0.5 hours to prepare by industry (by a mid-level that industry staff (a mid-level engineer) will spend for a well, and that APMs will be submitted for an engineer at a compensation rate of $89.42 per hour), 5 hours on average per report, at a compensation average of 1,010 wells with pulled and reinstalled and 10 others requiring about 2 hours to complete. rate of $89.42 per hour, and an average of 466 packers per year. We estimated that BSEE staff (a It was estimated that BSEE requires as much time reports will be provided per year. We estimated that mid-level engineer) will spend 0.25 hours (at $67.85 to process and review the reports, by a mid-level BSEE staff (a mid-level engineer) will spend 5 hours per hour) to review the additional information in BSEE engineer, at a compensation rate of $67.85 per on average to review and process the information, the APM for a well. hour. at an average compensation rate of $67.85 per hour.

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operating in high pressure and high not normally receive or review RTM HPHT conditions will result in new temperature reservoirs, plans, no significant additional costs to annual costs to industry. To calculate (2) Storing RTM data onshore, and BSEE are expected as a result of these the costs associated with the required (3) An RTM plan addressing RTM requirements. verifications of BOP systems and capabilities and procedures. components by BSEE-approved (k) Additional Documentation and In order to comply with this section, verification organizations, we estimated industry will incur annual equipment Verification Requirements for BOP Systems and System Components the annual cost for performing the and labor costs associated with verification and multiplied the annual gathering, recording, transmitting, and Section 250.730 lists general cost by the number of wells that will storing data (as well as minimal one- requirements for BOP systems and incur this new cost. This calculation 46 time labor costs to develop RTM plan). system components and adds new resulted in annual equipment and labor To calculate the costs associated with documentation and verification costs for this verification requirement of these new requirements, we estimated requirements.48 We estimated an annual $500,000 to industry.51 the average equipment and labor cost labor cost to industry of about $1,800 per day to perform continuous associated with these submissions and In total, all of the annual equipment monitoring (based on BSEE’s labor costs to BSEE of about $700.49 We and labor costs associated with these interactions with the industry and were unable to estimate the cost for a new documentation and certification review of the equipment involved), and certification entity to meet the requirements are estimated to be the average amount of time that a rig requirements of ISO 17011 for quality $18,005 per entity. will engage in well operations per year management systems for BOP stacks. (l) Additional Information in the APD, (and will thus be subject to this Section 250.731(c) requires APM, or Other Submittals for BOP monitoring requirement). We assumed verification by a BAVO of specified Systems and System Components that this type of service mostly lends aspects of equipment design, equipment itself to a day rate, and multiplied the tests, shear tests, and pressure integrity Section 250.731 lists the descriptions cost per day to perform the monitoring tests; all certification documentation of BOP systems and system components by the number of days per year that the must be made available to BSEE. The that must be included in the applicable rig will be engaged in well operations. requirements laid out in § 250.731(c) APD, APM, or other submittal for a well. We then multiplied the product by the regarding certification for BOP systems Revised paragraph (a) requires the number of rigs that will incur this new and system components will result in submittal to include descriptions of the cost. This calculation resulted in new equipment and service costs to rated capacities for the fluid-gas average annual equipment and labor industry. We estimated a one-time cost separator system, control fluid volumes, costs for this monitoring requirement of to industry for equipment and service control system pressure to achieve a seal $40.5 million to industry (or about and multiplied the cost by the number of each ram BOP, number of $409,000 per entity).47 Since BSEE will of wells that will incur this new cost. accumulator bottles and bottle banks, This calculation resulted in one-time and control fluid volume calculations 46 As explained later in part VIII, under equipment and service costs for this for the accumulator system. Paperwork Reduction Act (PRA) of 1995, we certification requirement of $12.8 New paragraph (e) requires a listing of assumed that it will take an estimated 5 burden 50 hours to develop each RTM plan. Based on the million to industry. the functions with sequences and timing assumption that industry staff (a mid-level Section 250.732(c) requires a of autoshear, deadman, and EDS for engineer) will develop these plans, at a comprehensive review by a BAVO of compensation rate of $89.42 per hour, the one-time subsea BOPs. Paragraph (b) adds BOP and related equipment for use in schematic drawing requirements, cost of this requirement would be about $447 per high temperature and high pressure plan. Over the 10-year economic analysis period, including labeling for the control system the average annual cost would be about $44.7 per conditions. The requirements in new alarms and set points, control stations, plan. (We believe that the total costs for small § 250.732(c) surrounding a review of and riser cross section. For subsea entities could be even smaller since, based on the BOP systems and system components in comments submitted by industry, some operators BOPs, surface BOPs on floating already have RTM plans that may merely need facilities, and BOPs operating under rig is operational per year (270) by the average cost some adjustment to satisfy the final rule HPHT conditions, new paragraph (f) requirements; nonetheless, we have assumed here per day ($5,000) to perform monitoring and by the that all affected small entities would need to number of affected rigs (30) to obtain an average requires submission of a certification develop such plans.) These estimated costs are so annual equipment and labor cost to industry of that an MIA Report has been submitted small that they are effectively subsumed by the $40,500,000. within the past 12 months. New 48 overall costs of complying with the RTM Section 250.730(d) requires that quality paragraphs (c) and (d) include a change requirements generally. management systems for the manufacture of BOP 47 We estimated that the average costs per day and stacks be certified by an entity that meets the in required certifications; the the average operational days per year will be the requirements of International Organization for paragraphs require submission of same for rigs with subsea BOPs, surface BOPs on Standardization (ISO) 17011. Additionally, certification from a BAVO (rather than floating facilities, and rigs operating in HPHT operators may submit a request for approval of a ‘‘qualified third-party’’) 52 that: reservoirs. We estimated that a rig operates for 270 equipment manufactured under quality assurance days per year (three operations per year and three programs other than API Specification Q1, and months per operation) and that the average cost per BSEE may approve such a request provided the 51 We estimated that the annual costs per well day to perform continuous monitoring will be operator submits relevant information about the will be $50,000. We estimated that 10 HPHT wells $5,000, including equipment and labor. This alternative program. Additionally, new paragraph will incur a new cost to comply with these estimate is based on the experience of the BSEE (d) will result in labor costs to industry associated requirements. We multiplied the annual cost of regulatory staff, working in conjunction with BSEE with submitting requests for alternative programs. equipment and service by the number of affected engineers who interact with industry on a regular 49 We estimated that a mid-level industry wells to obtain an average annual equipment and basis and review the equipment. We also estimated engineer will spend 2 hours to submit a request, at service cost to industry of $500,000. that half of the rigs with subsea BOPs already a compensation rate of $89.42 per hour, for each of 52 BSEE expects that BAVOs will come from conduct this monitoring. Thus, only half of rigs ten wells during the year. We estimated that a mid- qualified third parties used by operators under with subsea BOPs (20 rigs) will incur a new cost level BSEE engineer will spend 1 hour to process BSEE’s former regulations and industry standards. to comply with these requirements. Similarly, we a request, at a compensation rate of $67.85 per hour. In addition, the certifications required under new estimated that a total of 10 rigs (i.e., 5 floating 50 We based this estimate on the assumption that § 250.731(c) and (d) are similar to the verifications facilities with a surface BOP and 5 rigs in HPHT the service costs per well will be $40,000, and 320 required by former § 250.416(e) and (f). Thus, there reservoirs) will incur a new cost to comply with wells will incur a new cost to comply with these should not be any incremental costs from these new these requirements. We multiplied the time that the requirements. certification requirements.

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(1) Test data demonstrate that the ensure that BSEE is aware of repairs or million, or about $2,500 per entity per shear ram(s) will shear the drill pipe at other changes to the operating BOPs. year (over a 10-year period).54 the water depth, and These reporting requirements will (o) New Subsea BOP System (2) The BOP has been designed, result in new capital costs to industry Requirements tested, and maintained to perform under and new labor costs to industry Section 250.734 includes new the maximum environmental and associated with the submission and requirements for subsea BOP systems, operational conditions anticipated to review of reports. To calculate the occur at the well, and based on recommendations from the capital costs to industry of submitting Deepwater Horizon incident (3) That the accumulator systems have MIA reports, we multiplied the annual sufficient fluid to function the BOP investigations. Revised paragraph (a) capital cost of submitting the report by requires that BOPs be equipped with system without assistance from the the estimated number of wells that will charging system. dual shear rams and outlines the be affected. This calculation resulted in requirements for the shear rams. The requirements to provide annual capital costs for reporting of $4.8 additional documentation about the BSEE recognizes that the equipment million to industry. To calculate the costs associated with these new subsea BOP system and system components in industry labor cost, we multiplied the the APD, APM, or other submittal will BOP system requirements will be case- time required to submit a report by the result in labor costs to industry and specific. For example, the costs will average hourly compensation rate of the BSEE. To calculate the industry labor depend on the age of the rig and BOP industry staff most likely to complete cost associated with these new system, the BOP system type, and the this task and then multiplied this cost requirements, we multiplied the size of the rig, among other factors. In by the number of additional reports estimated time it will take to document order to estimate the cost to industry the required information in an APD, expected per year. These calculations associated with these new shear ram APM, or other submittal by the average result in average annual labor costs of requirements, we multiplied the hourly compensation rate of the about $45,000 to industry and about estimated cost of compliance per rig by industry staff most likely to complete $11,000 to BSEE. Overall, all of the the estimated number of affected rigs. this task. We then multiplied the requirements under this section result Since API Standard 53 covers the product by the estimated number of in an annual cost per entity of about requirements under paragraph (a) for all 53 wells drilled per year. $50,000. rigs with the exception of moored rigs, the costs of these requirements, except Likewise, to calculate the new annual (n) New Surface BOP Requirements labor cost to BSEE, we multiplied the the costs associated with moored rigs, time that BSEE will spend to process Section 250.735 includes new are included in the baseline. We each submittal by the average hourly requirements for surface BOP stacks. multiplied the cost of compliance for a compensation rate of the BSEE staff Specifically, new § 250.735(g)(2)(i) moored rig by the number of moored most likely to complete this task and by requires that remotely-operated locking rigs in order to calculate the one-time the estimated number of wells drilled devices be installed on blind shear rams equipment costs of $50 million for this 55 per year. These calculations resulted in on surface BOPs. BSEE recognizes that requirement. This results in an average annual labor costs for this the equipment and labor costs average annual cost of $5 million per documentation requirement of about associated with this new requirement year over ten years, or an annual cost of $29,000 (about $300 per entity) to will be case-specific (since every BOP about $51,000 per entity. industry and about $22,000 to BSEE. stack is unique). In any case, BSEE (p) New Accumulator System (m) Submission of an MIA Report by a estimates that this new requirement will Requirements BAVO create a new one-time equipment cost to Section 250.735(a) lists new industry for the installation of remotely- requirements for the accumulator Sections 250.732(d) and (e) include operated locks. Operators may choose, new requirements on the submission of system of a BOP. The accumulator although they are not required, to use system must operate all BOP functions an MIA Report on the BOP stack and hydraulically operated locks to comply systems. New paragraph (d) outlines the against MASP with at least 200 pounds with this requirement. Because we per square inch remaining on the bottles requirements for this report, which must cannot predict how many operators will be completed by a BAVO and submitted use hydraulic locks, rather than 54 Based on industry comments, BSEE has revised by the operator for operations that alternative (and typically less costly) the cost estimate for this provision. The cost of require the use of a subsea BOP, a locking devices, we have continued to installing a hydraulically operated lock is estimated surface BOP on a floating facility, or a at $50,000. Although the revised final rule only estimate the cost of this provision based imposes such new costs on surface BOPs with blind BOP that is being used in HPHT on the cost for installing hydraulic operations. We calculate this annual shear rams, we chose to multiply this cost by the locks, even though that may result in an estimated total number (50) of rigs with surface cost by multiplying the time required to overestimation of actual costs. We BOPs with any kind of sealing ram to obtain the complete the task by the number of one-time cost estimate to industry of $2.5 million. estimate this cost by multiplying the submittals per year and by the hourly 55 Although the actual costs for obtaining and cost per equipment part by the number compensation rate of the industry staff installing any new equipment required by this of rigs with surface BOPs. This results section will vary, as stated above, based on existing most likely to complete the task. These in a one-time cost to industry of $2.50 technology for centering/shearing and BSEE’s calculations result in an annual labor discussion with a relevant equipment manufacturer, cost to industry of about $80,000. BSEE believes that the height of the subsea BOP 53 We estimated an annual capital cost of $15,000 stacks will not need to change significantly. We also Section 250.731(f) requires a for each of 320 wells, which resulted in an annual estimated that 5 moored rigs will be affected and certification stating that this report was capital cost of $4.8 million. For labor costs, we that the one-time capital compliance costs, submitted to BSEE prior to beginning estimated that industry staff (a mid-level engineer) including installation costs, associated with these any operations (to include maintenance will spend a half hour to prepare a report for each shear ram requirements will be $10,000,000 per rig. of 320 wells, at a compensation rate of $89.42. We To calculate the total one-time capital costs to and repairs) involving these BOPs. The also estimated that the same staff would spend 5 industry, we multiplied the equipment cost per rig BAVO report will enhance BSEE’s hours for each of 50 reports per year, and 10 hours by the number of affected rigs to yield a total cost review and permitting process and for each of 90 reports per year. to industry of $50,000,000.

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above the pre-charge pressure without (r) Notification and Procedure and verifying the closure of the selected use of the charging system. Revised Requirements for Testing of Surface ram(s) on a subsea BOP. This testing paragraph (a) details additional BOP Systems requirement will result in an annual accumulator requirements regarding Section 250.737(d)(2) expands operations cost to industry of about 60 fluid capacity and accumulator notification and procedural $417,000, or about $4,200 per entity. regulators. This revision will ensure that requirements regarding the use of water (u) Autoshear, Deadman, and EDS the BOP system is capable of operating to test a surface BOP system on the System Function Testing on Subsea all critical functions. initial test. These expanded notification BOPs The requirement that the accumulator and procedural requirements will result Section 250.737(d)(12) expands the system operate all functions for all BOP in increased annual costs to industry of requirements for function testing of systems will result in a total one-time about $5,400 (about $50 per entity) and autoshear, deadman, and EDSs on cost to industry of about $2.4 million, or to BSEE of about $4,100.58 about $2,500 per entity per year over 10 subsea BOPs. It requires the test years.56 Since this work can be planned (s) Alternating BOP Control Station procedures submitted for the BSEE for and done during routine Function Testing District Manager’s approval to include maintenance or downtime scheduled for Section 250.737(d)(5) expands the schematics of the actual controls and other reasons, no incremental rig requirements for function testing BOP circuitry of the system, the approved downtime or daily rig costs are control stations. It requires that the schematics of the BOP control system, expected. operator designate the BOP control and a description of how the ROV is used during the operation. It also (q) Chart Recorders stations as primary and secondary and alternate function testing of each station outlines the requirements for the Section 250.737(c), which addresses weekly. This testing requirement will deadman system test, including a BOP testing requirements, will result in increased operating costs to requirement that the testing must introduce a requirement that each test industry. To calculate the annual indicate the discharge pressure of the must hold the required pressure for five subsea accumulator system throughout operations costs associated with this minutes while using a four-hour chart. the test. It requires that the blind shear requirement, we multiplied the time This chart will contain sufficient detail rams be tested to verify closure. The required to conduct the testing per rig to show if a leak occurred during the operator must document the plan to by the daily rig operating cost and by test. verify closure of the casing shear ram(s), the estimated number of rigs affected This testing requirement will result in if installed, as well as all test results. a one-time equipment and labor cost to per year. Because subsea and surface These documentation and testing industry for those operators that do not BOPs have different daily rig operating requirements will result in a one-time already have the required equipment. costs, we performed separate equipment cost and increased annual Some operators will have to purchase calculations for the costs for subsea and operating costs to industry. The the equipment (a chart recorder or surface BOP rigs. We estimated an industry will incur a one-time digital recorder) to be able to comply increased annual operating cost to equipment cost to purchase a sensing with the testing requirement. To industry associated with this provision device to detect the discharge pressure calculate the equipment cost, we of $25 million, or an annual operations during deadman system testing. We 59 multiplied the estimated cost of cost of about $250,000 per entity. multiplied the average cost per rig of the equipment per rig by the estimated total (t) ROV Intervention Function Testing sensing device by the estimated number number of rigs that may need it. To of subsea BOP rigs required to comply. Section 250.737(d)(4) establishes calculate the one-time labor cost to We assumed installation costs to be requirements for testing ROV industry, we multiplied the time negligible because the sensing device intervention functions to include testing required per rig to install the chart will be installed as part of routine recorder by the average hourly (half of the 90 rigs in total, with the other half servicing. In order to calculate the compensation rate of the industry staff estimated to already have the equipment). This annual operations cost, we multiplied most likely to complete this task and by yielded an estimated one-time equipment cost to the estimated time per subsea BOP rig the total number of rigs. This industry of $90,000. We estimated that industry required to comply with the calculation resulted in a one-time cost staff (rig crew) will spend five minutes (0.08 hours) per rig to install the equipment at an average hourly documentation and testing requirements to industry of about $90,000, or about compensation rate of $57.20. This resulted in a total by the daily operating cost for a subsea 57 $90 per entity per year over 10 years. one-time cost to industry of $90,215. BOP rig and by the estimated number of 58 This $54 labor cost per entity reflects our subsea BOP rigs affected per year. These 56 BSEE estimated that the cost of the additional assumptions that a mid-level industry engineer will calculations resulted in a one-time equipment needed to meet the requirements will be spend 1 additional hour on a submittal as a result $25,000 per rig. It is unknown how many rigs of these expanded requirements and that industry equipment cost to industry of $100,000 already comply; thus, we made a conservative will submit 60 notifications per year. and an average annual increased assumption that all rigs will be affected (90 rigs). 59 We estimated that testing would require 0.5 operating cost to industry of $5 million, We obtained an estimated one-time equipment cost days per rig per year. Because subsea and surface or an annual cost of about $51,000 per of $2.25 million. For the one-time labor cost to BOP rigs have different daily rig operating costs, we 61 industry, we estimated that three days of industry performed separate calculations for the costs for entity. time will be required per rig to install the new subsea and surface BOP rigs. For subsea BOP rigs, equipment. We estimated that industry staff (a mid- we multiplied the time required to conduct the 60 We estimated that it will take five minutes per level engineer) will spend 24 hours to install the testing per rig by the daily rig operating cost for well to conduct the testing and that 120 wells will new equipment on a rig, at a compensation rate of subsea BOP rigs ($1 million) and by the number of be affected (40 subsea BOP rigs with three wells per $89.42 per hour. This rendered an estimated one- subsea BOP rigs (40) for an annual cost of $20 rig). We considered the time diverted for testing as time labor cost to industry of $193,143. Summing million for subsea BOP rigs. For surface BOP rigs, a fraction of a day (0.003472), and the daily the equipment and labor costs resulted in a total we estimated a daily rig operating cost of $200,000 operating cost per rig ($1,000,000) to obtain an one-time cost to industry of $2,443,143. We divided and the number of surface BOP rigs to be 50, for average annual operations cost to industry of the one-time equipment and labor cost by the an annual cost of $5 million for surface BOP rigs. $416,667, or $4,209 per entity. number of entities (99) to obtain a one-time Summing the annual costs for subsea BOP rigs and 61 BSEE estimated that the cost of the sensing equipment and labor cost per entity of $24,6787. surface BOP rigs resulted in a total annual increased device will be $2,500 per rig. We multiplied the 57 We estimated that a chart recorder would have operating cost to industry associated with this equipment cost by the total number of subsea BOP an average cost of $2,000 per rig, for each of 45 rigs provision of $25 million. rigs (40) to obtain the one-time equipment cost to

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(v) Approval for Well-Control operation per year. Because subsea and time labor cost of about $20,000 or Equipment not Covered in Subpart G surface BOPs differ in structure, they annual cost of $20 per entity.65 Section 250.738 describes the incur different costs to break down and (z) BAVO Application Costs required actions for specified situations inspect. In order to reflect these Qualified third-parties currently involving BOP equipment or systems. differences, we performed separate perform verifications under BSEE’s Paragraphs (b), (i), and (o) include calculations of the costs for subsea and existing regulations and current requirements for reports from BAVOs. surface BOP rigs. Assuming staggered Reports previously required to be inspections, we estimated that, in each industry practice that are similar to the prepared by a ‘‘qualified third-party’’ year, an average of eight subsea BOP rigs certifications and verifications that a BAVO will be required to perform under under these sections will be required to would undergo inspections, thereby § 250.732(a) of the final rule. BSEE be prepared by a BAVO. Paragraph (m) enabling all 40 subsea BOP rigs to expects that many of these existing includes a similar change and undergo such inspections over a five- third-party organizations will become introduces a requirement that an year period. Similarly, we estimated BAVOs. To become a BAVO, operator request approval from the that 10, of a total of 50, surface BOP rigs BSEE District Manager if the operator organizations will need to apply to would undergo inspections each year. BSEE and have their applications plans to use well-control equipment not This resulted in annual costs to industry covered in Subpart G. The operator approved by BSEE. Those that are of $4.3 million, or about $43,000 per approved as BAVOs will then be placed must submit a report from a BAVO, as entity.63 well as any other information required on a list for operators to use in finding by the District Manager. This new The proposed rule contained a a BAVO that will enable the operators approval request requirement will result requirement that operators breakdown to obtain the required certifications and in annual labor costs to industry and the entire BOP system every five years verifications. BSEE of about $13,000 and about for recertification, without the option to We estimated the number of BAVO $10,000, respectively, and annual costs phase or stagger recertification. BSEE applications to be 15 in the first year per entity of about $100.62 received comments that this (2016), three in the second year (2017), requirement would cause rigs to be out and two per year for each of the (w) Breakdown and Inspection of the of service for extended periods of time, remaining eight years (2018 to 2025). BOP System and Components at substantial opportunity costs to We further estimated that organizations Section 250.739(b) introduces a industry. BSEE revised the requirement would require, on average, about 100 requirement for a complete breakdown in the final rule to allow for staggered hours of a mid-level engineer’s time to and inspection of the BOP and every inspections over the course of five years. complete and submit each application. associated component every 5 years, This change eliminates the need for rigs We also estimated that BSEE would which may be performed in phased to be brought out of service for extended require, on average, about 40 hours of a intervals. During this complete periods of time. mid-level engineer’s time to review and breakdown and inspection, a BAVO process each application, except during must document the inspection and any (x) Additional Recordkeeping for RTM the first year in which BSEE would problems encountered. This BAVO require 80 hours per application (since report must be available to BSEE upon Sections 250.740(a) and 250.741(b) BSEE will need additional time in the request. This additional requirement is introduce requirements for additional first year to develop and begin necessary to ensure that the components recordkeeping of RTM data for well implementing the approval process). on the BOP stack will be regularly operations. These additional These estimates result in average annual inspected. In the past, BSEE has, in requirements will create an annual labor costs to industry of about $30,000 per some cases, seen components of BOP cost of about $1,500 to industry, or year (about $300 per entity) and to BSEE stacks go more than 10 years without about $15 per entity.64 of about $13,000 per year, for a total 66 this type of inspection. (y) Industry Familiarization With New average annual cost of $44,000. This inspection and documentation Regulations requirement will result in cost to Total Cost Burden for Small Entities industry associated with generating When the new regulation takes effect, To estimate the cost burden for small reports by BAVOs. To calculate this operators will need to read and interpret entities, BSEE scaled the per-entity costs report cost, we multiplied the estimated the rule. Through this review, operators report cost per rig by the number of will familiarize themselves with the 65 We assumed that industry staff (a professional reports completed per rig annually and engineer, supervisory) will spend two hours to structure of the new rule and identify review the new regulation, at an hourly wage rate by the estimated number of rigs in any new provisions relevant to their of $53.00, based on BSEE’s Supporting Statement A operations. Operators will evaluate (BSEE Production Safety Systems). We multiplied industry of $100,000. We estimated that it will take this wage rate by the private sector loaded wage one hour per well to perform the testing and whether any new action must be taken factor of 1.43 to account for employee benefits, documentation tasks required by this provision, and to achieve compliance with the rule. resulting in a loaded average hourly compensation that each subsea BOP rig will be affected (40 subsea Reviewing the new regulations will rate of $75.79. We assumed that an industry staff rigs). We multiplied the time diverted for testing in require staff time, representing a one- will review the new regulation at each of the 130 a day 0.125 by the daily operating cost per rig field offices. We multiplied the number of hours per ($1,000,000) and by the estimated number of rigs review by the average hourly compensation rate and affected per year to obtain an average annual 63 For subsea BOP rigs we estimated that by the number of field offices, resulting in an operations cost to industry of $5 million. equipment and labor cost will be $350,000 per rig, estimated one-time labor cost to industry of 62 These estimates are based on the assumption for each of 8 subsea BOP rigs each year, resulting $19,705. We divided annual labor cost of $1,971 by that industry staff (a mid-level engineer) will spend in an annual cost of $2.8 million. For surface BOP the number of entities (99) to obtain an average an average of 0.81 hours per report, at a rigs we estimated that equipment and labor cost annual one-time labor cost of $20. compensation rate of $89.42 per hour, for will be $150,000 per rig, for each of 10 rigs per year, 66 The total is slightly different due to roundiing, approximately 183 reports for year. It was estimated resulting in an annual cost of $1.5 million. using a compensation rate of $89.42 per hour for that that BSEE staff (a mid-level engineer) will 64 This $15 labor cost per entity reflects our industry results in an average annual cost to spend the same amount of time to review and assumption that an administrative staff will spend industry of $30,403; and using a compensation rate process the report, at a compensation rate of $67.85 0.5 hours to submit a report for each of 120 wells of $67.85 for BSEE results in an average annual cost per hour. (three wells per subsea BOP rig). to BSEE of $13,299.

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to match the labor and equipment costs average annual cost per entity (for all about $556,000 per affected small entity that would be faced by a small entity entities) of about $897,000. BSEE’s as a result of certain one-time with few wells as opposed to large calculations thus indicate that the total equipment costs, especially the costs of entities with several wells. Of the 99 cost burden of this rule will be $3.3 new subsea BOP system requirements. entities operating on the OCS, 50 (or million per affected small entity over 10 The costs of the rule as a proportion 50.51 percent) of them are small years, as presented in Exhibit 1. of small entity revenue range from 0.29 entities. In terms of revenue of offshore Exhibit 2 displays estimates of costs percent in most years to 0.52 percent in oil and gas sales, these small entities to small entities as a percentage of the first year. BSEE considers a rule to account for 18.50 percent of the total 67 revenues. In all but the first year of the have a ‘‘significant economic impact’’ revenue of all 99 entities. This implies 10 years in the analysis period, the rule when the total annual cost associated that the average small firm tends to have represents a cost of approximately operations that are about 36.6 percent as with the rule for a small entity is equal $304,000 per affected small entity. In to or exceeds 1 percent of annual large as the operations of an average the first year, costs will be higher at operator, e.g., having that many fewer revenue. Thus, the rule is not expected wells, rigs, and employees, on average. to have a significant economic impact 67 We used ReferenceUSA, a directory of business on the participating small operators, Therefore, it was estimated that the information for more than 14 million, businesses in costs per entity for a small entity would all zip codes of the United States, for data on lease holders, and pipeline right-of-way be 36.6 percent the cost per entity for all estimated annual revenue and number of holders. Therefore, BSEE has concluded entities. As a result, the total estimated employees. WE retrieved the ReferenceUSA data in that this rule will not have a significant February 2015. Based on these data, the average economic impact on a substantial annual cost of the rule per small entity annual revenue of the small operators is is about $328,000, in comparison to the $105,963,674. number of small entities.

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EXHIBIT 1: COSTS OF THE RULE PER SMALL ENTITY1 TotallO Year Average Annual Cost per Small Cost per Small Percent of Type of Cost Entity Entity Total Cost (undiscounted) (undiscounted) (a) Additional information in the description of $1,059 $106 0.03% well drilling design criteria (b) Additional information in the drilling $265 $26 0.01% prognosis (c) Prohibition of a liner as conductor casing $29,410 $2,941 0.90% (d) Additional capping stack testing requirements $8,368 $837 0.25% (e) Additional information in the APM for $215 $22 0.01% installed packers (f) Additional information in the APM for pulled $835 $84 0.03% and reinstalled packers (g) Rig movement reporting $149 $15 0.00%

(h) and (i) Information on MODUs $8,018.86 $802 0.24%

G) RTM of well operations $1,498,223 $149,822 45.61%

(k) Additional documentation and certification requirements for BOP systems and system $65,914 $6,591 2.01% components (l) Additional information in the APD, APM, or other submittal for BOP systems and system $1,059 $106 0.03% components (m) Submission of an MIA Report by a BSEE- $181,156 $18,116 5.51% approved verification organization (n) New surface BOP requirements $9,248 $925 0.28% ( o) New subsea BOP system requirements2 $184,966 $18,497 5.63% (p) New accumulator system requirements $9,038 $904 0.28% ( q) Chart recorders $334 $33 0.01% (r) Use water to test surface BOP system on the $198 $20 0.01% initial test (s)Alternating BOP control station function $924,829 $92,483 28.15% testing (t) ROV intervention function testing $15,414 $1,541 0.47% (u) Autoshear, deadman, and EDS system $185,336 $18,534 5.64% function testing on subsea BOPs (v) Approval for well-control equipment not $490 $49 0.01% covered in Subpart G (w) Breakdown and inspection of BOP system $159,071 $15,907 4.84% and components (x) Record-keeping for RTM $54 $5 0.00% (y) Industry familiarization with the new rule $73 $7 0.00%

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

BOP PRESSURE TESTING

Current testing Testing Operation frequency frequency (days) (days)

Drilling/Completions ...... 14 14 Workover/Decommissioning ...... 7 14

(2) Promulgate the requirements pressure testing from the existing operation) to 21 days for all operations. contained within the rule with a change regulatory requirements (i.e., 7 or 14 The following chart identifies the BOP to the required frequency of BOP days depending upon the type of testing changes related to Alternative 2:

BOP PRESSURE TESTING

Current Testing testing frequency Alternative 2 testing Operation frequency (alternative 1) frequency (days) (days) (days)

Drilling/Completions ...... 14 14 21 Workover/Decommissioning ...... 7 14 21

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(3) Take no regulatory action and a written statement satisfying the Civil Justice Reform (E.O. 12988) continue to rely on existing BOP requirements of UMRA. Those This rule complies with the regulations in combination with permit requirements are addressed and the requirements of E.O. 12988. conditions, DWOPs, operator prudence, required statements are found in the Specifically, this rule: and industry standards. final RIA and final RFA analysis or in (1) Meets the criteria of section 3(a) BSEE has elected to move forward the preamble of this final rule. requiring that all regulations be with Alternative 1—the final rule— Specifically, the final RIA, the final reviewed to eliminate errors and which incorporates recommendations RFA analysis, or this document: ambiguity and be written to minimize provided by government, industry, 1. Identify the provisions of Federal litigation; and academia, and other stakeholders prior law (OCSLA) under which this rule is (2) Meets the criteria of section 3(b)(2) to the proposed rule or contained in being promulgated; requiring that all regulations be written public comments on the proposed rule. 2. Include a quantitative assessment in clear language and contain clear legal In addition to addressing concerns and of the anticipated costs to the private standards. aligning with industry standards, BSEE sector (i.e., expenditures on labor and is advancing several of the more critical equipment) of the final rule; and Consultation With Indian Tribes (E.O. capabilities beyond current industry 3. Include qualitative and quantitative 13175) assessments of the anticipated benefits standards applicable to BOP systems The BSEE is committed to regular and based on agency knowledge, experience of the final rule. Since all of the anticipated meaningful consultation and and technical expertise. The rule will collaboration with tribes on policy also improve efficiency and consistency expenditures by the private sector analyzed in the final RIA and the final decisions that have tribal implications. of the regulations and allow for Under the criteria in E.O. 13175 and flexibility in future rulemakings. RFA analysis would be borne by the offshore oil and gas exploration DOI’s Policy on Consultation with Small Business Regulatory Enforcement industry, the final RIA and final RFA Indian Tribes (Secretarial Order 3317, Fairness Act analysis satisfy the UMRA requirement Amendment 2, dated December 31, The rule is a major rule under the to estimate any disproportionate 2013), we have evaluated this final rule Small Business Regulatory Enforcement budgetary effects of the proposed rule and determined that it has no Fairness Act, 5 U.S.C. 801 et seq. Under on a particular segment of the private substantial direct effects on federally that statute, a major rule is one that: sector (i.e., the offshore oil and gas recognized Indian tribes. (1) Will have an annual effect on the industry). Paperwork Reduction Act (PRA) of 1995 economy of $100 million or more; or As discussed in the Regulatory (2) Will cause a major increase in Planning and Review section (regarding This rule contains a collection of costs or prices for consumers, E.O. 12866 and the RFA), and as information that was submitted to the individual industries, Federal, State, or explained fully in the final RIA, BSEE Office of Management and Budget local government agencies, or considered three regulatory alternatives (OMB) for review and approval under geographic regions; or for dealing with the safety and the Paperwork Reduction Act of 1995 (3) Will have significant adverse environmental concerns raised by past (44 U.S.C. 3501 et seq.). The title of the effects on competition, employment, and potential future losses of well collection of information for this rule is investment, productivity, innovation, or control. BSEE has decided to move 30 CFR part 250, subpart G, Well the ability of U.S.-based enterprises to forward with this final rule (Alternative Operations and Equipment. The OMB compete with foreign-based enterprises. 1) because the other alternatives would approved the collection under Control BSEE has determined that this rule is not as efficiently or effectively address Number 1014–0028, expiration a major rule because it will have an the safety or environmental concerns 04/30/2019, 285,111 hours, $102,500 annual effect on the economy of $100 raised by various investigations and non-hour cost burdens. The information million or more in at least one year of studies related to the Deepwater collection concerns BOP system the 10-year period analyzed. The Horizon incident or achieve the requirements and maintaining well requirements apply to all entities objectives of this final rule. control among others; the information is operating on the OCS regardless of used in BSEE’s efforts to regulate oil and company designation as a small Takings Implication Assessment (E.O. gas operations on the OCS, to protect business. For more information on costs 12630) life and the environment, conserve affecting small businesses, see the Under the criteria in E.O. 12630, this natural resources, and prevent waste. Regulatory Flexibility Act section above. rule does not have significant takings Potential respondents comprise implications. The rule is not a Federal OCS oil, gas, and sulfur Unfunded Mandates Reform Act of 1995 governmental action capable of operators and lessees. The frequency of (UMRA) interference with constitutionally response varies depending upon the In accordance with UMRA, BSEE has protected property rights. A Takings requirement. Responses to this determined that this rule will not Implication Assessment is not required. collection of information are mandatory, impose an unfunded mandate on State, or are required to obtain or retain a local, or tribal governments of more Federalism (E.O. 13132) benefit. The information collection (IC) than $100 million in a single year and Under the criteria in E.O. 13132, this does not include questions of a sensitive will not have a significant or unique rule does not have federalism nature. BSEE will protect proprietary effect on State, local, or tribal implications. This rule will not information according to the Freedom of governments. BSEE has determined that substantially and directly affect the Information Act (5 U.S.C. 552) and this rule will impose costs on the relationship between the Federal and DOI’s implementing regulations (43 CFR private sector of more than $100 million State governments. To the extent that part 2), 30 CFR 250.197, Data and in a single year. Although these costs do State and local governments have a role information to be made available to the not appear to trigger the requirement to in OCS activities, this rule will not public or for limited inspection, and 30 prepare a written statement under affect that role. A federalism assessment CFR part 252, OCS Oil and Gas UMRA, DOI has chosen to prepare such is not required. Information Program.

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As stated in the preamble, BSEE reporting additional information (+466 two revised burdens: subpart B—DWOP received 172 sets of comments from responses and +2,330 hours); (¥4 hours) and subpart D—EOR (+40 individual entities (companies, industry Under § 250.724—RTM burden hours hours). ¥ organizations, or private citizens), of were increased ( 20 responses and This rule affects ICs under 30 CFR which 12 comments pertained to IC. +64,200 hours); part 250, subpart A (1014–0022, The commenters discussed the Under § 250.724(c)—we added burden expiration 8/31/2017); subpart B (1014– additional burden and felt, in some hours for the requirement to develop 0024, expiration 11/30/2018; renewal cases, that the burden was not and implement an RTM plan (+130 for this subpart is currently at OMB for necessarily sufficient. Therefore, based responses and +650 hours); approval); Applications for Permits to Under § 250.732(a)—we increased on these comments there are changes to Drill (1014–0025, expiration 4/30/17); burden hours for the requirement to the paperwork requirements and/or Applications for Permits to Modify submit a verification and supporting burdens and these changes are as (1014–0026, expiration 5/31/17); information for BAVO (+2 responses follows: subpart D (1014–0018, expiration 10/31/ and +675 hours); Applications for Permit to Drill 17); subpart E, (1014–0004, expiration The burden hours in §§ 250.740, (APD)—we increased the burden hours 12/31/16); subpart F, (1014–0001, 250.741, and 250.724(b) for retention of (+510 hours); expiration 12/31/16); subpart P, (1014– drilling records and RTM data were Applications for Permit to Modify— 0006, expiration 12/31/16); and subpart increased (+95 responses and +35 we increased the burden hours (+2,411 Q, (1014–0010, expiration 10/31/16). hours); hours); Once this final rule becomes effective, Also, while reviewing comments on During the proposed rule, we the paperwork burdens associated with the final rule it became more clear that inadvertently entered the wrong hour the various other subparts will be under § 250.712(a), (b), and (f), we were burden under the subtotal for subpart G removed from this collection of counting the number of physical rigs on (Rig. Req. 1,783 hours should have been information (subpart G) and the OCS rather than counting the 1,633 hours); therefore, we have consolidated with the respective IC number of rig movement forms decreased the subtotal (¥150 hours); burdens under their OMB Control submitted. Therefore, we increased the Also, between the proposed rule and Numbers. number of response and burden to the final rule numerous ICs were accurately reflect the number of forms submitted to OMB resulting in This rule also codifies NTL 2013–G01, submitted (+681 responses and +166 increases/decreases in OMB approved Global Positioning Systems (GPS) for hours); burdens and responses of various Mobile Offshore Drilling Units (MODUs) Under § 250.712(c), (e)—we increased regulatory requirements associated with (1014–0013, expiration 11/30/2018 the burden hours relating to the proposed rule (+577 responses and (renewal for this collection is currently notifications if rigs are warm or cold +22,797 hours) (Note: see at OMB for approval)) into subpart G. stacked (+25 responses and +12 hours); www.reginfo.gov for all of BSEE’s ICs); Once this final rule becomes effective, The burden hours for § 250.713(a), and the IC for that NTL will be (b)—information on MODUs—we Due to the IC renewals, the number of discontinued. revised the burden for collecting and responses changed, which also affected BILLING CODE 4310–VH–P

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BURDEN TABLE

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

BAVO = BSEE Approved Verification Orgamzation 30CFR Average Annual Part 250 Reporting & Recordkeeping Hour No. of Burden Current Requirement+ Burden Annual Hours Revision Responses (rounded) NEW Subpart A 107(e) Produce and submit documents ordered by Burden covered under 0 BSEE to ensure compliance with this part. various 30 CFR part 250 regulations (depending on the operational requirement(s)). 141; 198; Request approval to use new or alternative 22 1,430 31,460* 701; procedures, along with supporting requests 720(a)(2); documentation if applicable, including BAST 72l(d); not specifically covered elsewhere in 730(d)(l); regulatory requirements. 1612 142; 198; Request approval of departure from operating 3.5 405 requests 1,418* 702 requirements not specifically covered elsewhere in regulatory requirements, along with supporting documentation if applicable. 1,835 32,878 Subtotal (A) responses hours* SubpartB 287; 291; Submit DWOP and accompanying/ supporting 1,140 11 plans 12,540* 292(p) information. Provide detailed information/descriptions pertaining to pipeline free standing hybrid riser (FSHR). Submit 4 44 documentation for pipeline FSHR certification and have verified by CVA. 12,540 hours* 44 hours Subtotal (B) 11 responses 12,584 hours

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Applications for Permit to Drill (APD) 410-418; Apply for permit to drill APD (Form BSEE- 114.98 408 46,912* 420(a); 0123) that includes any/all supporting applications 423(c); documentation /evidence (including, but not 428(b), limited to, test results, calculations, pressure (k); plus integrity, kill weight fluids, verifications, various certifications, procedures, criteria, qualifications, 4 1,632 references diverter descriptions; planned safe drilling in subparts margin; rig anchor pattern plats; contingency A,D,E,F, plan (move off info/current monitoring); G (701; description of your BOP and its components and 702; schematic drawings; descriptive schematic 713(a), (pressure ratings, dimensions, valves, load (b), (e), shoulders; locking mechanisms; location of (g); ruptured disks; description ofmudline level t1 720(b); displace cement; how operator visually 721(g)(4); monitors returns; PE certification re changes 724(b); to casing setting depths; BAVO reports; 731; description of source control and containmen 733(b); capabilities; EDS; pipe variable bore rams; 734 (c); annulus monitoring plan information; any 737(a)(3), additional information required by District (b)(2), Manager; etc.) and requests for various (b)(3), approvals required in Subpart D (including§§ (d)(2) 250.414(h); 418(g); 427,428,432,460, 490(c)) through and submitted via the form; upon request, make (4), available to BSEE. (d)(12); 738(1), (m), (n); H; andP 420(b)(4); Obtain approval to revise your drilling plan 1.34 662 888* 428; [changes to the casing], or change major submittals 465(a)(1); drilling equipment by submitting a revised 721(g)(4); Form BSEE-0123, Application for Permit to 731; Drill; include BAVO certification; any other 734(c) information required by the District Manager. 47,800 hours* 1,632 hours 1,070 Subtotal (APD) responses 49,432 hours Application for Permit to Modify (APM) 460; 465; Provide revised plans and the additional 2.841 2,893 8,219* ref in supporting information required by the cited applications subparts A, regulations [test results; calculations; D, E 518(/); verifications; certifications, procedures; F, 619(/); descriptions/calculations of production G, 701; packer setting depth; BAVO 1.5 4,340 702; reports/certifications; rig anchor pattern plats; 713(a), (b), contingency plan (move off info/current (e), (g); monitoring); description of your BOP, its 720(b); components and schematic drawings; [annulus 721(g)(4); monitoring plan information]; criteria; 724(b); qualifications; etc.] when you submit an

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731; Application for Permit to Modify (APM) (Form 733(b); BSEE-0124) to BSEE for approval. 734(b)(l); 737(d)(2) through ( 4), ( d)(12); 738(f), (m), (n); H; P; andQ 1704(S<) Subparts D, Submit Revised APM plans (BSEE-0124). 1 1,551 1,551 * E,F,H,P, (This burden represents only the filling out of applications Q the form). 9,770 hours*

4,444 4,340 hours Subtotal (APM) responses 14,110 hours SubpartD 420(b)(3); Submit form BSEE-0125 (End-of-Operations 2 279 558* 465(a) Report (EOR)) and all additional supporting submittals (b)(3); plus information as required by the cited various ref regulations; and any additional information 1 279 inA,D,E, required by the District Manager. F, G, 721(g)(8); 744; P; Q (1704(h)); 421(b) Alaska only: Discuss the cement fill level with 1 1 discussion 1* the District Manager. 421(f) Submit and receive approval if unable to Burden covered under 0 cement 500 ft above previous shoe. 30 CFR part 250, subpart A (§ 250.141/142) 1014- 0022 423(c)(2) Document all your test results and make them 0.5 300 results 150* available to BSEE upon request. 428(c)(3); In the GOM OCS Region, submit drilling 1 4,160 4,160* 428(k); activity reports weekly (District Manager may submittals 743(a), (c); require more frequent submittals) on Forms 746(e); ref BSEE-0133 (Well Activity Report (WAR)) and in subparts BSEE-0133S (Bore Hole Data) with supporting A,D,G documentation. 428(c)(3); In the Pacific and Alaska Regions during 1 14 wells x 1,022* 428(k); drilling operations, submit daily drilling reports 365 days x 743(b), (c) on Forms BSEE-0133 (Well Activity Report 20%year= refinA, D, (WAR)) and BSEE-0133S (Bore Hole Data) 1,022 G with supporting documentation. 428(d) Submit all remedial actions for review and 5 1,000 5,000* approval by District Manager (before taking submittals action); and any other requirements of the District Manager. 428(d) Submit descriptions of completed immediate 5 564 2,820 actions to District Manager and any other submittals requirements ofthe District Manager.

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428(d) Submit PE certification ofany proposed 4 450 1,800 changes to your well program; and any other submittals requirements ofthe District Mana~er. 428(k) NEW: Maintain daily drilling report 0.5 75 reports 38 (cementing requirements). 428(k) NEW: If cement returns are not observed, 1 10 requests 10 contact the District Manager to obtain approval before continuing with operations. 462(c) NEW: Submit a description of source control 8 150 1,200 and containment capabilities and all supporting submittals information for approval. 462(d) NEW: Request re-evaluation of your source 1 600 600 containment capabilities from the District requests Manager and Regional Supervisor. 462(e)(1) NEW: Notify BSEE 21 days prior to pressure 0.5 150 75 testing; witness by BSEE and BAVO. notification s 6,762 10,891 responses hours* 1,014 responses 4,899 hours 985 responses 1,923 hours 8,761 17,713 Subtotal (D) responses hours SubpartE 518(f) Include in your APM descriptions and Burden covered under 0 calculations of production packer setting 1014-0026. depth(s). SubpartF 619(f) Include in your APM descriptions and Burden covered under 0 calculations of production packer setting 1014-0026. depth(s). Subpart G General Requirements 701; Request alternative procedures or equipment Burden cover under 0 720(a); from District Manager; along with any 1014-0022. 730(d)(1) supporting documentation/ information (250.141) required. 702 Request departures from District Manager; Burden cover under 0 include justification; and submit supporting 1014-0022. (250.142) documentation if applicable. Rig Requirements 710(a) Instruct crew members in safety requirements 0.75 7,512 5,634* of operations - record dates and times of meetings meetings, include potential hazards; make available to BSEE. 710(b); Prepare a well-control drill plan for each well, 0.5 308 plans 154* 738(p) including but not limited to instructions re components ofBOP, procedures, crew assignments, established times to complete assignments, etc. Keep/post a copy of the plan on the rig at all times; post on rig floor/bulletin board.

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711(b), (c) Record in the daily report: time, date, and type 1 8,320 drills 8,320* of drill conducted; time re diverter or BOP components; total time for entire drill. 712(a), Notify BSEE of all rig movements on or off 0.1 20 notices 2* (b), (f) locations. Rig movements reported on Rig Movement 0.2 151 forms 30* Notification Report (Form BSEE-0144). Including MODUs, platform rigs; snubbing units, lift boats, wire-line units, and coiled 0.2 832forms 166 tubing units 24 hours prior to movement; if the initial date changes by more than 24 hours, submit updated BSEE-0144. 712(c), (e) NEW: Notify District Manager ifMODU or 0.5 50 25 platform rig is to be warm or cold stacked on notifications Form BSEE-0144; notify District Manager where the rig is coming from when entering OCS waters. 712(d) NEW: Prior to resuming operations, report to 2 10 20 District Manager any construction repairs or responses modifications that were made to the MODU or rig. 713 Submit MODU information if being used for Burden covered under 0 well operations with your APD/APM. 1014-0025 for APD; and 1014-0026 for APM. 713(a), Collect and report additional information if 5 30 responses 150* (b) sufficient information is not available. 466 2,330 responses 713(b) Reference to Exploration Plan, Development Burden covered under 0 and Production Plan, and Development 1010-0151. Operations Coordination Document (30 CFR part 550, subpart B). 713(c)(1) Submit 3rd party review of drilling unit Burden covered under 0 according to 30 CFR part 250, subpart I. 1014-0011. 713(c)(2); Have a Contingency Plan that addresses design Burden covered under 0 (417)(c)(2 and operating limitations ofMODU. 1014-0025. ) 713(d) Submit current certificate of inspection! Burden covered under 0 417(d) compliance from USCG and classification; 1014-0025. submit documentation of operational limitations by a classification society. 714 NEW: Develop and implement dropped 40 40 plans 1,600 objects plan with supporting documentation! information; any additional information required by the District Manager; make available to BSEE upon request.

715; NTL GPS for MODUs 0.25 1 rig 1* 1-Notify BSEE with tracking/locator data access and supporting information; notify BSEE Hurricane Response Team as soon as 1 operator is aware a rig has moved off location. notification 2 -Install and protect tracking/locator devices - 20 devices per year for replacement (these are replacement GPS devices or new). and/or new x $325.00 = $6,500*.

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3 - Pay monthly tracking fee for GPS devices 40 rigs x $50/month = ($600/year per 1 already placed on MODUs. rig) = $24,000*. 4 - Rent GPS devices and pay monthly 40 rigs@ $1,800 per year= $72,000*. tracking fee per MODU. 16,343 14,291 responses hours* 1,298 responses 2,496 hours 100 responses 1,645 hours 17,741 responses 18,432 hours $102,500 Non-hour cost Subtotal (G- Rig Req.) burdens* Well Operations 720(a) NEW: Notify and obtain approval from the 5 150 750 District Manager when interrupting operations. notifications 720(a)(2) Request approval to use alternate Burden covered under 0 procedures/barriers. 1014-0022. 720(b) Submit with your APD or APM reasons for Burden covered under 0 displacing kill-weight fluid with detailed 1014-0025 for APD; procedures with relevant information of and 10 14-0026 for section. APM. 721(d), Submit to the District Manager for approval 0.5 88 requests 44* (f), (g) plans tore-cement, repair, or run additional casing/liner, include PE certification of proposed plans. 721(g)(4) Submit test procedures and criteria for a Burden covered under 0 successful test with APD/APM; if changes 1014-0025 for APD; made to procedures, submit changes with and 10 14-0026 for revised APD or APM. APM. 721(g)(5) Document all your test results; make available 0.75 1,340 results 1,005* to BSEE upon request. 721(g)(6) Notify District Manager immediately of 1 14 14* indication of failed negative pressure test; notifications submit description of corrective action taken; receive approval to retest. 721(g)(8); Submit Form BSEE-0125, EOR. Burden covered under 0 744(a) 1014-0018. 722 Caliper, pressure test, or evaluate casing; 3 247 reports 741* submit evaluation results report including calculations; obtain approval before repairing or installing additional casing; PE Certification; or resuming operations (every 30 days during prolonged drilling).

722(b)(3) NEW: Perform a pressure test after repairs 1 300 results 300 made/casing installed and report results. 723(d) Request exceptions prior to moving rig(s) or 1.5 845 requests 1,268* related equipment. 724 NEW: Transmit real-time monitoring (RTM) 2,160 30 rigs 64,800 data onshore during operations or in HPHT reservoirs; store and monitor by qualified personnel. Provide BSEE access to RTM data storage locations upon request.

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724(c) NEW: Develop and implement a RTM plan 5 130 plans 650 that includes all required data of this section; make available to BSEE upon request. 724(b) NEW: Include in your APD a certification that Burden covered under 0 you have such a plan and meet criteria of this 1014-0025 for APD; section. and 1014-0026 for APM. 2,534 responses 3,072 hours* 610 66,500 responses hours 3,144 Subtotal (G- Well Op.) responses 69,572 hours BOP System Requirements 730(a)(4) NEW: Maintain current set of approved 24 10 requests 240 schematic drawings on rig and onshore location; obtain approval to resume operations if modified/changed. 730(c)(1) NEW: Provide written notice within 30 days 2 30 reports 60 of discovery/identification of equipment failure. 730(c)(2) NEW: Provide BSEE and manufacturer a 5 30 reports 150 copy of analysis report re equipment failure. 730(c)(3) NEW: Document all results and any 5 2 reports 10 corrective action re failure analysis. Submit report re design change/modified procedures within 30 days of manufacturer's notification. 730(d)(1) NEW: Request alternate approval from using 5 1 response 5 to API Spec. Q I. 731 Submit/resubmit BOP component information Burden covered under 0 in APD/APM and certification that verifies 1014-0025 for APD; changes or moved offlocation. and 10 14-0026 for APM. 732(a) NEW: Request and submit for approval all 100 7 700 relevant information to become a BAVO. applications 732(b) NEW: Submit BAVO verification and all 10 150 1,500 supporting documentation related to this verifications section (such as, but not limited to shearing testing, pressure integrity testing, calculations, etc.). 732(c) NEW: Submit verifications, before beginning 10 10 wells 100 operations in HPHT environment, that a BAVO conducted detailed reviews of the BOP and related equipment. 732(d), (e) NEW: Submit a BAVO Mechanical Integrity 10 90 reports 900 Assessment Report that includes all information from this section; make all documentation available to BSEE upon request. 733(b)(2) NEW: Describe in your APD or APM your Burden covered under 0 annulus monitoring plan. 1014-0025 for APD; and 10 14-0026 for APM. 734(a)(7) Demonstrate acoustic control system will 5 I validation 5*

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function properly in environment and I IO 10 conditions; submit any additional information submittals requested. 734(a)(9); Label all functions on all panels. 1.5 33 panels 50* 738(n) 734(a)(10) Develop written procedures for operating the Burden covered under 0 BOP stack, LMRP, and minimum knowledge 1014-0018. requirements for personnel authorized to operate/maintain BOP components. 734(b), (c) Before resuming operations, submit a revised Burden covered under 0 APDl AP M with BA VO report documenting 1014-0025 for APD; repairs; perform a new BOP test upon relatch, and 10 14-0026 for etc.; receive approval from the District APM. Manager. 737(a)(3), In your APD: submit stump, initial, or pressure Burden covered under 0 (a)(4); tests; and subsea BOP procedures and 1014-0025. {b)(2), supporting relevant data/information including, {b)(3); but not limited to, casing string and liner; quick (d)(2) disconnect procedures with your deadman test through procedures, etc. Obtain approval of test (4), d)(12) pressures. 737(c); Record time, date, and results of all pressure 7.75 4,457 results 34,542* 746(a), tests, actuations, and inspections of the BOP (b), (c), system, its components, and marine riser in the (d) daily report; onsite rep certify and sign/date reports, etc.; document sequential order of BOP, closing times, auxiliary testing, pressure, and duration of each test. 737(d)(2), Notify District Manager 72 hours prior to 0.25 186 47* {d)(3), testing; ifBSEE unable to witness test, provide notifications {d)(4); results to BSEE within 72 hours after 5.5 1,239 results 6,815* completion; document all ROV test results; make available to BSEE upon request. 737(d) Document all autoshear, EDS, and deadman 0.5 2,520 1,260* (12) test results; make available to BSEE upon submittals request. I I20 I20 responses 737(e) Provide 72 hour advance notice of location of 0.25 136 notices 34* shearing ram tests or inspections. 738; NEW/Revised: Requires District Manager 0.5 25 requests 13 746(e) Approval: 1 25 requests 25 (a), (d); 746(e) Report problems, issues, leaks; 1 25 requests 25 (b) Put well in a safe condition; 0.25 200 requests 50* (b) Prior to resuming operations for new/repaired/reconfigured BOP I I5 requests I5 (g) Your well control places demands above its rating pressure; 1 1 request 1 G) Two barriers in place prior to BOP removal. 738(b), (i) NEW: Submit a BAVO report/verification 0.5 50 25 that BOP is fit for service. submittals 738(f) NEW: Notify District Manager of BOP 0.5 15 8 configuration changes. submittals 738(g) NEW: Demonstrate well-control procedures 1 15 15 will not place demands above its working submittals

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pressure. 738(k) NEW: Contact and obtain for approval prior 1 2 requests 2 to latching up BOP stack/re-establishing power. 738(m) NEW: Request approval in your APD or APM Burden covered under 0 to utilize any other well-control equipment. 1014-0025 for APD; and 10 14-0026 for APM. 738(m) NEW: Request approval to utilize any other 2 10 requests 20 well-control equipment; include BAVO report re-equipment design and suitability; any other documentation/information required by District Manager. 738(n) NEW: Include in your APD or APM which Burden covered under 0 pipe/variable bore rams meet the criteria. 1014-0025 for APD; and 10 14-0026 for APM. 738(o) NEW: Submit BAVO report re failure of 1 15 15 redundant control and confirming no impact to submittals the BOP that makes it unfit; receive approval to continue operations; submit any additional information requested by the District Manager. 739 Document how you meet/exceed API 9.75 350 records 3,413* Standard 53; maintain complete records; track/document all inspection dates; maintain all records including but not limited to equipment schematics, maintenance, inspection, repair, etc., for 2 years or longer if directed on the rig; all equipment schematics, maintenance, inspection, repair records are located onshore for service life of equipment; make available to BSEE upon request. 739(b) NEW: A BAVO report documenting 5 21 reports 105 inspection, including problems and how corrected; make reports available to BSEE upon request. 9,122 46,216 responses hours* 145 145 responses hours 534 3,919 responses hours 9,801 50,280 Subtotal (G- BOP SR) responses hours Records and Reporting Requirement 740; Maintain daily report/records onsite during 25 min 312 reports 130* 71l(b); operations include, but not limited to, date, 724(b); time, type of drill, test results; any information 1 25 25 738(c); required by the District Manager. responses 745;746 740; 741; Retain drilling records for 90 days after drilling 2.15 3,460 7,439* 724(b) complete; retain casing/liner pressure, diverter, records BOP tests, real-time monitoring data for 2 0.5 120 records 60 years after completion; any other information requested by the District Manager.

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742; Submit copies oflogs/charts of electrical, 3 281logs/ 843* NTL radioactive, sonic, or other well logging surveys operations. Submit copies of directional and vertical-well 1 281 reports 281* surveys. Submit copies of velocity profiles and surveys. 1 55 reports 55* Record and submit core analyses. 1 150 analyses 150* 743(a), (c) In the GOM OCS Region, submit Well Burden covered under 0 Activity Reports (WARs) weekly (District 1014-0018. Manager may require more frequent submittals) on BSEE-0133 and BSEE-0133S (Open Hole Data Report) with supporting information described in this section; any additional information required by the District Mana~er. 743(b), (c) In the Pacific and Alaska OCS Regions during Burden covered under 0 operations, submit WARs daily (BSEE-0133 1014-0018. and BSEE-0133S); with supporting information described in this section; any additional information required by the District Manager. 744 Submit form BSEE-0125, EOR. Burden covered under 0 1014-0018. 745; NTL Submit copies of well records; paleontological 1.5 308 462* interpretations; service company reports; and submissions other reports or records of operations to BSEE as requested. 746 Record the time, date, and results of all casing 2 4,160 results 8,320* and liner presser tests. 746(f) Retain all records pertaining to pressure tests, 1.5 1,563 2,345* actuations, and inspections in daily report etc.; records retain all records listed in this section on the rig unit for the duration of operation; after completion, retain all records listed in this section for 2 years on rig unit and at the lessee's field office conveniently available to BSEE; make all the records available upon request.

10,570 20,025 responses hours* 145 85 responses hours 10,715 20,110 Subtotal (G- Rec. & Rpt. Req.) responses hours

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

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BILLING CODE 4310–VH–C C, sec. 515, 114 Stat. 2763, 2763A–153– Environmental Enforcement (BSEE) An agency may not conduct or 154). amends 30 CFR part 250 as follows: sponsor, and you are not required to respond to, a collection of information Effects on the Nation’s Energy Supply PART 250—OIL AND GAS AND unless it displays a currently valid OMB (E.O. 13211) SULFUR OPERATIONS IN THE OUTER control number. The public may This rule is not a significant energy CONTINENTAL SHELF comment, at any time, on the accuracy action under the definition in E.O. of the IC burden in this rule and may 13211. Although the rule is a significant ■ submit any comments to DOI/BSEE; 1. The authority citation for part 250 regulatory action under E.O. 12866, it is ATTN: Regulations and Standards continues to read as follows: not likely to have a significant adverse Branch; VAE–ORP; 45600 Woodland Authority: 30 U.S.C. 1751, 31 U.S.C. 9701, effect on the supply, distribution, or use Road, Sterling, VA 20166; or email at 43 U.S.C. 1334. of energy. A Statement of Energy Effects [email protected]; (703) 787–1607. is not required. Subpart A—General National Environmental Policy Act of List of Subjects in 30 CFR Part 250 1969 (NEPA) ■ 2. Amend § 250.102 by: Administrative practice and We prepared a final environmental ■ assessment that concludes that this final procedure, Continental shelf, a. Revising paragraphs (b)(1) and (11) rule would not have a significant impact Environmental impact statements, through (13); and on the quality of the human Environmental protection, Incorporation ■ b. Adding paragraph (b)(19). by reference, Oil and gas exploration, environment under NEPA. A copy of the The revisions and addition read as Outer Continental Shelf—mineral Environmental Assessment and Finding follows: of No Significant Impact can be viewed resources, Outer Continental Shelf— at www.regulations.gov (use the rights-of-way, Penalties, Reporting and § 250.102 What does this part do? recordkeeping requirements, Sulfur. keyword/ID BSEE–2015–0002). * * * * * Data Quality Act Janice M. Schneider, (b) * * * In developing this rule, we did not Assistant Secretary, Land and Minerals Management. conduct or use a study, experiment, or survey requiring peer review under the For the reasons stated in the Data Quality Act (Pub. L. 106–554, app. preamble, the Bureau of Safety and

TABLE—WHERE TO FIND INFORMATION FOR CONDUCTING OPERATIONS

For information about . . . Refer to . . .

(1) Applications for permit to drill (APD), ...... 30 CFR 250, subparts D and G.

******* (11) Oil and gas well-completion operations, ...... 30 CFR 250, subparts E and G. (12) Oil and gas well-workover operations, ...... 30 CFR 250, subparts F and G. (13) Decommissioning activities, ...... 30 CFR 250, subparts G and Q.

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TABLE—WHERE TO FIND INFORMATION FOR CONDUCTING OPERATIONS—Continued

For information about . . . Refer to . . .

******* (19) Well operations and equipment, ...... 30 CFR 250, subpart G.

■ 3. Amend § 250.107 by: (3) Utilizing recognized engineering may also issue orders to shut-in ■ a. Removing the word ‘‘and’’ from the practices that reduce risks to the lowest operations of a component or facility end of paragraph (a)(1); level practicable when conducting because of a threat of serious, ■ design, fabrication, installation, irreparable, or immediate harm to b. Removing the period from the end operation, inspection, repair, and health, safety, property, or the of paragraph (a)(2) and adding in its maintenance activities; and environment posed by those operations place a semicolon; and (4) Complying with all lease, plan, or because the operations violate law, ■ c. Adding paragraphs (a)(3) and (4) and permit terms and conditions. including a regulation, order, or and (e). * * * * * provision of a lease, plan, or permit. The additions read as follows: (e) BSEE may issue orders to ensure ■ 4. In § 250.125, revise the table in compliance with this part, including, paragraph (a) to read as follows: § 250.107 What must I do to protect health, but not limited to, orders to produce safety, property, and the environment? and submit records and to inspect, § 250.125 Service fees. (a) * * * repair, and/or replace equipment. BSEE (a) * * *

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

(1) Suspension of Operations/Suspension of $2,123 ...... § 250.171(e). Production (SOO/SOP) Request. (2) Deepwater Operations Plan (DWOP) ...... 3,599 ...... § 250.292(q). (3) Application for Permit to Drill (APD); Form $2,113 for initial applications only; no fee for § 250.410(d); § 250.513(b); § 250.1617(a). BSEE–0123. revisions.. (4) Application for Permit to Modify (APM); 125 ...... § 250.465(b); § 250.513(b); § 250.613(b); Form BSEE–0124. § 250.1618(a); § 250.1704(g). (5) New Facility Production Safety System Ap- $5,426 A component is a piece of equipment § 250.802(e). plication for facility with more than 125 com- or ancillary system that is protected by one ponents. or more of the safety devices required by API RP 14C (as incorporated by reference in § 250.198); $14,280 additional fee will be charged if BSEE deems it necessary to visit a facility offshore, and $7,426 to visit a fa- cility in a shipyard.. (6) New Facility Production Safety System Ap- $1,314 Additional fee of $8,967 will be § 250.802(e). plication for facility with 25–125 components. charged if BSEE deems it necessary to visit a facility offshore, and $5,141 to visit a fa- cility in a shipyard.. (7) New Facility Production Safety System Ap- 652 ...... § 250.802(e). plication for facility with fewer than 25 com- ponents. (8) Production Safety System Application— 605 ...... § 250.802(e). Modification with more than 125 components reviewed. (9) Production Safety System Application— 217 ...... § 250.802(e). Modification with 25–125 components re- viewed. (10) Production Safety System Application— 92 ...... § 250.802(e). Modification with fewer than 25 components reviewed. (11) Platform Application—Installation—Under 22,734 ...... § 250.905(l). the Platform Verification Program. (12) Platform Application—Installation—Fixed 3,256 ...... § 250.905(l). Structure Under the Platform Approval Pro- gram. (13) Platform Application—Installation—Cais- 1,657 ...... § 250.905(l) son/Well Protector. (14) Platform Application—Modification/Repair .. 3,884 ...... § 250.905(l). (15) New Pipeline Application (Lease Term) ..... 3,541 ...... § 250.1000(b). (16) Pipeline Application—Modification (Lease 2,056 ...... § 250.1000(b). Term). (17) Pipeline Application—Modification (ROW) 4,169 ...... § 250.1000(b). (18) Pipeline Repair Notification ...... 388 ...... § 250.1008(e). (19) Pipeline Right-of-Way (ROW) Grant Appli- 2,771 ...... § 250.1015(a). cation. (20) Pipeline Conversion of Lease Term to 236 ...... § 250.1015(a). ROW.

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

(21) Pipeline ROW Assignment ...... 201 ...... § 250.1018(b). (22) 500 Feet From Lease/Unit Line Production 3,892 ...... § 250.1156(a). Request. (23) Gas Cap Production Request ...... 4,953 ...... § 250.1157. (24) Downhole Commingling Request ...... 5,779 ...... § 250.1158(a). (25) Complex Surface Commingling and Meas- 4,056 ...... § 250.1202(a); § 250.1203(b); § 250.1204(a). urement Application. (26) Simple Surface Commingling and Meas- 1,371 ...... § 250.1202(a); § 250.1203(b); § 250.1204(a). urement Application. (27) Voluntary Unitization Proposal or Unit Ex- 12,619 ...... § 250.1303(d). pansion. (28) Unitization Revision ...... 896 ...... § 250.1303(d). (29) Application to Remove a Platform or Other 4,684 ...... § 250.1727. Facility. (30) Application to Decommission a Pipeline 1,142 ...... § 250.1751(a) or (Lease Term). § 250.1752(a). (31) Application to Decommission a Pipeline 2,170 ...... § 250.1751(a) or (ROW). § 250.1752(a).

* * * * * (68) ANSI/API Specification Q1, Reaffirmed July 2010; incorporated by ■ 5. Amend § 250.198 by: Specification for Quality Programs for reference at § 250.730; ■ a. Revising paragraphs (h)(51), (63), the Petroleum, Petrochemical and (92) API Specification 16D, (68), and (70); and Natural Gas Industry, Eighth Edition, Specification for Control Systems for ■ b. Removing the period at the end of December 2007, incorporated by Drilling Well Control Equipment and paragraph (h)(88) and adding a reference at §§ 250.730 and 250.806; Control Systems for Diverter Equipment, semicolon in its place; and * * * * * Second Edition, July 2004, Reaffirmed ■ c. Adding paragraphs (h)(89) through (70) ANSI/API Specification 6A, August 2013, incorporated by reference (94). Specification for Wellhead and at § 250.730; The revisions and additions read as Christmas Tree Equipment, Nineteenth (93) ANSI/API Specification 17D, follows: Edition, July 2004, including Errata 1 Design and Operation of Subsea (September 2004), Errata 2 (April 2005), Production Systems—Subsea Wellhead § 250.198 Documents incorporated by Errata 3 (June 2006), Errata 4 (August reference. and Tree Equipment, Second Edition; 2007), Errata 5 (May 2009), Addendum * * * * * May 2011, incorporated by reference at 1 (February 2008), Addenda 2, 3, and 4 § 250.730; and (h) * * * (December 2008), incorporated by (94) ANSI/API Recommended (51) API Recommended Practice 2RD, reference at §§ 250.730, 250.806, and Practice 17H, Remotely Operated Design of Risers for Floating Production 250.1002; Systems (FPSs) and Tension-Leg Vehicle Interfaces on Subsea Production Platforms (TLPs), First Edition, June * * * * * Systems, First Edition, July 2004, (89) ANSI/API Specification 11D1, 1998; Reaffirmed May 2006, including Reaffirmed January 2009, incorporated Packers and Bridge Plugs, Second Errata June 2009, incorporated by by reference at § 250.734. Edition, July 2009, incorporated by reference at §§ 250.292, 250.733, reference at §§ 250.518, 250.619, and * * * * * 250.800, 250.901, and 250.1002; 250.1703; ■ 6. In § 250.199, revise paragraph (e) to * * * * * (90) ANSI/API Specification 16A, read as follows: (63) API Standard 53, Blowout Specification for Drill-through Prevention Equipment Systems for Equipment, Third Edition, June 2004, § 250.199 Paperwork Reduction Act statements—information collection. Drilling Wells, Fourth Edition, Reaffirmed August 2010, incorporated November 2012, incorporated by by reference at § 250.730; * * * * * reference at §§ 250.730, 250.735, (91) ANSI/API Specification 16C, (e) BSEE is collecting this information 250.737, and 250.739; Specification for Choke and Kill for the reasons given in the following * * * * * Systems, First Edition, January 1993, table:

30 CFR Subpart, title and/or BSEE Form (OMB Control No.) BSEE collects this information and uses it to:

(1) Subpart A, General (1014–0022), including Forms BSEE–0011, iSEE; BSEE– (i) Determine that activities on the OCS comply with stat- 0132, Evacuation Statistics; BSEE–0143, Facility/Equipment Damage Report; utory and regulatory requirements; are safe and pro- BSEE–1832, Notification of Incidents of Noncompliance. tect the environment; and result in diligent develop- ment and production on OCS leases. (ii) Support the unproved and proved reserve estimation, resource assessment, and fair market value deter- minations. (iii) Assess damage and project any disruption of oil and gas production from the OCS after a major natural oc- currence. (2) Subpart B, Plans and Information (1014–0024) ...... Evaluate Deepwater Operations Plans for compliance with statutory and regulatory requirements (3) Subpart C, Pollution Prevention and Control (1014–0023) ...... (i) Evaluate measures to prevent unauthorized discharge of pollutants into the offshore waters.

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30 CFR Subpart, title and/or BSEE Form (OMB Control No.) BSEE collects this information and uses it to:

(ii) Ensure action is taken to control pollution. (4) Subpart D, Oil and Gas and Drilling Operations (1014–0018), including Forms (i) Evaluate the equipment and procedures to be used in BSEE–0125, End of Operations Report; BSEE–0133, Well Activity Report; and drilling operations on the OCS. BSEE–0133S, Open Hole Data Report. (ii) Ensure that drilling operations meet statutory and regulatory requirements. (5) Subpart E, Oil and Gas Well-Completion Operations (1014–0004) ...... (i) Evaluate the equipment and procedures to be used in well-completion operations on the OCS. (ii) Ensure that well-completion operations meet statutory and regulatory requirements. (6) Subpart F, Oil and Gas Well Workover Operations (1014–0001) ...... (i) Evaluate the equipment and procedures to be used during well-workover operations on the OCS. (ii) Ensure that well-workover operations meet statutory and regulatory requirements. (7) Subpart G, Blowout Preventer Systems (1014–0028), including Form BSEE–0144, (i) Evaluate the equipment and procedures to be used Rig Movement Notification Report. during well drilling, completion, workover, and aban- donment operations on the OCS. (ii) Ensure that well operations meet statutory and regu- latory requirements. (8) Subpart H, Oil and Gas Production Safety Systems (1014–0003) ...... (i) Evaluate the equipment and procedures that will be used during production operations on the OCS. (ii) Ensure that production operations meet statutory and regulatory requirements. (9) Subpart I, Platforms and Structures (1014–0011) ...... (i) Evaluate the design, fabrication, and installation of platforms on the OCS. (ii) Ensure the structural integrity of platforms installed on the OCS. (10) Subpart J, Pipelines and Pipeline Rights-of-Way (1014–0016), including Form (i) Evaluate the design, installation, and operation of BSEE–0149, Assignment of Federal OCS Pipeline Right-of-Way Grant. pipelines on the OCS. (ii) Ensure that pipeline operations meet statutory and regulatory requirements. (11) Subpart K, Oil and Gas Production Rates (1014–0019), including Forms BSEE– (i) Evaluate production rates for hydrocarbons produced 0126, Well Potential Test Report and BSEE–0128, Semiannual Well Test Report. on the OCS. (ii) Ensure economic maximization of ultimate hydro- carbon recovery. (12) Subpart L, Oil and Gas Production Measurement, Surface Commingling, and Se- (i) Evaluate the measurement of production, commin- curity (1014–0002). gling of hydrocarbons, and site security plans. (ii) Ensure that produced hydrocarbons are measured and commingled to provide for accurate royalty pay- ments and security. (13) Subpart M, Unitization (1014–0015) ...... (i) Evaluate the unitization of leases. (ii) Ensure that unitization prevents waste, conserves natural resources, and protects correlative rights. (14) Subpart N, Remedies and Penalties ...... (The requirements in subpart N are exempt from the Pa- perwork Reduction Act of 1995 according to 5 CFR 1320.4). (15) Subpart O, Well Control and Production Safety Training (1014–0008) ...... (i) Evaluate training program curricula for OCS workers, course schedules, and attendance. (ii) Ensure that training programs are technically accu- rate and sufficient to meet statutory and regulatory re- quirements, and that workers are properly trained. (16) Subpart P, Sulfur Operations (1014–0006) ...... (i) Evaluate sulfur exploration and development oper- ations on the OCS. (ii) Ensure that OCS sulfur operations meet statutory and regulatory requirements and will result in diligent development and production of sulfur leases. (17) Subpart Q, Decommissioning Activities (1014–0010) ...... Ensure that decommissioning activities, site clearance, and platform or pipeline removal are properly per- formed to meet statutory and regulatory requirements and do not conflict with other users of the OCS. (18) Subpart S, Safety and Environmental Management Systems (1014–0017), in- (i) Evaluate operators’ policies and procedures to assure cluding Form BSEE–0131, Performance Measures Data. safety and environmental protection while conducting OCS operations (including those operations conducted by contractor and subcontractor personnel). (ii) Evaluate Performance Measures Data relating to risk and number of accidents, injuries, and oil spills during OCS activities. (19) Application for Permit to Drill (APD, Revised APD), Form BSEE–0123; and Sup- (i) Evaluate and approve the adequacy of the equip- plemental APD Information Sheet, Form BSEE–0123S, and all supporting docu- ment, materials, and/or procedures that the lessee or mentation (1014–0025). operator plans to use during drilling. (ii) Ensure that applicable OCS operations meet statu- tory and regulatory requirements.

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30 CFR Subpart, title and/or BSEE Form (OMB Control No.) BSEE collects this information and uses it to:

(20) Application for Permit to Modify (APM), Form BSEE–0124, and supporting docu- (i) Evaluate and approve the adequacy of the equip- mentation (1014–0026). ment, materials, and/or procedures that the lessee or operator plans to use during drilling and to evaluate well plan modifications and changes in major equip- ment. (ii) Ensure that applicable OCS operations meet statu- tory and regulatory requirements.

Subpart B—Plans and Information (3) A description of how you met the or damage to life (including fish and design requirements, load cases, and other aquatic life), property, natural ■ 7. Amend § 250.292 by: allowable stresses for each load case resources of the Outer Continental Shelf ■ a. Removing the word ‘‘and’’ from the according to API RP 2RD (as (OCS), including any mineral deposits end of paragraph (o); incorporated by reference in § 250.198); (in areas leased and not leased), the ■ b. Redesignating paragraph (p) as (4) Detailed information regarding the National security or defense, or the paragraph (q); and tether system used to connect the FSHR marine, coastal, or human environment. ■ c. Adding new paragraph (p). to a buoyancy air can; In addition to the requirements of this The addition reads as follows: (5) Descriptions of your monitoring subpart, you must also follow the system and monitoring plan to monitor applicable requirements of subpart G of § 250.292 What must the DWOP contain? the pipeline FSHR and tether for fatigue, this part. * * * * * stress, and any other abnormal (p) If you propose to use a pipeline condition (e.g., corrosion) that may §§ 250.401 through 250.403 [Removed and Reserve] free standing hybrid riser (FSHR) on a negatively impact the riser or tether; and permanent installation that utilizes a (6) Documentation that the tether ■ 9. Remove and reserve §§ 250.401 critical chain, wire rope, or synthetic system and connection accessories for through 250.403. tether to connect the top of the riser to the pipeline FSHR have been certified a buoyancy air can, provide the by an approved classification society or § 250.406 [Removed and Reserve] following information in your DWOP in equivalent and verified by the CVA ■ 10. Remove and reserve § 250.406. required in subpart I of this part; and the discussions required by paragraphs ■ 11. Revise § 250.411 to read as (f) and (g) of this section: * * * * * follows: (1) A detailed description and drawings of the FSHR, buoy and the Subpart D—Oil and Gas Drilling § 250.411 What information must I submit tether system; Operations with my application? (2) Detailed information on the ■ 8. Revise § 250.400 to read as follows: In addition to forms BSEE–0123 and design, fabrication, and installation of BSEE–0123S, you must include the the FSHR, buoy and tether system, § 250.400 General requirements. information required in this subpart and including pressure ratings, fatigue life, Drilling operations must be conducted subpart G of this part, including the and yield strengths; in a safe manner to protect against harm following:

Information that you must include with an APD Where to find a description

(a) Plat that shows locations of the proposed well, ...... § 250.412. (b) Design criteria used for the proposed well, ...... § 250.413. (c) Drilling prognosis, ...... § 250.414. (d) Casing and cementing programs, ...... § 250.415. (e) Diverter systems descriptions, ...... § 250.416. (f) BOP system descriptions, ...... § 250.731. (g) Requirements for using a MODU, and ...... § 250.713. (h) Additional information...... § 250.418.

■ 12. In § 250.413, revise paragraph (g) ■ b. Adding paragraphs (j) and (k). (1) Your safe drilling margin must to read as follows: The revisions and additions read as also include use of equivalent downhole mud weight that is: § 250.413 What must my description of follows: well drilling design criteria address? (i) Greater than the estimated pore § 250.414 What must my drilling prognosis pressure; and * * * * * include? (ii) Except as provided in paragraph (g) A single plot containing curves for * * * * * (c)(2) of this section, a minimum of 0.5 estimated pore pressures, formation pound per gallon below the lower of the fracture gradients, proposed drilling (c) Planned safe drilling margin that is between the estimated pore pressure casing shoe pressure integrity test or the fluid weights, planned safe drilling lowest estimated fracture gradient. margin, and casing setting depths in and the lesser of estimated fracture (2) In lieu of meeting the criteria in true vertical measurements; gradients or casing shoe pressure integrity test and that is based on a risk paragraph (c)(1)(ii) of this section, you * * * * * may use an equivalent downhole mud assessment consistent with expected ■ 13. Amend § 250.414 by: weight as specified in your APD, well conditions and operations. ■ a. Revising paragraphs (c), (h), and (i); provided that you submit adequate and documentation (such as risk modeling

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data, off-set well data, analog data, ■ 15. Revise § 250.416 to read as ■ d. Revising paragraph (c). seismic data) to justify the alternative follows: The revisions and additions read as equivalent downhole mud weight. follows: (3) When determining the pore § 250.416 What must I include in the pressure and lowest estimated fracture diverter description? § 250.420 What well casing and cementing gradient for a specific interval, you must You must include in the diverter requirements must I meet? consider related off-set well behavior description: You must case and cement all wells. observations. (a) A description of the diverter Your casing and cementing programs system and its operating procedures; * * * * * must meet the applicable requirements (b) A schematic drawing of the (h) A list and description of all of this subpart and of subpart G of this diverter system (plan and elevation requests for using alternate procedures part. views) that shows: or departures from the requirements of (1) The size of the element installed (a) * * * this subpart in one place in the APD. in the diverter housing; (5) Support unconsolidated You must explain how the alternate (2) Spool outlet internal diameter(s); sediments; procedures afford an equal or greater (3) Diverter-line lengths and (6) Provide adequate centralization to degree of protection, safety, or diameters; burst strengths and radius of ensure proper cementation; and performance, or why the departures are curvature at each turn; and * * * * * requested; (4) Valve type, size, working pressure (i) Projected plans for well testing (b) * * * rating, and location. (refer to § 250.460); (4) If you need to substitute a different (j) The type of wellhead system and § 250.417 [Removed and Reserved] size, grade, or weight of casing than liner hanger system to be installed and ■ 16. Remove and reserve § 250.417. what was approved in your APD, you a descriptive schematic, which includes must contact the District Manager for ■ 17. In § 250.418, revise paragraphs (g) but is not limited to pressure ratings, approval prior to installing the casing. and (h), remove paragraph (i), and dimensions, valves, load shoulders, and * * * * * locking mechanisms, if applicable; and redesignate paragraph (j) as paragraph (k) Any additional information (i) to read as follows: (c) Cementing requirements. (1) You must design and conduct your required by the District Manager needed § 250.418 What additional information to clarify or evaluate your drilling cementing jobs so that cement must I submit with my APD? composition, placement techniques, and prognosis. * * * * * ■ waiting times ensure that the cement 14. In § 250.415, revise paragraph (a) (g) A request for approval, if you plan placed behind the bottom 500 feet of to read as follows: to wash out or displace cement to casing attains a minimum compressive § 250.415 What must my casing and facilitate casing removal upon well strength of 500 psi before drilling out cementing programs include? abandonment. Your request must the casing or before commencing * * * * * include a description of how far below completion operations. (If a liner is used (a) The following well design the mudline you propose to displace refer to § 250.421(f)). information: cement and how you will visually (2) You must use a weighted fluid (1) Hole sizes; monitor returns; during displacement to maintain an (2) Bit depths (including measured (h) Certification of your casing and overbalanced hydrostatic pressure and true vertical depth (TVD)); cementing program as required in during the cement setting time, except (3) Casing information, including § 250.420(a)(7); and when cementing casings or liners in sizes, weights, grades, collapse and * * * * * riserless hole sections. burst values, types of connection, and ■ 18. Amend § 250.420 by: ■ 19. In § 250.421, revise paragraphs (b) setting depths (measured and TVD) for ■ a. Revising the introductory text and and (f) to read as follows: all sections of each casing interval; and paragraph (a)(5); (4) Locations of any installed rupture ■ b. Redesignating paragraph (a)(6) as § 250.421 What are the casing and disks (indicate if burst or collapse and paragraph (a)(7); cementing requirements by type of casing rating); ■ c. Adding new paragraph (a)(6) and string? * * * * * paragraph (b)(4); and * * * * *

Casing type Casing requirements Cementing requirements

******* (b) Conductor ...... Design casing and select setting depths based on rel- Use enough cement to fill the calculated annular space evant engineering and geologic factors. These fac- back to the mudline. tors include the presence or absence of hydro- Verify annular fill by observing cement returns. If you carbons, potential hazards, and water depths. cannot observe cement returns, use additional ce- Set casing immediately before drilling into formations ment to ensure fill-back to the mudline. known to contain oil or gas. If you encounter oil or For drilling on an artificial island or when using a well gas or unexpected formation pressure before the cellar, you must discuss the cement fill level with the planned casing point, you must set casing imme- District Manager. diately and set it above the encountered zone.

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Casing type Casing requirements Cementing requirements

*******

(f) Liners ...... If you use a liner as surface casing, you must set the Same as cementing requirements for specific casing top of the liner at least 200 feet above the previous types. For example, a liner used as intermediate cas- casing/liner shoe. ing must be cemented according to the cementing If you use a liner as an intermediate string below a sur- requirements for intermediate casing. If you have a face string or production casing below an inter- liner lap and are unable to cement 500 feet above mediate string, you must set the top of the liner at the previous shoe, as provided by paragraphs (d) least 100 feet above the previous casing shoe. and (e) of this section, you must submit and receive You may not use a liner as conductor casing ...... approval from the District Manager on a case-by- A subsea well casing string whose top is above the case basis. mudline and that has been cemented back to the mudline will not be considered a liner.

■ 20. Revise § 250.423 to read as inadequate cement job, you must § 250.427 What are the requirements for follows: comply with § 250.428(c). pressure integrity tests? (c) You must perform a pressure test * * * * * § 250.423 What are the requirements for on the casing seal assembly to ensure (b) While drilling, you must maintain casing and liner installation? proper installation of casing or liner. the safe drilling margins identified in You must ensure proper installation You must perform this test for the § 250.414. When you cannot maintain of casing in the subsea wellhead or liner intermediate and production casing the safe margins, you must suspend in the liner hanger. strings or liners. (a) You must ensure that the latching (1) You must submit for approval with drilling operations and remedy the mechanisms or lock down mechanisms your APD, test procedures and criteria situation. are engaged upon successfully installing for a successful test. ■ 23. Amend § 250.428 by: and cementing the casing string. If there (2) You must document all your test ■ a. Revising paragraphs (b) through (d); is an indication of an inadequate cement results and make them available to and job, you must comply with § 250.428(c). BSEE upon request. (b) If you run a liner that has a ■ b. Adding paragraph (k). latching mechanism or lock down §§ 250.424 through 250.426 [Removed and Reserved] The revisions and addition read as mechanism, you must ensure that the follows: latching mechanisms or lock down ■ 21. Remove and reserve §§ 250.424 mechanisms are engaged upon through 250.426. § 250.428 What must I do in certain successfully installing and cementing ■ 22. In § 250.427, revise paragraph (b) cementing and casing situations? the liner. If there is an indication of an to read as follows: * * * * *

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

*******

(b) Need to change casing setting depths or hole interval drilling depth Submit those changes to the District Manager for approval and include (for a BHA with an under-reamer, this means bit depth) more than a certification by a professional engineer (PE) that he or she re- 100 feet true vertical depth (TVD) from the approved APD due to viewed and approved the proposed changes. conditions encountered during drilling operations, (c) Have indication of inadequate cement job (such as lost returns, no (1) Locate the top of cement by: cement returns to mudline or expected height, cement channeling, or (i) Running a temperature survey; failure of equipment), (ii) Running a cement evaluation log; or (iii) Using a combination of these techniques. (2) Determine if your cement job is inadequate. If your cement job is determined to be inadequate, refer to paragraph (d) of this section. (3) If your cement job is determined to be adequate, report the results to the District Manager in your submitted WAR. (d) Inadequate cement job, Take remedial actions. The District Manager must review and approve all remedial actions before you may take them, unless immediate ac- tions must be taken to ensure the safety of the crew or to prevent a well-control event. If you complete any immediate action to ensure the safety of the crew or to prevent a well-control event, submit a description of the action to the District Manager when that action is complete. Any changes to the well program will require submittal of a certification by a professional engineer (PE) certifying that he or she reviewed and approved the proposed changes, and must meet any other requirements of the District Manager.

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

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(k) Plan to use a valve(s) on the drive pipe during cementing oper- Include a description of the plan in your APD. Your description must in- ations for the conductor casing, surface casing, or liner, clude a schematic of the valve and height above the water line. The valve must be remotely operated and full opening with visual obser- vation while taking returns. The person in charge of observing re- turns must be in communication with the drill floor. You must record in your daily report and in the WAR if cement returns were observed. If cement returns are not observed, you must contact the District Manager and obtain approval of proposed plans to locate the top of cement before continuing with operations.

§§ 250.440 through 250.451 [Removed and If your evaluation indicates that the well (7) Support vessels; and Reserved] can only be partially shut-in, then you (8) Storage facilities. ■ 24. Remove the undesignated center must determine your ability to flow and (c) You must submit a description of heading ‘‘Blowout Preventer (BOP) capture the residual fluids to a surface your source control and containment System Requirements’’ and remove and production and storage system. capabilities to the Regional Supervisor reserve §§ 250.440 through 250.451. (b) You must have access to and the and receive approval before BSEE will ability to deploy Source Control and § 250.456 [Amended] approve your APD, Form BSEE–0123. Containment Equipment (SCCE) and all The description of your containment ■ 25. Amend § 250.456: other necessary supporting and capabilities must contain the following: ■ a. In paragraph (i), by adding the word collocated equipment to regain control (1) Your source control and ‘‘and’’ after the semicolon; of the well. SCCE means the capping containment capabilities for controlling ■ b. By removing paragraph (j); and stack, cap-and-flow system, ■ c. By redesignating paragraph (k) as and containing a blowout event at the containment dome, and/or other subsea seafloor; paragraph (j). and surface devices, equipment, and (2) A discussion of the determination ■ 26. Revise § 250.462 to read as vessels, which have the collective required in paragraph (a) of this section; follows: purpose to control a spill source and and § 250.462 What are the source control, stop the flow of fluids into the environment or to contain fluids (3) Information showing that you have containment, and collocated equipment access to and the ability to deploy all requirements? escaping into the environment. This SCCE, supporting equipment, and equipment required by paragraph (b) of For drilling operations using a subsea this section. BOP or surface BOP on a floating collocated equipment must include, but is not limited to, the following: (d) You must contact the District facility, you must have the ability to Manager and Regional Supervisor for control or contain a blowout event at the (1) Subsea containment and capture equipment, including containment reevaluation of your source control and sea floor. containment capabilities if your: (a) To determine your required source domes and capping stacks; control and containment capabilities (2) Subsea utility equipment (1) Well design changes; or you must do the following: including hydraulic power sources and (2) Approved source control and (1) Consider a scenario of the wellbore hydrate control equipment; containment equipment is out of fully evacuated to reservoir fluids, with (3) Collocated equipment including service. no restrictions in the well. dispersant injection equipment; (e) You must maintain, test, and (2) Evaluate the performance of the (4) Riser systems; inspect the source control, containment, well as designed to determine if a full (5) Remotely operated vehicles and collocated equipment identified in shut-in can be achieved without having (ROVs); the following table according to these reservoir fluids broach to the sea floor. (6) Capture vessels; requirements:

Equipment Requirements, you must: Additional information

(1) Capping stacks, ...... (i) Function test all pressure containing critical compo- Pressure containing critical components are those com- nents on a quarterly frequency (not to exceed 104 ponents that will experience wellbore pressure during days between tests), a shut-in after being functioned. (ii) Pressure test pressure containing critical compo- Pressure containing critical components are those com- nents on a bi-annual basis, but not later than 210 ponents that will experience wellbore pressure during days from the last pressure test. All pressure testing a shut-in. These components include, but are not lim- must be witnessed by BSEE (if available) and a ited to: All blind rams, wellhead connectors, and out- BSEE-approved verification organization. let valves. (iii) Notify BSEE at least 21 days prior to commencing any pressure testing. (2) Production safety sys- (i) Meet or exceed the requirements set forth in tems used for flow and §§ 250.800 through 250.808, excluding required capture operations, equipment that would be installed below the wellhead or that is not applicable to the cap and flow system. (ii) Have all equipment unique to containment oper- ations available for inspection at all times. (3) Subsea utility equipment, Have all referenced containment equipment available Subsea utility equipment includes, but is not limited to: for inspection at all times. Hydraulic power sources, debris removal, and hy- drate control equipment.

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Equipment Requirements, you must: Additional information

(4) Collocated equipment, .... Have equipment available for inspection at all times ..... Collocated equipment includes, but is not limited to, dispersant injection equipment and other subsea con- trol equipment.

■ 27. In § 250.465, revise paragraph ■ a. Removing paragraph (b); § 250.613 Approval and reporting for well- (b)(3) to read as follows: ■ b. Redesignating paragraphs (c) workover operations. through (e) as paragraphs (b) through * * * * * § 250.465 When must I submit an (d); and (b) * * * Application for Permit to Modify (APM) or ■ an End of Operations Report to BSEE? c. Adding new paragraph (e) and (3) All information required in paragraph (f). § 250.731. * * * * * The additions read as follows: (b) * * * * * * * * (3) Within 30 days after completing § 250.518 Tubing and wellhead equipment. § 250.614 [Amended] this work, you must submit an End of * * * * * ■ Operations Report (EOR), Form BSEE– 39. In § 250.614, remove paragraph (e) When installed, packers and bridge (d). 0125, as required under § 250.744. plugs must meet the following: §§ 250.466 through 250.469 [Removed and (1) All permanently installed packers § 250.615 [Removed and Reserved] Reserved] and bridge plugs must comply with API ■ 40. Remove and reserve § 250.615. Spec. 11D1 (as incorporated by ■ ■ 41. Amend § 250.616 by: 28. Remove and reserve §§ 250.466 reference in § 250.198); through 250.469. ■ a. Revising the section heading; (2) The production packer must be set ■ b. Removing paragraphs (a) through Subpart E—Oil and Gas Well- at a depth that will allow for a column (e); and Completion Operations of weighted fluids to be placed above ■ c. Redesignating paragraphs (f) the packer that will exert a hydrostatic through (h) as paragraphs (a) through ■ 29. Revise § 250.500 to read as force greater than or equal to the force (c). follows: created by the reservoir pressure below The revision reads as follows: the packer; § 250.500 General requirements. (3) The production packer must be set § 250.616 Coiled tubing and snubbing Well-completion operations must be as close as practically possible to the operations. conducted in a manner to protect perforated interval; and * * * * * against harm or damage to life (4) The production packer must be set (including fish and other aquatic life), §§ 250.617 and 250.618 [Removed and at a depth that is within the cemented Reserved] property, natural resources of the OCS, interval of the selected casing section. including any mineral deposits (in areas (f) Your APM must include a ■ 42. Remove and reserve §§ 250.617 leased and not leased), the National description and calculations for how and 250.618. security or defense, or the marine, you determined the production packer ■ 43. Amend § 250.619 by: coastal, or human environment. In setting depth. ■ a. Removing paragraph (b); addition to the requirements of this ■ b. Redesignating paragraphs (c) subpart, you must also follow the Subpart F—Oil and Gas Well-Workover through (e) as paragraphs (b) through applicable requirements of subpart G of Operations (d); and this part. ■ c. Adding new paragraph (e) and ■ 35. Revise § 250.600 to read as paragraph (f). §§ 250.502 and 250.506 [Removed and follows: The additions read as follows: Reserved] § 250.600 General requirements. § 250.619 Tubing and wellhead equipment. ■ 30. Remove and reserve §§ 250.502 and 250.506. Well-workover operations must be * * * * * ■ 31. In § 250.513, revise paragraph conducted in a manner to protect (e) If you pull and reinstall packers (b)(4) to read as follows: against harm or damage to life and bridge plugs, you must meet the (including fish and other aquatic life), following requirements: § 250.513 Approval and reporting of well- property, natural resources of the Outer (1) All permanently installed packers completion operations. Continental Shelf (OCS) including any and bridge plugs must comply with API * * * * * mineral deposits (in areas leased and Spec. 11D1 (as incorporated by (b) * * * not leased), the National security or reference in § 250.198); (4) All applicable information defense, or the marine, coastal, or (2) The production packer must be set required in § 250.731. human environment. In addition to the at a depth that will allow for a column * * * * * requirements of this subpart, you must of weighted fluids to be placed above also follow the applicable requirements the packer that will exert a hydrostatic § 250.514 [Amended] of subpart G of this part. force greater than or equal to the force ■ created by the reservoir pressure below 32. In § 250.514, remove paragraph § 250.602 [Removed and Reserved] (d). the packer; ■ 36. Remove and reserve § 250.602. (3) The production packer must be set §§ 250.515 through 250.517 [Removed and as close as practically possible to the Reserved] § 250.606 [Removed and Reserved] perforated interval; and ■ 33. Remove and reserve §§ 250.515 ■ 37. Remove and reserve § 250.606. (4) The production packer must be set through 250.517. ■ 38. In § 250.613, revise paragraph at a depth that is within the cemented ■ 34. Amend § 250.518 by: (b)(3) to read as follows: interval of the selected casing section.

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(f) Your APM must include a Records and Reporting (b) Have a person onsite during description and calculations for how 250.740 What records must I keep? operations who represents your interests you determined the production packer 250.741 How long must I keep records? and can fulfill your responsibilities; setting depth. 250.742 What well records am I required to (c) Ensure that the toolpusher, ■ 44. Add subpart G to read as follows: submit? operator’s representative, or a member 250.743 What are the well activity reporting of the rig crew maintains continuous Subpart G—Well Operations and Equipment requirements? surveillance on the rig floor from the 250.744 What are the end of operation General Requirements reporting requirements? beginning of operations until the well is Sec. 250.745 What other well records could I be completed or abandoned, unless you 250.700 What operations and equipment required to submit? have secured the well with blowout does this subpart cover? 250.746 What are the recordkeeping preventers (BOPs), bridge plugs, cement 250.701 May I use alternate procedures or requirements for casing, liner, and BOP plugs, or packers; equipment during operations? tests, and inspections of BOP systems (d) Use personnel trained according to 250.702 May I obtain departures from these and marine risers? the provisions of subparts O and S of requirements? 250.703 What must I do to keep wells under Subpart G—Well Operations and this part; (e) Use and maintain equipment and control? Equipment materials necessary to ensure the safety Rig Requirements General Requirements and protection of personnel, equipment, 250.710 What instructions must be given to natural resources, and the environment; personnel engaged in well operations? § 250.700 What operations and equipment and 250.711 What are the requirements for well- does this subpart cover? (f) Use equipment that has been control drills? This subpart covers operations and designed, tested, and rated for the 250.712 What rig unit movements must I equipment associated with drilling, maximum environmental and report? completion, workover, and 250.713 What must I provide if I plan to use operational conditions to which it may a mobile offshore drilling unit (MODU) decommissioning activities. This be exposed while in service. for well operations? subpart includes regulations applicable 250.714 Do I have to develop a dropped to drilling, completion, workover, and Rig Requirements objects plan? decommissioning activities in addition § 250.710 What instructions must be given 250.715 Do I need a global positioning to applicable regulations contained in to personnel engaged in well operations? system (GPS) for all MODUs? subparts D, E, F, and Q of this part Prior to engaging in well operations, Well Operations unless explicitly stated otherwise. personnel must be instructed in: 250.720 When and how must I secure a § 250.701 May I use alternate procedures (a) Hazards and safety requirements. well? or equipment during operations? You must instruct your personnel 250.721 What are the requirements for You may use alternate procedures or regarding the safety requirements for the pressure testing casing and liners? operations to be performed, possible 250.722 What are the requirements for equipment during operations after receiving approval as described in hazards to be encountered, and general prolonged operations in a well? safety considerations to protect 250.723 What additional safety measures § 250.141. You must identify and must I take when I conduct operations discuss your proposed alternate personnel, equipment, and the on a platform that has producing wells procedures or equipment in your environment as required by subpart S of or has other hydrocarbon flow? Application for Permit to Drill (APD) this part. The date and time of safety 250.724 What are the real-time monitoring (Form BSEE–0123) (see § 250.414(h)) or meetings must be recorded and requirements? your Application for Permit to Modify available at the facility for review by Blowout Preventer (BOP) System (APM) (Form BSEE–0124). Procedures BSEE representatives. (b) Well control. You must prepare a Requirements for obtaining approval of alternate well-control plan for each well. Each 250.730 What are the general requirements procedures or equipment are described well-control plan must contain for BOP systems and system in § 250.141. components? instructions for personnel about the use 250.731 What information must I submit for § 250.702 May I obtain departures from of each well-control component of your BOP systems and system components? these requirements? BOP, procedures that describe how 250.732 What are the BSEE-approved You may apply for a departure from personnel will seal the wellbore and verification organization (BAVO) these requirements as described in shear pipe before maximum anticipated requirements for BOP systems and § 250.142. Your request must include a surface pressure (MASP) conditions are system components? exceeded, assignments for each crew 250.733 What are the requirements for a justification showing why the departure surface BOP stack? is necessary. You must identify and member, and a schedule for completion 250.734 What are the requirements for a discuss the departure you are requesting of each assignment. You must keep a subsea BOP system? in your APD (see § 250.414(h)) or your copy of your well-control plan on the rig 250.735 What associated systems and APM. at all times, and make it available to related equipment must all BOP systems BSEE upon request. You must post a include? § 250.703 What must I do to keep wells copy of the well-control plan on the rig 250.736 What are the requirements for under control? floor. choke manifolds, kelly-type valves You must take the necessary inside BOPs, and drill string safety precautions to keep wells under control § 250.711 What are the requirements for valves? at all times, including: well-control drills? 250.737 What are the BOP system testing (a) Use recognized engineering You must conduct a weekly well- requirements? practices to reduce risks to the lowest control drill with all personnel engaged 250.738 What must I do in certain situations involving BOP equipment or level practicable when monitoring and in well operations. Your drill must systems? evaluating well conditions and to familiarize personnel engaged in well 250.739 What are the BOP maintenance and minimize the potential for the well to operations with their roles and inspection requirements? flow or kick; functions so that they can perform their

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duties promptly and efficiently as (d) Prior to resuming operations after you must obtain a third-party review of outlined in the well-control plan stacking, you must notify the your MODU similar to the process required by § 250.710. appropriate District Manager of any outlined in §§ 250.915 through 250.918. (a) Timing of drills. You must conduct construction, repairs, or modifications You may submit this information before each drill during a period of activity associated with the drilling package submitting an APD or APM. that minimizes the risk to operations. made to the MODU or platform rig. (2) If you plan to conduct operations The timing of your drills must cover a (e) If a drilling rig is entering OCS in a frontier area, you must have a range of different operations, including waters, you must inform the District contingency plan that addresses design drilling with a diverter, on-bottom Manager where the drilling rig is and operating limitations of the MODU. drilling, and tripping. The same drill coming from. Your plan must identify the actions may not be repeated consecutively with (f) If you change your anticipated date necessary to maintain safety and the same crew. for initially moving on or off location by prevent damage to the environment. (b) Recordkeeping requirements. For more than 24 hours, you must submit an Actions must include the suspension, each drill, you must record the updated Form BSEE–0144, Rig curtailment, or modification of following in the daily report: Movement Notification Report. operations to remedy various (1) Date, time, and type of drill operational or environmental situations conducted; § 250.713 What must I provide if I plan to use a mobile offshore drilling unit (MODU) (e.g., vessel motion, riser offset, anchor (2) The amount of time it took to be for well operations? tensions, wind speed, wave height, ready to close the diverter or use each If you plan to use a MODU for well currents, icing or ice-loading, settling, well-control component of BOP system; operations, you must provide: tilt or lateral movement, resupply and (a) Fitness requirements. Information capability). (3) The total time to complete the and data to demonstrate the MODU’s (d) Additional documentation. You entire drill. capability to perform at the proposed must provide the current Certificate of (c) A BSEE ordered drill. A BSEE location. This information must include Inspection (for U.S.-flag vessels) or representative may require you to the maximum environmental and Certificate of Compliance (for foreign- conduct a well-control drill during a operational conditions that the MODU flag vessels) from the USCG and BSEE inspection. The BSEE is designed to withstand, including the Certificate of Classification. You must representative will consult with your minimum air gap necessary for both also provide current documentation of onsite representative before requiring hurricane and non-hurricane seasons. If any operational limitations imposed by the drill. sufficient environmental information an appropriate classification society. § 250.712 What rig unit movements must I and data are not available at the time (e) Dynamically positioned MODU. If report? you submit your APD or APM, the you use a dynamically positioned (a) You must report the movement of District Manager may approve your APD MODU, you must include in your APD all rig units on and off locations to the or APM, but require you to collect and or APM your contingency plan for District Manager using Form BSEE– report this information during moving off location in an emergency 0144, Rig Movement Notification operations. Under this circumstance, the situation. At a minimum, your plan Report. Rig units include MODUs, District Manager may revoke the must address emergency events caused platform rigs, snubbing units, wire-line approval of the APD or APM if by storms, currents, station-keeping units used for non-routine operations, information collected during operations failures, power failures, and losses of and coiled tubing units. You must shows that the MODU is not capable of well control. The District Manager may inform the District Manager 24 hours performing at the proposed location. require your plan to include additional before: (b) Foundation requirements. events that may require movement of (1) The arrival of a rig unit on Information to show that site-specific the MODU and other information location; soil and oceanographic conditions are needed to clarify or further address how (2) The movement of a rig unit to capable of supporting the proposed the MODU will respond to emergencies another slot. For movements that will bottom-founded MODU. If you provided or other events. occur less than 24 hours after initially sufficient site-specific information in (f) Inspection of MODU. The MODU moving onto location (e.g., coiled tubing your EP, DPP, or DOCD submitted to must be available for inspection by the and batch operations), you may include BOEM, you may reference that District Manager before commencing your anticipated movement schedule on information. The District Manager may operations and at any time during Form BSEE–0144; or require you to conduct additional operations. (3) The departure of a rig unit from surveys and soil borings before (g) Current monitoring. For water the location. approving the APD or APM if additional depths greater than 400 meters (1,312 (b) You must provide the District information is needed to make a feet), you must include in your APD or Manager with the rig name, lease determination that the conditions are APM: number, well number, and expected capable of supporting the MODU, or (1) A description of the specific time of arrival or departure. equipment installed on a subsea current speeds that will cause you to (c) If a MODU or platform rig is to be wellhead. For a moored rig, you must implement rig shutdown, move-off warm or cold stacked, you must inform submit a plat of the rig’s anchor pattern procedures, or both; and the District Manager: approved in your EP, DPP, or DOCD in (2) A discussion of the specific (1) Where the MODU or platform rig your APD or APM. measures you will take to curtail rig is coming from; (c) For frontier areas. (1) If the design operations and move off location when (2) The location where the MODU or of the MODU you plan to use in a such currents are encountered. You may platform rig will be positioned; frontier area is unique or has not been use criteria, such as current velocities, (3) Whether the MODU or platform rig proven for use in the proposed riser angles, watch circles, and will be manned or unmanned; and environment, the District Manager may remaining rig power to describe when (4) If the location for stacking the require you to submit a third-party these procedures or measures will be MODU or platform rig changes. review of the MODU design. If required, implemented.

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§ 250.714 Do I have to develop a dropped minimize the risk of the system being District Manager include, but are not objects plan? disabled. limited to, the following: If you use a floating rig unit in an area (c) You must place the GPS (i) Evacuation of the rig crew; with subsea infrastructure, you must transponders in different locations for (ii) Inability to keep the rig on develop a dropped objects plan and redundancy to minimize risk of system location; make it available to BSEE upon request. failure. (iii) Repair to major rig or well-control This plan must be updated as the (d) Each GPS transponder must be equipment; or infrastructure on the seafloor changes. capable of transmitting data for at least (iv) Observed flow outside the well’s Your plan must include: 7 days after a storm has passed. casing (e.g., shallow water flow or (a) A description and plot of the path (e) If the MODU is moved off location bubbling). the rig will take while running and in the event of a storm, you must (2) The District Manager may approve pulling the riser; immediately begin to record the GPS alternate procedures or barriers, in (b) A plat showing the location of any location data. accordance with § 250.141, if you do not subsea wells, production equipment, have time to install the required barriers pipelines, and any other identified (f) You must contact the Regional Office and allow real-time access to the or if special circumstances occur. debris; (b) Before you displace kill-weight (c) Modeling of a dropped object’s MODU location data. When you contact fluid from the wellbore and/or riser, path with consideration given to the Regional Office, provide the thereby creating an underbalanced state, metocean conditions for various following: you must obtain approval from the material forms, such as a tubular (e.g., (1) Name of the lessee and operator District Manager. To obtain approval, riser or casing) and box (e.g., BOP or with contact information; you must submit with your APD or tree); (2) MODU name; (d) Communications, procedures, and (3) Initial date and time; and APM your reasons for displacing the delegated authorities established with (4) How you will provide GPS real- kill-weight fluid and provide detailed the production host facility to shut-in time access. step-by-step written procedures any active subsea wells, equipment, or describing how you will safely displace Well Operations pipelines in the event of a dropped these fluids. The step-by-step displacement procedures must address object; and § 250.720 When and how must I secure a (e) Any additional information well? the following: required by the District Manager as (1) Number and type of independent (a) Whenever you interrupt barriers, as described in § 250.420(b)(3), appropriate to clarify, update, or operations, you must notify the District evaluate your dropped objects plan. that are in place for each flow path that Manager. Before moving off the well, requires such barriers; § 250.715 Do I need a global positioning you must have two independent barriers (2) Tests you will conduct to ensure system (GPS) for all MODUs? installed, at least one of which must be integrity of independent barriers; All MODUs must have a minimum of a mechanical barrier, as approved by the (3) BOP procedures you will use two functioning GPS transponders at all District Manager. You must install the while displacing kill-weight fluids; and times, and you must provide to BSEE barriers at appropriate depths within a (4) Procedures you will use to monitor real-time access to the GPS data prior to properly cemented casing string or liner. the volumes and rates of fluids entering and during each hurricane season. Before removing a subsea BOP stack or and leaving the wellbore. (a) The GPS must be capable of surface BOP stack on a mudline monitoring the position and tracking the suspension well, you must conduct a § 250.721 What are the requirements for path in real-time if the MODU moves negative pressure test in accordance pressure testing casing and liners? from its location during a severe storm. with § 250.721. (a) You must test each casing string (b) You must install and protect the (1) The events that would cause you that extends to the wellhead according tracking system’s equipment to to interrupt operations and notify the to the following table:

Casing type Minimum test pressure

(1) Drive or Structural, ...... Not required. (2) Conductor, excluding subsea wellheads, ...... 250 psi. (3) Surface, Intermediate, and Production, ...... 70 percent of its minimum internal yield.

(b) You must test each drilling liner (e) If you plan to produce a well, you test. If the pressure declines more than and liner-top to a pressure at least equal must: 10 percent in a 30-minute test, or if to the anticipated leak-off pressure of (1) For a well that is fully cased and there is another indication of a leak, you the formation below that liner shoe, or cemented, pressure test the entire well must submit to the District Manager for subsequent liner shoes if set. You must to maximum anticipated shut-in tubing approval your proposed plans to re- conduct this test before you continue pressure, not to exceed 70% of the burst cement, repair the casing or liner, or run operations in the well. rating limit of the weakest component additional casing/liner to provide a (c) You must test each production before perforating the casing or liner; or proper seal. Your submittal must liner and liner-top to a minimum of 500 (2) For an open-hole completion, include a PE certification of your psi above the formation fracture pressure test the entire well to proposed plans. pressure at the casing shoe into which maximum anticipated shut-in tubing (g) You must perform a negative the liner is lapped. pressure, not to exceed 70% of the burst pressure test on all wells that use a (d) The District Manager may approve rating limit of the weakest component subsea BOP stack or wells with mudline or require other casing test pressures as before you drill the open-hole section. suspension systems. appropriate under the circumstances to (f) You may not resume operations (1) You must perform a negative ensure casing integrity. until you obtain a satisfactory pressure pressure test on your final casing string

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or liner. This test must be conducted of evaluation of the effects on the well (1) A closed surface-controlled after setting your second barrier just casing of prolonged operations; and subsurface safety valve of the pump- above the shoe track, but prior to (2) Report the results of your through-type may be used in lieu of the conducting any completion operations. evaluation to the District Manager and pump-through-type tubing plug (2) You must perform a negative obtain approval of those results before provided that the surface control has pressure test prior to unlatching the resuming operations. Your report must been locked out of operation. BOP at any point in the well. The include calculations that show the (2) The well to which a rig unit or negative pressure test must be well’s integrity is above the minimum related equipment is to be moved must performed on those components, at a safety factors, if an imaging tool or be equipped with a back-pressure valve minimum, that will be exposed to the caliper is used. prior to removing the tree and installing negative differential pressure that will (b) If well integrity has deteriorated to and testing the BOP system. occur when the BOP is disconnected. a level below minimum safety factors, (3) The well from which a rig unit or (3) The District Manager may require you must: related equipment is to be moved must (1) Obtain approval from the District you to perform additional negative be equipped with a back pressure valve Manager to begin repairs or install pressure tests on other casing strings or prior to removing the BOP system and additional casing. To obtain approval, liners (e.g., intermediate casing string or installing the production tree. liner) or on wells with a surface BOP you must also provide a PE certification showing that he or she reviewed and (e) Coiled tubing units, snubbing stack as appropriate to demonstrate units, or wireline units may be moved casing or liner integrity. approved the proposed changes; (2) Repair the casing or run another onto and off of a platform without (4) You must submit for approval with shutting in wells. your APD or APM, test procedures and casing string; and criteria for a successful negative (3) Perform a pressure test after the § 250.724 What are the real-time pressure test. If any of your test repairs are made or additional casing is monitoring requirements? installed and report the results to the procedures or criteria for a successful (a) No later than April 29, 2019, when District Manager as specified in test change, you must submit for conducting well operations with a § 250.721. approval the changes in a revised APD subsea BOP or with a surface BOP on a or APM. § 250.723 What additional safety measures floating facility, or when operating in an (5) You must document all your test must I take when I conduct operations on high pressure high temperature (HPHT) results and make them available to a platform that has producing wells or has environment, you must gather and BSEE upon request. other hydrocarbon flow? monitor real-time well data using an (6) If you have any indication of a You must take the following safety independent, automatic, and continuous failed negative pressure test, such as, measures when you conduct operations monitoring system capable of recording, but not limited to, pressure buildup or with a rig unit or lift boat on or jacked- storing, and transmitting data regarding observed flow, you must immediately up over a platform with producing wells the following: investigate the cause. If your or that has other hydrocarbon flow: (1) The BOP control system; investigation confirms that a failure (a) The movement of rig units and (2) The well’s fluid handling system occurred during the negative pressure related equipment on and off a platform on the rig; and test, you must: or from well to well on the same (3) The well’s downhole conditions (i) Correct the problem and platform, including rigging up and with the bottom hole assembly tools (if immediately notify the appropriate rigging down, must be conducted in a any tools are installed). safe manner; District Manager; and (b) You must transmit these data as (ii) Submit a description of the (b) You must install an emergency they are gathered, barring unforeseeable corrective action taken and receive shutdown station for the production or unpreventable interruptions in approval from the appropriate District system near the rig operator’s console; transmission, and have the capability to Manager for the retest. (c) You must shut-in all producible monitor the data onshore, using (7) You must have two barriers in wells located in the affected wellbay qualified personnel in accordance with place, as described in § 250.420(b)(3), at below the surface and at the wellhead a real-time monitoring plan, as provided any time and for any well, prior to when: in paragraph (c) of this section. Onshore performing the negative pressure test. (1) You move a rig unit or related personnel who monitor real-time data (8) You must include documentation equipment on and off a platform. This must have the capability to contact rig of the successful negative pressure test includes rigging up and rigging down personnel during operations. After in the End-of-Operations Report (Form activities within 500 feet of the affected operations, you must preserve and store BSEE–0125). platform; (2) You move or skid a rig unit these data onshore for recordkeeping § 250.722 What are the requirements for between wells on a platform; or purposes as required in §§ 250.740 and prolonged operations in a well? (3) A MODU or lift boat moves within 250.741. You must provide BSEE with If wellbore operations continue 500 feet of a platform. You may resume access to your designated real-time within a casing or liner for more than production once the MODU or lift boat monitoring data onshore upon request. 30 days from the previous pressure test is in place, secured, and ready to begin You must include in your APD a of the well’s casing or liner, you must: operations. certification that you have a real-time (a) Stop operations as soon as (d) All wells in the same well-bay monitoring plan that meets the criteria practicable, and evaluate the effects of which are capable of producing in paragraph (c) of this section. the prolonged operations on continued hydrocarbons must be shut-in below the (c) You must develop and implement operations and the life of the well. At a surface with a pump-through-type a real-time monitoring plan. Your real- minimum, you must: tubing plug and at the surface with a time monitoring plan, and all real-time (1) Evaluate the well casing with a closed master valve prior to moving rig monitoring data, must be made available pressure test, caliper tool, or imaging units and related equipment, unless to BSEE upon request. Your real-time tool. On a case-by-case basis, the District otherwise approved by the District monitoring plan must include the Manager may require a specific method Manager. following:

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(1) A description of your real-time conflict between API Standard 53, and ensure that the Chief, Office of Offshore monitoring capabilities, including the the requirements of this subpart, you Regulatory Programs and the types of the data collected; must follow the requirements of this manufacturer receive a copy of the (2) A description of how your real- subpart. analysis report. time monitoring data will be transmitted (2) Those provisions of the following (3) If the equipment manufacturer onshore during operations, how the data industry standards (all incorporated by notifies you that it has changed the will be labeled and monitored by reference in § 250.198) that apply to design of the equipment that failed or if qualified onshore personnel, and how it BOP systems: you have changed operating or repair will be stored onshore; (i) ANSI/API Spec. 6A; procedures as a result of a failure, then (3) A description of your procedures (ii) ANSI/API Spec. 16A; you must, within 30 days of such for providing BSEE access, upon (iii) ANSI/API Spec. 16C; changes, report the design change or request, to your real-time monitoring (iv) API Spec. 16D; and modified procedures in writing to the data including, if applicable, the (v) ANSI/API Spec. 17D. Chief, Office of Offshore Regulatory location of any onshore data monitoring (3) For surface and subsea BOPs, the Programs. pipe and variable bore rams installed in or data storage facilities; (4) You must send the reports (4) The qualifications of the onshore the BOP stack must be capable of required in this paragraph to: Chief, personnel monitoring the data; effectively closing and sealing on the Office of Offshore Regulatory Programs; (5) Your procedures for, and methods tubular body of any drill pipe, Bureau of Safety and Environmental of, communication between rig workstring, and tubing (excluding Enforcement; 45600 Woodland Road, personnel and the onshore monitoring tubing with exterior control lines and Sterling, VA 20166. personnel; and flat packs) in the hole under MASP, as (6) Actions to be taken if you lose any defined for the operation, with the (d) If you plan to use a BOP stack real-time monitoring capabilities or proposed regulator settings of the BOP manufactured after the effective date of communications between rig and control system. this regulation, you must use one onshore personnel, and a protocol for (4) The current set of approved manufactured pursuant to an API Spec. how you will respond to any significant schematic drawings must be available Q1 (as incorporated by reference in and/or prolonged interruption of on the rig and at an onshore location. If § 250.198) quality management system. monitoring or onshore-offshore you make any modifications to the BOP Such quality management system must communications, including your or control system that will change your be certified by an entity that meets the protocol for notifying BSEE of any BSEE-approved schematic drawings, requirements of ISO 17011. significant and/or prolonged you must suspend operations until you (1) BSEE may consider accepting interruptions. obtain approval from the District equipment manufactured under quality assurance programs other than API Blowout Preventer (BOP) System Manager. Spec. Q1, provided you submit a request Requirements (b) You must ensure that the design, fabrication, maintenance, and repair of to the Chief, Office of Offshore § 250.730 What are the general your BOP system is in accordance with Regulatory Programs for approval, requirements for BOP systems and system the requirements contained in this part, containing relevant information about components? Original Equipment Manufacturers the alternative program. (a) You must ensure that the BOP (OEM) recommendations unless (2) You must submit this request to system and system components are otherwise directed by BSEE, and the Chief, Office of Offshore Regulatory designed, installed, maintained, recognized engineering practices. The Programs; Bureau of Safety and inspected, tested, and used properly to training and qualification of repair and Environmental Enforcement; 45600 ensure well control. The working- maintenance personnel must meet or Woodland Road, Sterling, Virginia pressure rating of each BOP component exceed any OEM training 20166. (excluding annular(s)) must exceed recommendations unless otherwise MASP as defined for the operation. For directed by BSEE. § 250.731 What information must I submit a subsea BOP, the MASP must be taken (c) You must follow the failure for BOP systems and system components? at the mudline. The BOP system reporting procedures contained in API For any operation that requires the includes the BOP stack, control system, Standard 53, ANSI/API Spec. 6A, and use of a BOP, you must include the and any other associated system(s) and ANSI/API Spec 16A (all incorporated by information listed in this section with equipment. The BOP system and reference in § 250.198), and: your applicable APD, APM, or other individual components must be able to (1) You must provide a written notice submittal. You are required to submit perform their expected functions and be of equipment failure to the Chief, Office this information only once for each compatible with each other. Your BOP of Offshore Regulatory Programs, and well, unless the information changes system (excluding casing shear) must be the manufacturer of such equipment from what you provided in an earlier capable of closing and sealing the within 30 days after the discovery and approved submission or you have wellbore at all times, including under identification of the failure. A failure is moved off location from the well. After anticipated flowing conditions for the any condition that prevents the you have submitted this information for specific well conditions, without losing equipment from meeting the functional a particular well, subsequent APMs or ram closure time and sealing integrity specification. other submittals for the well should due to the corrosiveness, volume, and (2) You must ensure that an reference the approved submittal abrasiveness of any fluids in the investigation and a failure analysis are containing the information required by wellbore that the BOP system may performed within 120 days of the failure this section and confirm that the encounter. Your BOP system must meet to determine the cause of the failure. information remains accurate and that the following requirements: You must also ensure that the results you have not moved off location from (1) The BOP requirements of API and any corrective action are that well. If the information changes or Standard 53 (incorporated by reference documented. If the investigation and you have moved off location from the in § 250.198) and the requirements of analysis are performed by an entity well, you must submit updated §§ 250.733 through 250.739. If there is a other than the manufacturer, you must information in your next submission.

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You must submit: Including:

(a) A complete description of the BOP system and sys- (1) Pressure ratings of BOP equipment; tem components, (2) Proposed BOP test pressures (for subsea BOPs, include both surface and cor- responding subsea pressures); (3) Rated capacities for liquid and gas for the fluid-gas separator system; (4) Control fluid volumes needed to close, seal, and open each component; (5) Control system pressure and regulator settings needed to achieve an effective seal of each ram BOP under MASP as defined for the operation; (6) Number and volume of accumulator bottles and bottle banks (for subsea BOP, in- clude both surface and subsea bottles); (7) Accumulator pre-charge calculations (for subsea BOP, include both surface and subsea calculations); (8) All locking devices; and (9) Control fluid volume calculations for the accumulator system (for a subsea BOP system, include both the surface and subsea volumes). (b) Schematic drawings, ...... (1) The inside diameter of the BOP stack; (2) Number and type of preventers (including blade type for shear ram(s)); (3) All locking devices; (4) Size range for variable bore ram(s); (5) Size of fixed ram(s); (6) All control systems with all alarms and set points labeled, including pods; (7) Location and size of choke and kill lines (and gas bleed line(s) for subsea BOP); (8) Associated valves of the BOP system; (9) Control station locations; and (10) A cross-section of the riser for a subsea BOP system showing number, size, and labeling of all control, supply, choke, and kill lines down to the BOP. (c) Certification by a BSEE-approved verification organi- Verification that: zation (BAVO), (1) Test data demonstrate the shear ram(s) will shear the drill pipe at the water depth as required in § 250.732; (2) The BOP was designed, tested, and maintained to perform under the maximum environmental and operational conditions anticipated to occur at the well; and (3) The accumulator system has sufficient fluid to operate the BOP system without assistance from the charging system. (d) Additional certification by a BAVO, if you use a Verification that: subsea BOP, a BOP in an HPHT environment as de- (1) The BOP stack is designed and suitable for the specific equipment on the rig and fined in § 250.807, or a surface BOP on a floating facil- for the specific well design; ity, (2) The BOP stack has not been compromised or damaged from previous service; and (3) The BOP stack will operate in the conditions in which it will be used. (e) If you are using a subsea BOP, descriptions of A listing of the functions with their sequences and timing. autoshear, deadman, and emergency disconnect se- quence (EDS) systems, (f) Certification stating that the MIA Report required in § 250.732(d) has been submitted within the past 12 months for a subsea BOP, a BOP being used in an HPHT environment as defined in § 250.807, or a sur- face BOP on a floating facility.

§ 250.732 What are the BSEE-approved paragraph (a)(2) of this section to installation, repair, or major verification organization (BAVO) prepare certifications, verifications, and modification of BOPs and related requirements for BOP systems and system reports as required by §§ 250.731(c) and systems and equipment; components? (d), 250.732 (b) and (c), 250.734(b)(1), (ii) Technical capabilities; (a) BSEE will maintain a list of BSEE- 250.738(b)(4), and 250.739(b). (iii) Size and type of organization; approved verification organizations (2) The independent third-party must (BAVOs) on its public website that you (iv) In-house availability of, or access be a technical classification society, or to, appropriate technology. This should must use to satisfy any provision in this a licensed professional engineering firm, subpart that requires a BAVO include computer programs, hardware, or a registered professional engineer and testing materials and equipment; certification, verification, report, or capable of providing the certifications, (v) Ability to perform the verification review. You must comply with all verifications, and reports required under functions for projects considering requirements in this subpart for BAVO paragraph (a)(1) of this section. certification, verification, or reporting (3) For an organization to become a current commitments; no later than 1 year from the date BSEE BAVO, it must submit the following (vi) Previous experience with BSEE publishes a list of BAVOs. information to the Chief, Office of requirements and procedures; and (1) Until such time as you use a Offshore Regulatory Programs; Bureau (vii) Any additional information that BAVO to perform the actions that this of Safety and Environmental may be relevant to BSEE’s review. subpart requires to be performed by a Enforcement; 45600 Woodland Road, (b) Prior to beginning any operation BAVO, but not after 1 year from the date Sterling, Virginia, 20166, for BSEE requiring the use of any BOP, you must BSEE publishes a list of BAVOs, you review and approval: submit verification by a BAVO and must use an independent third-party (i) Previous experience in verification supporting documentation as required meeting the criteria specified in or in the design, fabrication, by this paragraph to the appropriate

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District Manager and Regional Supervisor.

You must submit verification and documentation related to: That:

(1) Shear testing, ...... (i) Demonstrates that the BOP will shear the drill pipe and any electric-, wire-, and slick-line to be used in the well, no later than April 30, 2018; (ii) Demonstrates the use of test protocols and analysis that represent recognized engineering practices for ensuring the repeatability and reproducibility of the tests, and that the testing was performed by a facility that meets generally accepted quality assurance standards; (iii) Provides a reasonable representation of field applications, taking into consider- ation the physical and mechanical properties of the drill pipe; (iv) Ensures testing was performed on the outermost edges of the shearing blades of the shear ram positioning mechanism as required in § 250.734(a)(16); (v) Demonstrates the shearing capacity of the BOP equipment to the physical and mechanical properties of the drill pipe; and (vi) Includes relevant testing results. (2) Pressure integrity testing, and ...... (i) Shows that testing is conducted immediately after the shearing tests; (ii) Demonstrates that the equipment will seal at the rated working pressures (RWP) of the BOP for 30 minutes; and (iii) Includes all relevant test results. (3) Calculations ...... Include shearing and sealing pressures for all pipe to be used in the well including corrections for MASP.

(c) For wells in an HPHT you propose to use. You must provide (c) to the appropriate District Manager environment, as defined by § 250.807(b), the BAVO access to any facility and Regional Supervisor before you you must submit verification by a BAVO associated with the BOP system or begin any operations in an HPHT that the verification organization related equipment during the review environment with the proposed conducted a comprehensive review of process. You must submit the equipment. the BOP system and related equipment verifications required by this paragraph

You must submit: Including:

(1) Verification that the verification organization con- ducted a detailed review of the design package to en- sure that all critical components and systems meet rec- ognized engineering practices, (2) Verification that the designs of individual components (i) Identification of all reasonable potential modes of failure; and and the overall system have been proven in a testing (ii) Evaluation of the design verification tests. The design verification tests must as- process that demonstrates the performance and reli- sess the equipment for the identified potential modes of failure. ability of the equipment in a manner that is repeatable and reproducible, (3) Verification that the BOP equipment will perform as designed in the temperature, pressure, and environ- ment that will be encountered, and (4) Verification that the fabrication, manufacture, and as- For the quality control and assurance mechanisms, complete material and quality sembly of individual components and the overall sys- controls over all contractors, subcontractors, distributors, and suppliers at every tem uses recognized engineering practices and quality stage in the fabrication, manufacture, and assembly process. control and assurance mechanisms.

(d) Once every 12 months, you must standards incorporated into this (4) A description of records reviewed submit a Mechanical Integrity subpart, and recognized engineering related to any modifications to the Assessment Report for a subsea BOP, a practices. equipment and verification that any BOP being used in an HPHT (2) Verification that complete such changes do not adversely affect the environment as defined in § 250.807, or documentation of the equipment’s equipment’s capability to perform as a surface BOP on a floating facility. This service life exists that demonstrates that designed or invalidate test results. report must be completed by a BAVO. the BOP stack has not been (5) A description of the Safety and You must submit this report to the compromised or damaged during Environmental Management Systems Chief, Office of Offshore Regulatory previous service. (SEMS) plans reviewed related to Programs; Bureau of Safety and (3) A description of all inspection, assurance of quality and mechanical Environmental Enforcement; 45600 repair and maintenance records integrity of critical equipment and Woodland Road, Sterling, VA 20166. reviewed, and verification that all verification that the plans are This report must include: repairs, replacement parts, and comprehensive and fully implemented. (1) A determination that the BOP maintenance meet regulatory (6) Verification that the qualification stack and system meets or exceeds all requirements, recognized engineering and training of inspection, repair, and BSEE regulatory requirements, industry practices, and OEM specifications. maintenance personnel for the BOP

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systems meet recognized engineering you must install the BOP system before requirements of API RP 2RD (as practices and any applicable OEM drilling or conducting operations to incorporated by reference in § 250.198), requirements. deepen the well below the surface including appropriate design for the (7) A description of all records casing and after the well is deepened maximum anticipated operating and reviewed covering OEM safety alerts, all below the surface casing point. The environmental conditions. failure reports, and verification that any surface BOP stack must include at least (i) For a dual bore riser configuration, design or maintenance issues have been four remote-controlled, hydraulically the annulus between the risers must be completely identified and corrected. operated BOPs, consisting of one monitored for pressure during (8) A comprehensive assessment of annular BOP, one BOP equipped with operations. You must describe in your the overall system and verification that blind shear rams, and two BOPs APD or APM your annulus monitoring all components (including mechanical, equipped with pipe rams. plan and how you will secure the well hydraulic, electrical, and software) are (1) The blind shear rams must be in the event a leak is detected. capable of shearing at any point along compatible. (ii) The inner riser for a dual riser the tubular body of any drill pipe (9) Verification that documentation configuration is subject to the (excluding tool joints, bottom-hole tools, exists concerning the traceability of the requirements at § 250.721 for testing the and bottom hole assemblies that include fabrication, repair, and maintenance of casing or liner. all critical components. heavy-weight pipe or collars), (10) Verification of use of a formal workstring, tubing provided that the (c) You must install separate side maintenance tracking system to ensure capability to shear tubing with exterior outlets on the BOP stack for the kill and that corrective maintenance and control lines is not required prior to choke lines. If your stack does not have scheduled maintenance is implemented April 30, 2018, and any electric-, side outlets, you must install a drilling in a timely manner. wire-, and slick-line that is in the hole spool with side outlets. The outlet (11) Identification of gaps or and sealing the wellbore after shearing. valves must hold pressure from both deficiencies related to inspection and If your blind shear rams are unable to directions. maintenance procedures and cut any electric-, wire-, or slick-line (d) You must install a choke and a kill documentation, documentation of any under MASP as defined for the line on the BOP stack. You must equip deferred maintenance, and verification operation and seal the wellbore, you each line with two full-bore, full- of the completion of corrective action must use an alternative cutting device opening valves, one of which must be plans. capable of shearing the lines before remote-controlled. On the kill line, you (12) Verification that any inspection, closing the BOP. This device must be may install a check valve and a manual maintenance, or repair work meets the available on the rig floor during valve instead of the remote-controlled manufacturer’s design and material operations that require their use. valve. To use this configuration, both specifications. (2) The two BOPs equipped with pipe manual valves must be readily (13) Verification of written procedures rams must be capable of closing and accessible and you must install the for operating the BOP stack and Lower sealing on the tubular body of any drill check valve between the manual valves Marine Riser Package (LMRP) (including pipe, workstring, and tubing under and the pump. MASP, as defined for the operation, proper techniques to prevent accidental § 250.734 What are the requirements for a disconnection of these components) and except for tubing with exterior control subsea BOP system? minimum knowledge requirements for lines and flat packs, a bottom hole personnel authorized to operate and assembly that includes heavy-weight (a) When you drill or conduct maintain BOP components. pipe or collars, and bottom-hole tools. operations with a subsea BOP system, (14) Recommendations, if any, for (b) If you plan to use a surface BOP you must install the BOP system before how to improve the fabrication, on a floating production facility you drilling to deepen the well below the installation, operation, maintenance, must: surface casing or before conducting inspection, and repair of the equipment. (1) For BOPs installed after April 29, operations if the well is already (e) You must make all documentation 2019, follow the BOP requirements in deepened beyond the surface casing that supports the requirements of this § 250.734(a)(1). point. The District Manager may require section available to BSEE upon request. (2) For risers installed after July 28, you to install a subsea BOP system 2016, use a dual bore riser configuration before drilling or conducting operations § 250.733 What are the requirements for a before drilling or operating in any hole below the conductor casing if proposed surface BOP stack? section or interval where hydrocarbons casing setting depths or local geology (a) When you drill or conduct are, or may be, exposed to the well. The indicate the need. The following table operations with a surface BOP stack, dual bore riser must meet the design outlines your requirements.

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

(1) Have at least five remote-controlled, hydraulically operated BOPs; You must have at least one annular BOP, two BOPs equipped with pipe rams, and two BOPs equipped with shear rams. For the dual ram requirement, you must comply with this requirement no later than April 29, 2021. (i) Both BOPs equipped with pipe rams must be capable of closing and sealing on the tubular body of any drill pipe, workstring, and tubing under MASP, as defined for the operation, except tubing with exte- rior control lines and flat packs, a bottom hole assembly that in- cludes heavy-weight pipe or collars, and bottom-hole tools.

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

(ii) Both shear rams must be capable of shearing at any point along the tubular body of any drill pipe (excluding tool joints, bottom-hole tools, and bottom hole assemblies such as heavy-weight pipe or col- lars), workstring, tubing provided that the capability to shear tubing with exterior control lines is not required prior to April 30, 2018, ap- propriate area for the liner or casing landing string, shear sub on subsea test tree, and any electric-, wire-, slick-line in the hole no later than April 30, 2018; under MASP. At least one shear ram must be capable of sealing the wellbore after shearing under MASP condi- tions as defined for the operation. Any non-sealing shear ram(s) must be installed below a sealing shear ram(s). (2) Have an operable redundant pod control system to ensure proper and independent operation of the BOP system; (3) Have the accumulator capacity located subsea, to provide fast clo- The accumulator capacity must: sure of the BOP components and to operate all critical functions in (i) Operate each required shear ram, ram locks, one pipe ram, and dis- case of a loss of the power fluid connection to the surface; connect the LMRP. (ii) Have the capability of delivering fluid to each ROV function i.e., fly- ing leads. (iii) No later than April 29, 2021, have bottles for the autoshear, and deadman that are dedicated to, but may be shared between, those functions. (iv) Perform under MASP conditions as defined for the operation. (4) Have a subsea BOP stack equipped with remotely operated vehicle The ROV must be capable of opening and closing each shear ram, (ROV) intervention capability; ram locks, one pipe ram, and LMRP disconnect under MASP condi- tions as defined for the operation. The ROV panels on the BOP and LMRP must be compliant with API RP 17H (as incorporated by ref- erence in § 250.198). (5) Maintain an ROV and have a trained ROV crew on each rig unit on The crew must be trained in the operation of the ROV. The training a continuous basis once BOP deployment has been initiated from must include simulator training on stabbing into an ROV intervention the rig until recovered to the surface. The ROV crew must examine panel on a subsea BOP stack. The ROV crew must be in commu- all ROV-related well-control equipment (both surface and subsea) to nication with designated rig personnel who are knowledgeable about ensure that it is properly maintained and capable of carrying out ap- the BOP’s capabilities. propriate tasks during emergency operations; (6) Provide autoshear, deadman, and EDS systems for dynamically po- (i) Autoshear system means a safety system that is designed to auto- sitioned rigs; provide autoshear and deadman systems for moored matically shut-in the wellbore in the event of a disconnect of the rigs; LMRP. This is considered a rapid discharge system. (ii) Deadman system means a safety system that is designed to auto- matically shut-in the wellbore in the event of a simultaneous absence of hydraulic supply and signal transmission capacity in both subsea control pods. This is considered a rapid discharge system. (iii) Emergency Disconnect Sequence (EDS) system means a safety system that is designed to be manually activated to shut-in the wellbore and disconnect the LMRP in the event of an emergency sit- uation. This is considered a rapid discharge system. (iv) Each emergency function must close at a minimum, two shear rams in sequence and be capable of performing its expected shear- ing and sealing action under MASP conditions as defined for the op- eration. (v) Your sequencing must allow a sufficient delay for closing the upper shear ram after beginning closure of the lower shear ram to provide for maximum sealing efficiency. (vi) The control system for the emergency functions must be a fail-safe design once activated. (7) Demonstrate that any acoustic control system will function in the If you choose to use an acoustic control system in addition to the proposed environment and conditions; autoshear, deadman, and EDS requirements, you must demonstrate to the District Manager, as part of the information submitted under § 250.731, that the acoustic control system will function in the pro- posed environment and conditions. The District Manager may require additional information as appropriate to clarify or evaluate the acous- tic control system information provided in your demonstration. (8) Have operational or physical barrier(s) on BOP control panels to You must incorporate enable buttons, or a similar feature, on control prevent accidental disconnect functions; panels to ensure two-handed operation for all critical functions. (9) Clearly label all control panels for the subsea BOP system; Label other BOP control panels, such as hydraulic control panel. (10) Develop and use a management system for operating the BOP The management system must include written procedures for operating system, including the prevention of accidental or unplanned dis- the BOP stack and LMRP (including proper techniques to prevent connects of the system; accidental disconnection of these components) and minimum knowl- edge requirements for personnel authorized to operate and maintain BOP components.

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

(11) Establish minimum requirements for personnel authorized to oper- Personnel must have: ate critical BOP equipment; (i) Training in deepwater well-control theory and practice according to the requirements of Subparts O and S; and (ii) A comprehensive knowledge of BOP hardware and control systems. (12) Before removing the marine riser, displace the fluid in the riser You must maintain sufficient hydrostatic pressure or take other suitable with seawater; precautions to compensate for the reduction in pressure and to maintain a safe and controlled well condition. You must follow the re- quirements of § 250.720(b). (13) Install the BOP stack in a well cellar when in an ice-scour area; Your well cellar must be deep enough to ensure that the top of the stack is below the deepest probable ice-scour depth. (14) Install at least two side outlets for a choke line and two side out- (i) If your stack does not have side outlets, you must install a drilling lets for a kill line; spool with side outlets. (ii) Each side outlet must have two full-bore, full-opening valves. (iii) The valves must hold pressure from both directions and must be remote-controlled. iv) You must install a side outlet below the lowest sealing shear ram. You may have a pipe ram or rams between the shearing ram and side outlet. (15) Install a gas bleed line with two valves for the annular preventer (i) The valves must hold pressure from both directions; no later than April 30, 2018; (ii) If you have dual annulars, you must install the gas bleed line below the upper annular. (16) Use a BOP system that has the following mechanisms and capa- (i) A mechanism coupled with each shear ram to position the entire bilities; pipe, completely within the area of the shearing blade and ensure shearing will occur any time the shear rams are activated. This mechanism cannot be another ram BOP or annular preventer, but you may use those during a planned shear. You must install this mechanism no later than May 1, 2023; (ii) The ability to mitigate compression of the pipe stub between the shearing rams when both shear rams are closed; (iii) If your control pods contain a subsea electronic module with bat- teries, a mechanism for personnel on the rig to monitor the state of charge of the subsea electronic module batteries in the BOP control pods.

(b) If operations are suspended to § 250.735 What associated systems and independent power source must possess make repairs to any part of the subsea related equipment must all BOP systems sufficient capability to close and hold BOP system, you must stop operations include? closed all BOP components under at a safe downhole location. Before All BOP systems must include the MASP conditions as defined for the resuming operations you must: following associated systems and operation; related equipment: (c) At least two full BOP control (1) Submit a revised permit with a (a) An accumulator system (as stations. One station must be on the rig verification report from a BAVO specified in API Standard 53, and floor. You must locate the other station documenting the repairs and that the incorporated by reference in § 250.198) in a readily accessible location away BOP is fit for service; that provides the volume of fluid from the rig floor; (2) Upon relatch of the BOP, perform capacity (as specified in API Standard 53, Annex C) necessary to close and (d) The choke line(s) installed above an initial subsea BOP test in accordance the bottom well-control ram; with § 250.737(d)(4), including hold closed all BOP components against (e) The kill line must be installed deadman. If repairs take longer than 30 MASP. The system must operate under MASP conditions as defined for the beneath at least one well-control ram, days, once the BOP is on deck, you must operation. You must be able to operate and may be installed below the bottom test in accordance with the the BOP functions as defined in API ram; requirements of § 250.737; and Standard 53, without assistance from a (f) A fill-up line above the uppermost (3) Receive approval from the District charging system, and still have a BOP; Manager. minimum pressure of 200 psi remaining (g) Locking devices for all BOP sealing (c) If you plan to drill a new well with on the bottles above the pre-charge rams (i.e., blind shear rams, pipe rams a subsea BOP, you do not need to pressure. If you supply the accumulator and variable bore rams), as follows: submit with your APD the verifications regulators by rig air and do not have a (1) For subsea BOPs, hydraulic required by this subpart for the open secondary source of pneumatic supply, locking devices must be installed on all you must equip the regulators with water drilling operation. Before drilling sealing rams; manual overrides or other devices to out the surface casing, you must submit ensure capability of hydraulic (2) For surface BOPs: for approval a revised APD, including operations if rig air is lost; (i) Remotely-operated locking devices the verifications required in this (b) An automatic backup to the must be installed on blind shear rams subpart. primary accumulator-charging system. no later than April 29, 2019; The power source must be independent (ii) Manual or remotely-operated from the power source for the primary locking devices must be installed on accumulator-charging system. The pipe rams and variable bore rams; and

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(h) A wellhead assembly with a RWP installed below the remote-controlled since your last blind shear ram BOP that exceeds the maximum anticipated valve; pressure test. You must begin to test wellhead pressure. (3) An inside BOP in the open your BOP system before midnight on the position located on the rig floor. You 14th day (or 30th day for your blind § 250.736 What are the requirements for must be able to install an inside BOP for shear rams) following the conclusion of choke manifolds, kelly-type valves inside each size connection in the pipe; the previous test; BOPs, and drill string safety valves? (4) A drill string safety valve in the (3) Before drilling out each string of (a) Your BOP system must include a open position located on the rig floor. casing or a liner. You may omit this choke manifold that is suitable for the You must have a drill-string safety valve pressure test requirement if you did not anticipated surface pressures, available for each size connection in the remove the BOP stack to run the casing anticipated methods of well control, the pipe; surrounding environment, and the (5) When running casing, a safety string or liner, the required BOP test corrosiveness, volume, and abrasiveness valve in the open position available on pressures for the next section of the hole of drilling fluids and well fluids that the rig floor to fit the casing string being are not greater than the test pressures for you may encounter. run in the hole; the previous BOP test, and the time (b) Choke manifold components must (6) All required manual and remote- elapsed between tests has not exceeded have a RWP at least as great as the RWP controlled kelly-type valves, drill-string 14 days (or 30 days for blind shear of the ram BOPs. If your choke manifold safety valves, and comparable-type rams). You must indicate in your APD has buffer tanks downstream of choke valves (i.e., kelly-type valve in a top- which casing strings and liners meet assemblies, you must install isolation drive system) that are essentially full these criteria; valves on any bleed lines. opening; and (4) The District Manager may require (c) Valves, pipes, flexible steel hoses, (7) A wrench to fit each manual valve. more frequent testing if conditions or and other fittings upstream of the choke Each wrench must be readily accessible your BOP performance warrant. manifold must have a RWP at least as to the drilling crew. (b) Pressure test procedures. When great as the RWP of the ram BOPs. § 250.737 What are the BOP system you pressure test the BOP system, you (d) You must use the following BOP testing requirements? must conduct a low-pressure test and a equipment with a RWP and temperature Your BOP system (this includes the high-pressure test for each BOP of at least as great as the working choke manifold, kelly-type valves, component. You must begin each test by pressure and temperature of the ram inside BOP, and drill string safety valve) conducting the low-pressure test then BOP during all operations: must meet the following testing transition to the high-pressure test. Each (1) The applicable kelly-type valves as requirements: individual pressure test must hold described in API Standard 53 (a) Pressure test frequency. You must pressure long enough to demonstrate the (incorporated by reference in § 250.198); pressure test your BOP system: tested component(s) holds the required (2) On a top-drive system equipped (1) When installed; pressure. The table in this paragraph (b) with a remote-controlled valve, a (2) Before 14 days have elapsed since outlines your pressure test strippable kelly-type valve must be your last BOP pressure test, or 30 days requirements.

You must conduct a . . . According to the following procedures . . .

(1) Low-pressure test ...... All low-pressure tests must be between 250 and 350 psi. Any initial pressure above 350 psi must be bled back to a pressure between 250 and 350 psi before starting the test. If the initial pressure exceeds 500 psi, you must bleed back to zero and reinitiate the test. (2) High-pressure test for blind shear ram-type BOPs, The high-pressure test must equal the RWP of the equipment or be 500 psi greater ram-type BOPs, the choke manifold, outside of all than your calculated MASP, as defined for the operation for the applicable section choke and kill side outlet valves (and annular gas of hole. Before you may test BOP equipment to the MASP plus 500 psi, the Dis- bleed valves for subsea BOP), inside of all choke and trict Manager must have approved those test pressures in your APD. kill side outlet valves below uppermost ram, and other BOP components. (3) High-pressure test for annular-type BOPs, inside of The high pressure test must equal 70 percent of the RWP of the equipment or be choke or kill valves (and annular gas bleed valves for 500 psi greater than your calculated MASP, as defined for the operation for the subsea BOP) above the uppermost ram BOP. applicable section of hole. Before you may test BOP equipment to the MASP plus 500 psi, the District Manager must have approved those test pressures in your APD.

(c) Duration of pressure test. Each test recorded on a chart not exceeding 4 pressure during a test, you must correct must hold the required pressure for 5 hours, or on a digital recorder. The the problem and retest the affected minutes, which must be recorded on a recorded test pressures must be within component(s). chart not exceeding 4 hours. However, the middle half of the chart range, i.e., (d) Additional test requirements. You for surface BOP systems and surface cannot be within the lower or upper must meet the following additional BOP equipment of a subsea BOP system, a 3- one-fourth of the chart range. If the testing requirements: minute test duration is acceptable if equipment does not hold the required

You must . . . Additional requirements . . .

(1) Follow the testing requirements of API Standard 53 If there is a conflict between API Standard 53, testing requirements and this section, (as incorporated in § 250.198). you must follow the requirements of this section.

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You must . . . Additional requirements . . .

(2) Use water to test a surface BOP system on the initial (i) You must submit test procedures with your APD or APM for District Manager ap- test. You may use drilling/completion/workover fluids to proval. conduct subsequent tests of a surface BOP system. (ii) Contact the District Manager at least 72 hours prior to beginning the initial test to allow BSEE representative(s) to witness testing. If BSEE representative(s) are un- able to witness testing, you must provide the initial test results to the appropriate District Manager within 72 hours after completion of the tests. (3) Stump test a subsea BOP system before installation (i) You must use water to conduct this test. You may use drilling/completion/workover fluids to conduct subsequent tests of a subsea BOP system. (ii) You must submit test procedures with your APD or APM for District Manager ap- proval (iii) Contact the District Manager at least 72 hours prior to beginning the stump test to allow BSEE representative(s) to witness testing. If BSEE representative(s) are unable to witness testing, you must provide the test results to the appropriate Dis- trict Manager within 72 hours after completion of the tests. (iv) You must test and verify closure of all ROV intervention functions on your subsea BOP stack during the stump test. (v) You must follow paragraphs (b) and (c) of this section. (4) Perform an initial subsea BOP test ...... (i) You must perform the initial subsea BOP test on the seafloor within 30 days of the stump test. (ii) You must submit test procedures with your APD or APM for District Manager ap- proval. (iii) You must pressure test well-control rams according to paragraphs (b) and (c) of this section. (iv) You must notify the District Manager at least 72 hours prior to beginning the ini- tial subsea test for the BOP system to allow BSEE representative(s) to witness testing. (v) You must test and verify closure of at least one set of rams during the initial subsea test through a ROV hot stab. (vi) You must pressure test the selected rams according to paragraphs (b) and (c) of this section. (5) Alternate testing pods between control stations ...... (i) For two complete BOP control stations: (A) Designate a primary and secondary station, and both stations must be function- tested weekly; (B) The control station used for the pressure test must be alternated between pres- sure tests; and (C) For a subsea BOP, the pods must be rotated between control stations during weekly function testing and 14 day pressure testing. (ii) Remote panels where all BOP functions are not included (e.g., life boat panels) must be function-tested upon the initial BOP tests and monthly thereafter. (6) Pressure test variable bore-pipe ram BOPs against pipe sizes according to API Standard 53, excluding the bottom hole assembly that includes heavy-weight pipe or collars and bottom-hole tools. (7) Pressure test annular type BOPs against pipe sizes according to API Standard 53. (8) Pressure test affected BOP components following the disconnection or repair of any well-pressure contain- ment seal in the wellhead or BOP stack assembly. (9) Function test annular and pipe/variable bore ram BOPs every 7 days between pressure tests. (10) Function test shear ram(s) BOPs every 14 days. (11) Actuate safety valves assembled with proper casing connections before running casing.

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You must . . . Additional requirements . . .

(12) Function test autoshear/deadman, and EDS systems (i) You must submit test procedures with your APD or APM for District Manager ap- separately on your subsea BOP stack during the proval. The procedures for these function tests must include the schematics of the stump test. The District Manager may require addi- actual controls and circuitry of the system that will be used during an actual tional testing of the emergency systems. You must autoshear or deadman event. also test the deadman system and verify closure of the (ii) The procedures must also include the actions and sequence of events that take shearing rams during the initial test on the seafloor. place on the approved schematics of the BOP control system and describe specifi- cally how the ROV will be utilized during this operation. (iii) When you conduct the initial deadman system test on the seafloor, you must en- sure the well is secure and, if hydrocarbons have been present, appropriate bar- riers are in place to isolate hydrocarbons from the wellhead. You must also have an ROV on bottom during the test. (iv) The testing of the deadman system on the seafloor must indicate the discharge pressure of the subsea accumulator system throughout the test. (v) For the function test of the deadman system during the initial test on the seafloor, you must have the ability to quickly disconnect the LMRP should the rig experi- ence a loss of station-keeping event. You must include your quick-disconnect pro- cedures with your deadman test procedures. (vi) You must pressure test the blind shear ram(s) according to paragraphs (b) and (c) of this section. (vii) If a casing shear ram is installed, you must describe how you will verify closure of the ram. (viii) You must document all your test results and make them available to BSEE upon request.

(e) Prior to conducting any shear ram § 250.738 What must I do in certain tests in which you will shear pipe, you situations involving BOP equipment or must notify the District Manager at least systems? 72 hours in advance, to ensure that a The table in this section describes BSEE representative will have access to actions that you must take when certain the location to witness any testing. situations occur with BOP systems.

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

(a) BOP equipment does not hold the required pressure Correct the problem and retest the affected equipment. You must report any prob- during a test; lems or irregularities, including any leaks, on the daily report as required in § 250.746. (b) Need to repair, replace, or reconfigure a surface or (1) First place the well in a safe, controlled condition as approved by the District subsea BOP system; Manager (e.g., before drilling out a casing shoe or after setting a cement plug, bridge plug, or a packer). (2) Any repair or replacement parts must be manufactured under a quality assurance program and must meet or exceed the performance of the original part produced by the OEM. (3) You must receive approval from the District Manager prior to resuming operations with the new, repaired, or reconfigured BOP. (4) You must submit a report from a BAVO to the District Manager certifying that the BOP is fit for service. (c) Need to postpone a BOP test due to well-control Record the reason for postponing the test in the daily report and conduct the re- problems such as lost circulation, formation fluid influx, quired BOP test after the first trip out of the hole. or stuck pipe; (d) BOP control station or pod that does not function Suspend operations until that station or pod is operable. You must report any prob- properly; lems or irregularities, including any leaks, to the District Manager. (e) Plan to operate with a tapered string; Install two or more sets of conventional or variable-bore pipe rams in the BOP stack to provide for the following: two sets of rams must be capable of sealing around the larger-size drill string and one set of pipe rams must be capable of sealing around the smaller size pipe, excluding the bottom hole assembly that includes heavy weight pipe or collars and bottom-hole tools. (f) Plan to install casing rams or casing shear rams in a Test the affected connections before running casing to the RWP or MASP plus 500 surface BOP stack; psi. If this installation was not included in your approved permit, and changes the BOP configuration approved in the APD or APM, you must notify and receive ap- proval from the District Manager. (g) Plan to use an annular BOP with a RWP less than Demonstrate that your well-control procedures or the anticipated well conditions will the anticipated surface pressure; not place demands above its RWP and obtain approval from the District Manager. (h) Plan to use a subsea BOP system in an ice-scour Install the BOP stack in a well cellar. The well cellar must be deep enough to ensure area; that the top of the stack is below the deepest probable ice-scour depth. (i) You activate any shear ram and pipe or casing is Retrieve, physically inspect, and conduct a full pressure test of the BOP stack after sheared; the situation is fully controlled. You must submit to the District Manager a report from a BSEE-approved verification organization certifying that the BOP is fit to re- turn to service. (j) Need to remove the BOP stack; Have a minimum of two barriers in place prior to BOP removal. You must obtain ap- proval from the District Manager of the two barriers prior to removal and the Dis- trict Manager may require additional barriers and test(s).

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

(k) In the event of a deadman or autoshear activation, if Place the blind shear ram opening function in the block position prior to re-estab- there is a possibility of the blind shear ram opening im- lishing power to the stack. Contact the District Manager and receive approval of mediately upon re-establishing power to the BOP procedures for re-establishing power and functions prior to latching up the BOP stack; stack or re-establishing power to the stack. (l) If a test ram is to be used; The wellhead/BOP connection must be tested to the MASP plus 500 psi for the hole section to which it is exposed. This can be done by: (1) Testing wellhead/BOP connection to the MASP plus 500 psi for the well upon in- stallation; (2) Pressure testing each casing to the MASP plus 500 psi for the next hole section; or (3) Some combination of paragraphs (l)(1) and (2) of this section. (m) Plan to utilize any other well-control equipment (e.g., Contact the District Manager and request approval in your APD or APM. Your re- but not limited to, subsea isolation device, subsea ac- quest must include a report from a BAVO on the equipment’s design and suitability cumulator module, or gas handler) that is in addition to for its intended use as well as any other information required by the District Man- the equipment required in this subpart; ager. The District Manager may impose any conditions regarding the equipment’s capabilities, operation, and testing. (n) You have pipe/variable bore rams that have no cur- Indicate in your APD or APM which pipe/variable bore rams meet these criteria and rent utility or well-control purposes; clearly label them on all BOP control panels. You do not need to function test or pressure test pipe/variable bore rams having no current utility, and that will not be used for well-control purposes, until such time as they are intended to be used during operations. (o) You install redundant components for well control in Comply with all testing, maintenance, and inspection requirements in this subpart your BOP system that are in addition to the required that are applicable to those well-control components. If any redundant component components of this subpart (e.g., pipe/variable bore fails a test, you must submit a report from a BAVO that describes the failure and rams, shear rams, annular preventers, gas bleed lines, confirms that there is no impact on the BOP that will make it unfit for well-control and choke/kill side outlets or lines); purposes. You must submit this report to the District Manager and receive ap- proval before resuming operations. The District Manager may require you to pro- vide additional information as needed to clarify or evaluate your report. (p) Need to position the bottom hole assembly, including Ensure that the well is stable prior to positioning the bottom hole assembly across heavy-weight pipe or collars, and bottom-hole tools the BOP. You must have, as part of your well-control plan required by § 250.710, across the BOP for tripping or any other operations. procedures that enable the removal of the bottom hole assembly from across the BOP in the event of a well-control or emergency situation (for dynamically posi- tioned rigs, your plan must also include steps for when the EDS must be activated) before MASP conditions are reached as defined for the operation.

§ 250.739 What are the BOP maintenance must compile a detailed report incorporated by reference in this and inspection requirements? documenting the inspection, including subpart. (a) You must maintain and inspect descriptions of any problems and how (e) You must make all records your BOP system to ensure that the they were corrected. You must make available to BSEE upon request. You equipment functions as designed. The these reports available to BSEE upon must ensure that the rig unit owner BOP maintenance and inspections must request. This complete breakdown and maintains the BOP maintenance, meet or exceed any OEM inspection must be performed every 5 inspection, and repair records on the rig recommendations, recognized years from the following applicable unit for 2 years from the date the engineering practices, and industry dates, whichever is later: records are created or for a longer period standards incorporated by reference into (1) The date the equipment owner if directed by BSEE. You must ensure the regulations of this subpart, accepts delivery of a new build drilling that all equipment schematics, including API Standard 53 rig with a new BOP system; maintenance, inspection, and repair (incorporated by reference in § 250.198). (2) The date the new, repaired, or records are located at an onshore You must document how you met or remanufactured equipment is initially location for the service life of the exceeded the provisions of API installed into the system; or equipment. Standard 53, maintain complete records to ensure the traceability of BOP stack (3) The date of the last 5 year Records and Reporting inspection for the component. equipment beginning at fabrication, and § 250.740 What records must I keep? record the results of your BOP (c) You must visually inspect your inspections and maintenance actions. surface BOP system on a daily basis. You must keep a daily report You must make all records available to You must visually inspect your subsea consisting of complete, legible, and BSEE upon request. BOP system, marine riser, and wellhead accurate records for each well. You (b) A complete breakdown and at least once every 3 days if weather and must keep records onsite while well detailed physical inspection of the BOP sea conditions permit. You may use operations continue. After completion and every associated system and cameras to inspect subsea equipment. of operations, you must keep all component must be performed every 5 (d) You must ensure that all personnel operation and other well records for the years. This complete breakdown and maintaining, inspecting, or repairing time periods shown in § 250.741 at a inspection may be performed in phased BOPs, or critical components of the BOP location of your choice, except as intervals. You must track and document system, are trained in accordance with required in § 250.746. The records must all system and component inspection applicable training requirements in contain complete information on all of dates. These records must be available subpart S of this part, any applicable the following: on the rig. A BAVO is required to be OEM criteria, recognized engineering (a) Well operations, all testing present during each inspection and practices, and industry standards conducted, and any real-time

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monitoring data as required by (e) All well logs and surveys run in operations are consistent with § 250.724; the wellbore; conservation of natural resources and (b) Descriptions of formations (f) Any significant malfunction or protection of safety and the penetrated; problem; and environment on the OCS. (c) Content and character of oil, gas, (g) All other information required by water, and other mineral deposits in the District Manager as appropriate to § 250.741 How long must I keep records? ensure compliance with the each formation; You must keep records for the time (d) Kind, weight, size, grade, and requirements of this section and to periods shown in the following table. setting depth of casing; enable BSEE to determine that the well

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

(a) Drilling; 90 days after you complete operations. (b) Casing and liner pressure tests, diverter tests, BOP tests, and real- 2 years after the completion of operations. time monitoring data; (c) Completion of a well or of any workover activity that materially al- You permanently plug and abandon the well or until you assign the ters the completion configuration or affects a hydrocarbon-bearing lease and forward the records to the assignee. zone.

§ 250.742 What well records am I required begin operations to the time you end tubing, landing nipples, subsurface to submit? operations, any verbal approval safety devices, and any other You must submit to BSEE copies of received, the well’s as-built drawings, information required by the District logs or charts of electrical, radioactive, casing, fluid weights, shoe tests, test Manager regarding the end of well sonic, and other well logging operations; pressures at surface conditions, and any operations. The EOR must indicate the directional and vertical well surveys; other information concerning well status of the well (completed, velocity profiles and surveys; and activities required by the District temporarily abandoned, permanently analysis of cores. Each Region will Manager. For casing cementing abandoned, or drilling suspended) and provide specific instructions for operations, indicate type of returns (i.e., the date of the well status designation. submitting well logs and surveys. full, partial, or none). If partial or no The well status date is subject to the returns are observed, you must indicate following: § 250.743 What are the well activity how you determined the top of cement. reporting requirements? (1) For surface well operations and For each report, indicate the operation riserless subsea operations, the (a) For operations in the BSEE Gulf of status for the well at the end of the Mexico (GOM) OCS Region, you must reporting period. On the final WAR, operations end date is subject to the submit Form BSEE–0133, Well Activity indicate the status of the well discretion of the District Manager; and Report (WAR), to the District Manager (completed, temporarily abandoned, (2) For subsea well operations, the on a weekly basis. The reporting week permanently abandoned, or drilling operations end date is considered to be is defined as beginning on Sunday (12 suspended) and the date you finished the date the BOP is disconnected from a.m.) and ending on the following such operations. the wellhead unless otherwise specified Saturday (11:59 p.m.). This reporting by the District Manager. week corresponds to a week (Sunday § 250.744 What are the end of operation (b) You must submit public through Saturday) on a standard reporting requirements? information copies of Form BSEE–0125 calendar. Report any well operations (a) Within 30 days after completing according to § 250.186(b). that extend past the end of this weekly operations, except routine operations as reporting period on the next weekly defined in § 250.601, you must submit § 250.745 What other well records could I report. The reporting period for the Form BSEE–0125, End of Operations be required to submit? weekly report is never longer than 7 Report (EOR), to the District Manager. The District Manager or Regional days, but could be less than 7 days for The EOR must include: a listing, with the first reporting period and the last top and bottom depths, of all Supervisor may require you to submit reporting period for a particular well hydrocarbon zones and other zones of copies of any or all of the following well operation. Submit each WAR and porosity encountered with any cored records: accompanying Form BSEE–0133S, Open intervals; details on any drill-stem and (a) Well records as specified in Hole Data Report, to the BSEE GOM formation tests conducted; § 250.740; OCS Region no later than close of documentation of successful negative (b) Paleontological interpretations or business on the Friday immediately pressure testing on wells that use a reports identifying microscopic fossils after the closure of the reporting week. subsea BOP stack or wells with mudline by depth and/or washed samples of drill The District Manager may require more suspension systems; and an updated cuttings that you normally maintain for frequent submittal of the WAR on a schematic of the full wellbore paleontological determinations. The case-by-case basis. configuration. The schematic must be Regional Supervisor may issue a Notice (b) For operations in the Pacific or clearly labeled and show all applicable to Lessees that sets forth the manner, Alaska OCS Regions, you must submit top and bottom depths, locations and timeframe, and format for submitting Form BSEE–0133, WAR, to the District sizes of all casings, cut casing or stubs, this information; Manager on a daily basis. casing perforations, casing rupture discs (c) The WAR must include a (indicate if burst or collapse and rating), (c) Service company reports on description of the operations conducted, cemented intervals, cement plugs, cementing, perforating, acidizing, any abnormal or significant events that mechanical plugs, perforated zones, testing, or other similar services; or affect the permitted operation each day completion equipment, production and (d) Other reports and records of within the report from the time you isolation packers, alternate completions, operations.

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§ 250.746 What are the recordkeeping the BOP or control system during testing ■ a. Revising paragraphs (b) and (e); requirements for casing, liner, and BOP must be documented in the WAR. If any ■ tests, and inspections of BOP systems and b. Redesignating paragraph (f) as problems that cannot be resolved paragraph (g); and marine risers? promptly are observed during testing, You must record the time, date, and operations must be suspended until the ■ c. Adding new paragraph (f). results of all casing and liner pressure District Manager determines that you The revisions and addition read as tests. You must also record pressure may continue; and follows: tests, actuations, and inspections of the (f) Retain all records, including BOP system, system components, and pressure charts, daily reports, and § 250.1703 What are the general marine riser in the daily report referenced documents pertaining to requirements for decommissioning? described in § 250.740. In addition, you tests, actuations, and inspections at the * * * * * must: rig unit for the duration of the (b) Permanently plug all wells. (a) Record test pressures on pressure operation. After completion of the Permanently installed packers and charts or digital recorders; operation, you must retain all the bridge plugs must comply with API (b) Require your onsite lessee records listed in this section for a period Spec. 11D1 (as incorporated by representative, designated rig or of 2 years at the rig unit. You must also reference in § 250.198); contractor representative, and pump retain the records at the lessee’s field * * * * * operator to sign and date the pressure office nearest the facility or at another charts or digital recordings and daily location available to BSEE. You must (e) Clear the seafloor of all reports as correct; make all the records available to BSEE obstructions created by your lease and (c) Document on the daily report the upon request. pipeline right-of-way operations; sequential order of BOP and auxiliary (f) Follow all applicable requirements equipment testing and the pressure and Subpart P—Sulphur Operations of subpart G of this part; and duration of each test. For subsea BOP systems, you must also record the ■ 45. Revise § 250.1612 to read as * * * * * closing times for annular and ram BOPs. follows: ■ 47. Amend § 250.1704 by: You may reference a BOP test plan if it § 250.1612 Well-control drills. ■ a. Revising paragraph (g); is available at the facility; Well-control drills must be conducted ■ (d) Identify on the daily report the b. Redesignating paragraphs (h) and (i) for each drilling crew in accordance as paragraphs (i) and (j); and control station and pod used during the with the requirements set forth in ■ c. Adding new paragraph (h). test (identifying the pod does not apply § 250.711 or as approved by the District to coiled tubing and snubbing units); Manager. The revision and addition read as (e) Identify on the daily report any follows: problems or irregularities observed Subpart Q—Decommissioning during BOP system testing and record Activities § 250.1704 When must I submit actions taken to remedy the problems or decommissioning applications and reports? irregularities. Any leaks associated with ■ 46. Amend § 250.1703 by: * * * * *

Decommissioning applica- tions and reports When to submit Instructions

******* (g) Form BSEE–0124, Appli- (1) Before you temporarily abandon or permanently (i) Include information required under §§ 250.1712 and cation for Permit to Modify plug a well or zone, 250.1721. (APM). The submission of (ii) When using a BOP for abandonment operations, in- your APM must be accom- clude information required under § 250.731. panied by payment of the service fee listed in § 250.125; (2) Before you install a subsea protective device, Refer to § 250.1722(a). (3) Before you remove any casing stub or mud line Refer to § 250.1723. suspension equipment and any subsea protective de- vice, (h) Form BSEE–0125, End (1) Within 30 days after you complete a protective de- Include information required under § 250.1722(d). of Operations Report vice trawl test, (EOR); (2) Within 30 days after you complete site clearance Include information required under § 250.1743(a). verification activities,

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§ 250.1705 [Removed and Reserved] ■ c. Redesignating paragraphs (f) § 250.1706 Coiled tubing and snubbing operations. ■ 48. Remove and reserve § 250.1705. through (h) as paragraphs (a) through (c). * * * * * ■ 49. Amend § 250.1706 by: The revision reads as follows: ■ a. Revising the section heading; ■ b. Removing paragraphs (a) through (e); and

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§§ 250.1707 through 250.1709 [Removed PERMANENT WELL PLUGGING * * * * * and Reserved] REQUIREMENTS § 250.1717 [Removed and Reserved] ■ 50. Remove and reserve §§ 250.1707 If you have . . ■ through 250.1709. . Then you must use . . . 52. Remove and reserve § 250.1717. ■ 51. In § 250.1715, revise paragraph § 250.1721 [Amended] (a)(3)(iii)(B) to read as follows: ***** ■ 53. Amend § 250.1721 by removing (3) * * *. § 250.1715 How must I permanently plug a (iii) * * * paragraph (g) and redesignating well? (B) A casing bridge plug set paragraph (h) as paragraph (g). (a) * * * 50 to 100 feet above the [FR Doc. 2016–08921 Filed 4–28–16; 8:45 am] top of the perforated inter- val and at least 50 feet of BILLING CODE 4310–VH–P cement on top of the bridge plug;

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